Annual Report (Form 10-K), fiscal year 1994

ITEM 1. BUSINESS
General
Snyder Oil Corporation (the "Company") is engaged in the acquisition and development of oil and gas properties primarily in the Rocky Mountain and Gulf Coast regions of the United States. The Company also gathers, transports, processes and markets natural gas generally in proximity to its principal producing properties. Over the past five years, revenues have increased from $84.3 million to $262.3 million, net income rose from $3.2 million to $12.4 million and net cash provided by operations grew from $22.5 million to $86.5 million. At December 31, 1994, the Company's net proved reserves totalled 120.2 million barrels of oil equivalent("MMBOE"), having a pretax present value at constant prices of $414.4 million. Approximately 71% of the reserves were natural gas.
The Company's reserves are concentrated in five major producing areas located in Colorado, Wyoming and Texas, which collectively account for more than 86% of the present value of its reserves. The Company owns properties in 15 states and the Gulf of Mexico, including 5,269 gross (2,651 net) producing wells and nine gas transportation and processing facilities. The Company operates more than 2,600 wells which account for almost 90% of its developed reserves. The Company also participates in several international exploration and development projects through a wholly owned subsidiary and its 29% owned Australian affiliate, Command Petroleum Limited. At December 31, 1994, the Company held undeveloped acreage totaling 1.4 million gross acres (962,000 net) domestically and 5.7 million gross acres (2.8 million net) internationally.
Over the past four years, the Company has pursued a balanced strategy of development drilling and acquisitions, focusing on enhancing operating efficiency and reducing capital costs through the concentration of assets in selected geographic areas or "hubs." Currently, the Company's primary emphasis is on development drilling in several Rocky Mountain basins and in southeast Texas. Prior to 1994, drilling was focused in the Wattenberg Field of the Denver- Julesburg Basin ("DJ Basin") of Colorado where the Company has drilled over 1,000 wells since 1991. This drilling increased the Company's Wattenberg production more than sixfold, from an average of 2.6 MBOE per day in 1991 to 15.9 MBOE in 1994. Beginning in 1994, a growing percentage of drilling expenditures was directed towards developing a series of projects outside Wattenberg. To date, projects have been successfully initiated in the Greater Green River, Piceance and Uinta Basins of the Rocky Mountains and in the Giddings Field of southeast Texas. In 1994, 370 wells were drilled in Wattenberg. In late 1994, the Company curtailed drilling in Wattenberg as the result of declining gas prices and disappointing drilling results in certain outlying areas of the Field. Based on current gas prices, the Company expects to drill less than 100 wells in Wattenberg in 1995 and to concentrate on oil development and those gas development projects which are less sensitive to low gas prices.
The experience gained in Wattenberg has assisted the Company in developing other large scale drilling projects in the Rockies and the Gulf Coast. By yearend 1994, these projects (including certain fields in northern Wyoming acquired in late 1992) accounted for 60.7 MMBOE, or more than half, of the Company's proved reserves. In the East Washakie and Deep Green River areas of the Washakie Basin of
southern Wyoming (collectively, Greater Green River), the Company drilled 39 wells during 1994 with production reaching 4,400 BOE per day in December 1994. The Company operates 153 wells and holds a significant inventory of potential drilling locations, including 102 locations classified as proved undeveloped at December 31, 1994. The Western Slope Project incorporates portions of the Piceance Basin of western Colorado and the Uinta Basin of Utah. In 1994, the Company drilled 25 wells in the Piceance Basin with production reaching nearly 2,000 BOE per day by yearend. A total of 9 wells were drilled in late 1994 in the Uinta Basin with production remaining modest at yearend. The Company operates 143 wells in these two Basins and holds a significant inventory of potential drilling locations, including 70 locations that were classified as proved undeveloped at December 31, 1994. In the Giddings Field in southeast Texas, the Company placed 23 horizontal oil wells on sales during 1994, increasing its production to 3,600 BOE per day by yearend. It also added to its inventory of potential locations in the Field, including 20 locations that were classified as proved at yearend 1994.
In view of the low current gas prices, the Company plans to limit its 1995 development expenditures to $70 million. This level of expenditure is expected to fund the drilling of up to 150 wells, 70 of which are planned for Wattenberg, 22 in the Greater Green River area, 36 in the Western Slope Project and 20 in the Giddings Field, where oil is the primary objective. Gas wells slated for drilling in 1995 have been limited to those expected to yield a high rate of return even at current prices or those which help evaluate or hold material acreage positions. The Company intends to continue to purchase acreage to establish new development projects and to seek to acquire properties which strengthen its existing asset base or secure a foothold in new geographic areas. The Company also expects to be able to continue to pursue various international projects at a limited capital cost. The overall objective is to maintain a superior record of growth without taking undue financial risk in the current adverse climate. Every effort is being made to retain and enhance the Company's ability to accelerate drilling if gas prices recover.
Development
General. Since 1990, development drilling has been the Company's primary focus. The Company's existing properties have extensive development drilling and enhancement potential, primarily in the DJ Basin of Colorado, the Washakie and Green River Basins in southern Wyoming, the Piceance and Uinta Basins in western Colorado and Utah and in the Giddings Field in southeast Texas. The Company designs its major drilling programs to reduce risk, create synergies with its gas management operations and exploit the potential for continuous cost improvement. Owing to the low current gas prices, the Company expects to drill only 150 wells in 1995, including 70 wells in Wattenberg, as opposed to over 500 wells drilled during 1994, 370 of which were in Wattenberg. Emphasis will be placed on drilling for oil, with over 40% of development expenditure slated for development of projects, primarily in the Giddings Field and the Uinta Basin., where oil is the primary objective.
In its large scale development projects, the Company attempts to acquire and maintain a sizeable inventory of potential drilling locations, many of which may not be economic at current cost and price levels, but which may prove attractive if reservoir assumptions are validated and well economics improve over the life of the project through cost reductions or price increases.
Assuming no material changes in energy prices, the Company plans to spend $70 million on development drilling in 1995. Such expenditures totalled $90.6 million in 1993 and $156.9 million in 1994.
DJ Basin
Wattenberg Field. Wattenberg is the Company's largest base of operations, representing approximately 45% of total proved reserves at December 31, 1994. Over the past four years, a total of 1,037 wells have been drilled in Wattenberg, including 370 wells drilled in 1994. At yearend, the Company had interests in more than 1,800
producing wells, of which it operated 1,500. Owing primarily to depressed gas prices, the Company expects to drill less than 100 wells and to undertake 60 recompletions in Wattenberg in 1995. The Company has numerous Wattenberg locations which would be attractive to drill at higher gas prices. If gas prices increase, the Company would expect to materially increase its drilling in the Field.
At yearend 1994, the net proved reserves attributed to the Wattenberg properties were 12.2 million barrels of oil and 178.7 Bcf of gas. Proved reserve quantities were significantly reduced by low year-end gas prices (approximately $1.69 per Mcf) prevailing in Wattenberg. The reserves were attributable to 1,847 producing wells, 63 wells in progress, 340 proved undeveloped locations and approximately 323 proved behind pipe zones. The number of proved undeveloped locations is sensitive to the prevailing level of gas prices, and could increase significantly if prices return to historic levels. The Company expects proved reserves to be assigned to additional locations as drilling progresses.
The Codell formation, traditionally the primary objective of the drilling, is a blanket siltstone formation that exists under much of the Wattenberg acreage at depths of 6,700 to 7,500 feet. Codell reserves generally have a high degree of predictability due to uniform deposition and gradual transition from high to low gas/oil ratio areas. The Company frequently dually completes the Niobrara chalk formation, which lies immediately above the Codell, to enhance drilling economics. The Codell/Niobrara wells produce most prolifically in the first six to twelve months, after which production declines to a fraction of initial rates. More than half of a typical well's reserves are recovered in the first three years of production. As a result, each well contributes significantly more production in its first year than in subsequent years.
During 1994, the Company continued to expand its drilling targets to include both deeper and shallower formations. The J sand lies approximately 400 feet below the Codell. It is a low permeability sandstone generally found to be productive throughout the DJ Basin, with performance varying with porosity and thickness and much greater variability outside the heart of the Wattenberg Field. The Dakota formation lies approximately 150 feet below the J sand. It is a low permeability sand occasionally naturally fractured with less predictable commercial accumulations and varied performance results. During 1994, the Company had some success in using 3-D seismic technology for mapping the Dakota in the southern parts of the Field. The Sussex formation is at average depths of 4,500 feet. The Sussex sands were deposited in bars and exhibit variable reservoir quality with a moderate degree of predictability.
Because the Codell, Niobrara and J formations are continuous reservoirs over a large portion of the DJ Basin, the Company believes that drilling, at least in the heart of the Wattenberg Field, is relatively low risk. Of the 1,037 wells drilled between 1991 and 1994, only 15 were classified as dry holes, and most of these have been in outlying areas of the Basin. Dry holes in the Basin cost an average of $110,000 per well. The average cost of a completed well approximated $204,000 in 1994.
In early 1994, an agreement was finalized with Union Pacific Resource Company ("UPRC") under which the Company has the right for up to six years to drill wells on UPRC's undeveloped acreage in the Wattenberg area. As compensation, UPRC was granted warrants to purchase two million shares of Common Stock. During 1994, the Company drilled 77 wells on acreage committed under the venture. As the result of disappointing drilling in certain outlying areas covered by the venture, the Company paid UPRC $400,000 in early 1995 for an extension of the time period to drill the commitment wells and released a portion of the outlying acreage committed to the venture. The Company has undertaken to drill 55 wells during the last three quarters of 1995, 85 wells from January 1, 1996 through February 28, 1997 and of 70 wells from March 1, 1997 through February 28, 1998. Thereafter, the Company can, at its option, extend the venture for up to two additional years by committing to drill 150 wells per year. There is no limit on the number of wells to drilled, and wells in excess of the minimum reduce the number of wells required in the following year by up to 50%. If the Company drills less than the minimum number of wells, it is required to pay UPRC $20,000 per well for the shortfall. On mineral acreage, UPRC retains a 15% royalty and has the option to receive an additional 10% royalty after pay-out or
to participate as a 50% working interest owner. On leasehold acreage, UPRC does not have the right to participate but retains a royalty that results in a total royalty burden of 25%.
Cheyenne. During 1994, 10 wells were placed on stream in a shallow gas producing area on the northeast flank of the DJ Basin. This project, known as the Cheyenne Project, began with the acquisition of five shut-in gas wells in 1990 when the Company determined that it could capitalize on new open access rules of the Federal Energy Regulatory Commission ("FERC") by constructing a gathering system to transport gas to a nearby interstate pipeline. After acquiring almost 50,000 acres of leases in the area and selling an approximate 27.5% interest to other parties on a promoted basis, the Company has drilled 64 successful wells and eight dry holes in the area and constructed a gathering system having a capacity of 10 MMcf per day to transport the gas to the interstate pipeline. The Company currently operates 72 wells in this area that produce from the Niobrara formation.
Greater Green River
East Washakie. Since the mid-1980's, the Company's properties in the Barrel Springs Unit and the Blue Gap Field of southern Wyoming, together with its gas gathering and transportation facilities there, have been one of its most significant assets. During 1994, the Company continued to develop fluvial Mesaverde sands in the eastern Washakie Basin near these properties. Twenty-five wells were completed in this area in 1994 at depths ranging from 7,500 to 11,000 feet, developing net proved reserves of 3.6 MMBOE. Acquisitions, including the repurchase of a 50% net profits interest in the Barrel Springs Unit,added another 6.6 MMBOE. By yearend, net production of gas, which accounts for approximately 90% of the reserves, had reached 21.4 MMcf per day, up from 9.2 MMcf per day one year earlier. An environmental impact statement covering the Company's southern and eastern lands was approved in October 1994, allowing the drilling of up to 250 locations. Two additional environmental impact statements covering the north and west areas should be approved during 1995 and 1996., allowing up to 500 additional locations by the Company and other producers in these areas. The Company expects to drill 16 wells in East Washakie during 1995.
The Company currently operates 130 wells in this area and holds over 800 potential drilling locations, 101 of which were classified as proved undeveloped at yearend 1994. The Company holds interests in approximately 102,000 gross (78,000 net) undeveloped acres in the Washakie Basin. This includes 36,000 gross (24,000 net) undeveloped acres added during 1994.
Deep Green River. During 1994, the Company initiated a major project to develop fluvial Lance sands in the deep portion of the Green River Basin. The Company participated in five wells during the fourth quarter of 1994, with encouraging results. Production commenced in the fourth quarter and had reached 4.9 MMcf per day by yearend. An eight well program is planned for 1995 in strategic locations to earn acreage and further evaluate potential recoveries. The Company holds interests in approximately 95,000 gross (79,000 net) undeveloped acres in this project. The Company believes that there are in excess of 500 potential drilling locations on this acreage. At the end of 1994, only four locations were classified as proved undeveloped.
Western Slope
Development of the Western Slope Project, encompassing portions of the Piceance Basin on the western slope of Colorado and the Uinta Basin in northeastern Utah, continued during 1994. In the southeast corner of the Piceance Basin, the 9,000 acre Grass Mesa Unit was formed adjacent to the 53,000 acre Hunter Mesa Unit that the Company operates. At yearend, the Company owned approximately 110,000 gross (83,000 net) acres in this portion of the Piceance Basin. In the Douglas Creek Arch area of the Piceance Basin, the Company holds an additional 29,600 net acres. Subsequent to yearend, an agreement was reached to sell most of this acreage at a profit. In the Uinta Basin, the Company holds interests in approximately 104,000 gross (85,000 net) acres. During 1995, the Company expects to reduce its drilling program for gas reserves and to put greater emphasis on drilling oil reserves in the Uinta Basin, with eight wells expected in the Piceance Basin and, depending on further evaluation of recently drilled wells, up to 25 wells planned in the Uinta Basin.
During 1994, 25 new wells were drilled to test the Hunter Mesa and Grass Mesa Units. Most of the wells were placed on production in December, with the remaining wells being completed in early 1995. Net production from the Hunter Mesa, Grass Mesa and Divide Creek Units averaged 11.7 MMcf per day during December 1994, and had reached 16.2 MMcf per day by February 1995. During 1994, the Company acquired or installed 33 miles of gathering lines. These lines provide access to the Rocky Mountain Natural Gas System, which compliments the existing connection to the Questar System. Although this affords greater transportation capacity and flexibility, the extent to which the Company will be able to continue to develop the Piceance Basin is in part dependent on arranging additional gathering and transportation at a reasonable cost. The Company is exploring options for gathering and transporting future gas production, including the possibility of constructing additional Company owned facilities.
Activities in the Uinta Basin during 1994 included the drilling of three wells in the Southman Canyon Mesaverde gas project area, one well in the Horseshoe 'B' gas project area and seven wells in the Green River oil fairway project. Two of the Southman Canyon wells were completed and the third Southman Canyon well and the Horseshoe 'B' were completed in early 1995. Three of the Green River oil wells are on production. Although production rates have not yet stabilized, early tests are encouraging and, if sustained, could lead to a 20 to 25 well drilling program during 1995.
The Company believes there are up to 1,400 potentially drillable locations on its holdings in the Piceance and Uinta Basins. Depths of producing formations range form 3,000 to 9,000 feet, with producing formations including the Uinta 'B', Green River, Wasatch, Mesaverde and Dakota. At yearend 1994 there were 231 proved producing wells, 23 proved non-producing zones and 66 proved undeveloped locations. Proven reserves at yearend were 72.9 Bcf of gas and 1.6 million barrels of oil.
Northern Wyoming
In 1992, the Company acquired four large producing fields from Atlantic Richfield Company. At yearend 1994, proved reserves in these fields totalled 16.2 MMBOE, including 10.9 million barrels of oil and 31.6 Bcf of gas. The Pitchfork and Hamilton Dome fields produce sour crude oil primarily from the Tensleep, Madison and Phosphoria formations at depths of 2,500 to 4,000 feet. The Salt Creek field produces sweet crude oil from the Wall Creek formation at depths of 2,000 to 2,900 feet. The Riverton Dome field produces primarily gas from the Frontier and Dakota tight sands formations at 8,000 to 10,000 feet with some sour crude oil production from the Tensleep and Phosphoria. Production from this field is processed at a Company-owned plant.
The Company operates the Hamilton Dome Field, located in the Big Horn Basin, and the Riverton Dome Field, located in the Wind River Basin. Since the acquisition, the Company has focused on enhancing value through reducing operating expenses, waterflood optimization, workovers and recompletions and limited additional drilling. In 1994 the Company initiated stepout drilling in the Riverton Dome Field, where two successful wells were completed in the Frontier and Dakota formations. A third well was completed early in 1995. One successful Tensleep infill well was drilled in Hamilton Dome during late 1994. Production from the Riverton Dome and Hamilton Dome Fields exceeded levels projected at the time of the acquisition by 11% during 1994, and is expected to exceed the originally projected amounts by 28% during 1995. While production have been increased, the Company has reduced its lease operating expenses in these fields by approximately $400,000 per year.
The Company initiated two new exploitation projects in northern Wyoming during 1995. In the Wind River Basin, the Company has assembled approximately 73,000 net acres. Plans are to continue leasing through mid-1995, with initial drilling expected in early 1996. In the Big Horn Basin, the Company had assembled approximately 43,000 net acres through February 1995. Additional leasing is expected to continue through the second half of 1995. Initial drilling on the project is targeted for the fourth quarter of 1995.
Gulf Coast Area
In the Giddings Field in southeast Texas, the Company continued expanding its horizontal drilling program. Horizontal drilling entails risks in that the technology is still relatively new and rapidly evolving, costs are relatively high (with dry hole costs
ranging from $900,000 to $1.45 million for a new well and $350,000 to $750,000 for a re-entry well) and high initial production, while leading to high rates of return on successful wells, makes ultimate recoveries difficult to predict. The Company's program has been successful to date, and increasing emphasis is being placed on horizontal drilling in Giddings. During 1994, the Company drilled 33 wells in the Field and at yearend had placed 23 wells on sales with nine wells in progress. One well was abandoned. Daily net production averaged 3,600 BOE during December 1994, or nearly 10% of total Company production, compared to 1,500 BOE a year earlier. Proved reserves are 38% oil and 62% gas and exceeded 7.1 MMBOE at yearend. Based on attractive economics of the program to date, the Company acquired approximately 30,000 net undeveloped acres in the Austin Chalk Trend, including the Giddings Field in 1994, and plans to continue its horizontal drilling activity during 1995, with plans to drill up to 20 wells and complete the nine wells in progress at yearend. Oil is expected to be nearly 60% of production from the locations to be drilled in 1995. Based on currently budgeted capital expenditures, drilling in the Giddings Field will be the Company's largest single project during 1995. The Company has 50 locations classified as proved undeveloped, and believes that the total number of potential drillable locations may ultimately be twice that number. During 1994, the Company also acquired for $4.3 million working interests in 10 producing wells in Brazos County which the Company believes may have additional horizontal development potential.
The Company acquired overriding royalty interests in approximately 250 producing wells and 330,000 net mineral acres, primarily in north Louisiana, in 1994 for a price of $9.7 million. The Company also entered into lease option agreements covering an additional 373,000 net acres in north Louisiana. The transactions also included access to over 5,000 miles of seismic data, which the Company is currently reviewing to seek acquisition opportunities and to develop exploitation and exploration prospects to drill or to promote to industry partners. During 1994 the Company drilled 14 wells, 3 of which were placed on production and 11 of which were abandoned, to test the shallow Wilcox formation. The cost of the abandoned wells averaged approximately $60,000 per well. Several formations are productive in the area, including the Wilcox, Hosston and Cotton Valley trends, and the Company expects to develop prospects covering one or more of these formations.
In late 1994, the Company acquired 51% of the common stock of DelMar Petroleum, Inc., a closely-held company headquartered in Houston, Texas, for $6.6 million. DelMar owns interests in and operates 22 platforms in the Gulf of Mexico and manages investment programs for institutional partners. During the last quarter or 1994, DelMar acquired the interests of one of its institutional partners for approximately $3.5 million and implemented a development program at its Main Pass prospect. At yearend four wells had been completed and were producing at an aggregate rate of 65 MMcf per day. DelMar's interest in the Main Pass couples is currently less than 1%. The Company believes its ownership position in DelMar will enable it to expand its position in the Gulf of Mexico through acquisitions, development and, to a much lesser extent, exploration. Such expansion may be pursued through DelMar or directly.
Gas Management
General. The Company expanded its gas gathering and processing capacity during 1994 with the construction of additional gathering facilities and construction of the West Plant in Wattenberg. By yearend, operated processing capacity had increased to more than 160 MMcf per day and gathering system capacity was increased to more than 250 MMcf per day. The gas management unit complements the Company's development and acquisition activities by providing additional cash flow and enhancing returns. The segment is also increasingly profitable in its own right. During 1994, gross margin increased by approximately 42% to $13.1 million. See "Customers and Marketing."
Colorado Facilities. The largest concentration of gas facilities is in the Wattenberg area. These facilities include two major gathering systems, the Enterprise system and Energy Pipeline, the Roggen and West Plant processing plants, and a number of minor facilities. By yearend 1994, plant capacity had reached 140 MMcf per day, as the result of completion of the West Plant in late October. During the fourth quarter of 1994, average throughput reached 72 MMcf per day.
The gas produced from most wells drilled on acreage acquired from Amoco is dedicated for the life of the lease to Amoco's Wattenberg gas processing plant. If Amoco were unable to process Company production at its plant for any reason, including a shut-down of the plant, it would have a short-term adverse impact on the Company. The Wattenberg plants enable the Company to mitigate the effects of any downtime at the Amoco plant.
At the Wattenberg plants, gas is processed to recover gas liquids, primarily propane and a butane/gasoline mix, from gas supplied by the Company and third parties. The liquids are then sold separately from the residue gas. The liquids are marketed to local and regional distributors and the residue gas is sold to utilities, independent marketers and end users through an intrastate system and the Colorado Interstate Gas ("CIG") pipeline. Two liquids lines permit the direct sale of liquids products through either an Amoco line to the major interchange at Conway, Kansas or to the Phillips Petroleum line which connects the plants to the Phillips Powder River liquids pipeline.
The Company's Wattenberg gathering systems include over 900 miles of pipeline that collect, compress and deliver gas from over 1,850 wells to the Wattenberg plants. During 1994, the Company substantially increased the capacity of its gathering systems through the expansion of existing facilities and the acquisition of new facilities. Enterprise collects a portion of the Company's gas produced from acreage acquired from Amoco and delivers it to the Amoco Wattenberg plant. Enterprise includes 26 miles of 20" diameter trunk and 29 miles of associated lateral gathering lines connecting 20 of the Company's existing central delivery points. As a result of the completion of the second phase, the Enterprise system has the capacity to deliver 75 MMcf per day to the Amoco Wattenberg plant.
The Company has negotiated a transportation arrangement with CIG that, in conjunction with the gathering fees to be charged on the Company's gathering systems, allows the delivery of gas to the Amoco Wattenberg plant at a favorable rate. In addition to reducing the Company's exposure to future escalation in gathering costs applicable to the Company's production, Enterprise provides an enhanced degree of operational control. Because the Enterprise system interconnects with the Company's other Colorado facilities, the Company's plants and other plants in the area can serve as a backup for processing a portion of the Company's gas in the event of any curtailment at the Amoco Wattenberg plant. While shut downs of Amoco's plant reduce the Company's production, diversion of gas to the Company's plants and, to a lesser degree, two other plants in the area, enabled the Company to produce significant volumes that would have otherwise been curtailed.
Subsequent to yearend 1994, the Company announced that it was considering the sale of its Wattenberg gas facilities.
Wyoming Facilities. The Company operates two pipeline systems in Wyoming that enhance its ability to market gas produced from its properties in the Washakie Basin. Wyoming Gathering and Production Company ("WYGAP") gathers gas produced from approximately 150 operated wells in the Barrel Springs Unit and the Blue Gap area. The system has a capacity of 26 MMcf per day. Throughput averaged 14 MMcf and 19 MMcf per day during 1993 and 1994, respectively. WYGAP delivers gas to Western Transmission Corporation ("Westrans"), a Company-owned interstate pipeline system which operates under FERC jurisdiction.
The Westrans system consists of a 26-mile main pipeline, a smaller 9.2 mile line and related gathering facilities. The system gathers and transports gas under open access transportation service agreements on an interruptible basis. The main line extends from the Washakie Basin area of Carbon County, Wyoming to connections with Williams' and CIG's interstate pipelines in Sweetwater County, Wyoming. Gas transported on Westrans also has access to California markets through the Kern River Pipeline via interconnects with CIG and Williams. Westrans is located near several other interstate pipelines, providing the potential for additional interconnects that offer alternative transportation routes to end markets. In addition to the gas from WYGAP, which accounts for over 85% of its volumes, Westrans transports volumes from other operated wells and third parties. The capacity of Westrans is 65 MMcf per day. Daily throughput averaged 15 MMcf during 1993 and 22 MMcf during 1994. As the East Washakie project progresses, the Company expects to further expand its gathering network in the area.
Other Facilities. The Company expanded its gathering system in southern Nebraska during 1994 to gather gas produced from newly developed Cheyenne County properties for delivery to various markets accessible through an interstate pipeline. The Cheyenne system includes 14 miles of 4" to 6" trunkline and 10 miles of 3" lateral gathering lines. During the fourth quarter of 1994, throughput averaged over 4 MMcf per day of gas from 70 producing wells. Included in the 1992 acquisition of Wyoming properties was a gas processing plant in Fremont County, Wyoming. The plant has a 20 MMcf per day capacity with current throughput of 7 MMcf per day from wells in the Riverton Dome Field.
In conjunction with the growing level of acquisition and development activity in the Western Slope Project, the Company is actively exploring alternatives to gather and transport future gas production, including the possible construction of a Company-owned gathering and transportation line. Traditionally, the lack of sufficient pipeline capacity has been a major deterrent to development in the Piceance Basin. During 1994, the Company acquired or installed 33 miles of pipeline systems in the area. These systems provide access to the Rocky Mountain Natural Gas System, which compliments the existing connection to the Questar System.
International Activities
The Company's strategy internationally is to develop projects that have the potential for a major impact in the future. The Company attempts to structure the projects to limit its financial exposure and mitigate political risk by minimizing financial commitments in the early phases of a project and seeking industry partners and investors to fund the majority of the equity capital. A wholly owned subsidiary of the Company, SOCO International, Inc., is the holding company for all international operations. Edward T. Story, President of SOCO International holds an option to purchase 10% of the currently outstanding shares of SOCO International, through April 1998.
Russian Joint Venture. Permtex, a joint drilling venture formed in 1993 with Permneft, a Russian oil and gas company, officially began operations in mid 1994. The venture was formed to develop proven oil fields located in the Volga-Urals Basin of the Perm Region of Russia, approximately 800 miles east of Moscow. Permtex holds exploration and development rights to over 300,000 acres in the Volga-Urals Basin, in a contract area containing four major and four minor fields as well as other potential prospects. The Company estimates that the four major fields could ultimately produce 115 million barrels of oil, of which approximately 30% was classified as proved at yearend, with the remaining reserves expected to be ultimately recovered through implementation of waterflood projects. The joint venture utilizes primarily Russian personnel and equipment and Western technology under joint Russian/American management.
The major fields were previously delineated through 45 previously drilled wells. Four of these wells were placed on production during 1994 with production averaging 1,000 barrels per day. Through the end of 1994, the venture produced approximately 80,000 barrels of oil. It is anticipated that 25 of the existing wells will ultimately be placed on production, and that up to 400 additional development wells will be drilled over the next five to ten years. An 18-mile pipeline extension linking the Logovskoye field with refineries in Perm was completed in 1994 and a pump station is now being installed. Upon completion of the pipeline and approval by the state inspection committee, three new development wells drilled during 1994 will be placed on production, which should increase production by 1,000 barrels per day.
The venture successfully exported three shipments of oil totalling 69,000 barrels of oil with payment in U.S. dollars during 1994. Also, the venture has received an exemption from excise taxes and has applied for exemption from the export tariff, which is currently equivalent to $4.00 per barrel (based on an exchange rate of .75 European Currency Units per Dollar).
Based on currently expected rig availability in the area, the venture plans to drill approximately 18 new wells during 1995. In addition, several of the previously existing wells are scheduled to be brought on stream through rework and perforation upon completion of the pipeline pump station.
During 1994, Command, the Company's Australian affiliate, Holland Sea Search NV ("HSSH"), a Dutch affiliate of Command, and ITOCHU, a major Japanese trading company which has agreed to purchase
oil from the venture for export, purchased equity interests in Permtex for aggregate contributions of $11.25 million, of which $8.5 million was received during 1994. As the result of these contributions, the Company's interest in Permtex decreased from 37.5% to 20.6%. The Company also received a commitment from the Overseas Private Investment Corporation ("OPIC"), an agency of the United States Government, to provide political risk insurance and up to $40 million in financing to fund Permtex's initial operations. Closing on the OPIC financing, which would be guaranteed in certain respects by the Company, is expected in late spring 1995 with drawings expected to commence in mid-summer.
Command Petroleum Limited. In 1993, the Company purchased 42.8% of the outstanding shares of Command for approximately $18.2 million. Due to shares subsequently issued by Command in a series of transactions, the Company's current interest in Command is 29%. Command is an exploration and production company based in Sydney, Australia and listed on the Australian Stock Exchange. At yearend 1994 Command had a market capitalization of $100 million, working capital of $36 million and no debt. Command currently holds interests in more than 14 exploration permits and production licenses primarily in the Southwestern Pacific Rim including Australia and Papua New Guinea, Tunisia, Yemen and India. Command also holds a 48% interest in HSSH, a publicly traded Dutch exploration and production company whose primary asset is an interest in the North Sea's Markham gas field.
During 1994 Command and its industry partners signed a production sharing contract with the government of India to develop the Ravva Field in the Bay of Bengal. Command owns 22.5% of the venture and is the operator for the project. Command, together with HSSH, also purchased a 12.5% interest in Permtex, the Company's Russian venture. In 1995, Command purchased the Company's concession rights in Tunisia in return for Command stock and purchased a 10% interest in the Company's Mongolian venture.
Mongolia. The Company further expanded its Mongolian venture during 1994 and early 1995. In 1993, the Company entered into a production sharing agreement with Mongol Petroleum Company, the national oil company of Mongolia covering a block of 11,400 square kilometers, or approximately 2.8 million gross acres, in the Tamtsag Basin of northeastern Mongolia. In late 1994 an adjacent block was acquired, increasing the Company's acreage to 5.3 million acres, in exchange for a 1.25% overriding royalty interest in both blocks. These concessions offset the Hailar Basin of China. The venture also has applications for production sharing contracts pending as a co- applicant with the Mongolian government for an additional five million acres on two blocks adjacent to the venture's current blocks. If these concessions are awarded, the venture's acreage would cover the entire Tamtsag Basin in Mongolia.
During 1994, the venture continued its seismic acquisition program. Seismic acquisition to date has identified the presence of large structures which seem analogous to the Songliao Basin of China which contains the Daqing field. The first well to test the acreage is expected to begin drilling in the second quarter of 1995. In late 1994 a consortium was formed with PT BIP Energimas ("BIP"), the oil and gas subsidiary of PT Bhuwanatala Indah Permai, a publicly listed Indonesian company, whereby BIP acquired an interest in the venture in exchange for committing to drill two 3,400 meter wells. Command also acquired a 10% interest at yearend 1994. The Company's interest in the venture is 49.5%, which will be reduced to 38% upon completion of the required seismic program by one of the Company's co-venturers.
Although the prospective potential of the previously unexplored Tamtsag Basin has long been recognized, the lack of an outlet for production has prevented exploration in the Basin. In early 1995, the venture entered into an agreement with China National United Oil Corporation ("CNUOC"), under which CNUOC agreed to purchase crude oil produced by the venture at a mutually-agreed Mongolian/Chinese border point at world market prices, less $2 per barrel. CNUOC is a joint venture between China National Petroleum Corporation and SINOCHEM, both state-owned entities.
Tunisia. In early 1995, the Company transferred its interests in the Fejaj Permit area to Command, which already holds interests in that country. In exchange for the transfer, the Company received 4.7 million shares of Command stock having a market value approximating the Company's investment in Tunisia and will receive an additional 4.7 million shares if a commercial discovery is made as the result of the initial 4,000 meter drilling commitment. Depending on Command's success in locating farmout partners to drill
the first well on the concession, the Company has agreed to pay up to $750,000 of the costs incurred by Command in drilling such well.
Production, Revenue and Price History
The following table sets forth information regarding net production of crude oil and liquids and natural gas, revenues and expenses attributable to such production and to natural gas transportation, processing and marketing and certain price and cost information for the five years ended December 31, 1994.
Drilling Results
The following table sets forth information with respect to wells drilled during the past three years. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons whether or not they produce a reasonable rate of return.
As of December 31, 1994, the Company had 92 gross (75.9 net) development wells in progress. Between yearend and February 28, 1995, the Company spudded 28 wells. At that date 78 gross (73.0 net) wells, including wells in progress at yearend, had been completed, one well (1.0 net) had been abandoned and 52 gross (45.9 net) development wells were in progress.
Field Operations
In its capacity as operator, the Company supervises day-to-day field activities, generally employing a combination of its personnel and contract pumpers. The Company maintains eight district field offices and one division office.
As operator, the Company charges overhead fees to all working interest owners according to the applicable operating agreements. As of the end of 1992, 1993 and 1994, respectively, the Company operated 1,745, 2,176 and 2,634 wells. The Company received overhead reimbursements for operations and drilling of $12.9 million, $17.0 million and $23.9 million during 1992, 1993 and 1994, respectively (including reimbursements attributable to the Company's interest). The increase in reimbursements is attributable to the increase in operated drilling and producing wells and contractual escalations. Based on the time allocated to operations, these reimbursements in aggregate generally have exceeded the costs of such activities.
Customers and Marketing
The Company's oil and gas production is principally sold to end users, marketers and other purchasers having access to pipeline facilities near its properties. Where there is no access to pipelines, crude oil is trucked to storage facilities. In 1993 and 1994, Amoco accounted for approximately 12% and 11% of revenues,
respectively. The marketing of oil and gas by the Company can be affected by a number of factors that are beyond its control and whose future effect cannot be accurately predicted. The Company does not believe, however, that the loss of any of its customers would have a material adverse effect on its operations.
Primarily due to reduced margins resulting from decreases in the differential between Rocky Mountain gas prices and prices in the Mid-Continent and Gulf Coast regions, the Company discontinued third party marketing during the last half of 1994 and began to concentrate its marketing efforts on maximizing value received for equity gas. As a results, gross margins during 1994 from third party marketing activities decreased from $1.2 million to $.6 million.
In June 1991, the Company entered into a contract to supply gas to a cogeneration facility through August 2004. The contract calls for the Company to supply 10,000 MMBtu per day. This plant, which requires up to 24,500 MMBtu per day of gas, began operations in 1989 and is located at a manufacturing facility in Oklahoma City. The effect of this contract depends on market prices for gas and the local utility's choice of alternative sources of fuel to meet its supply commitments. Gross margin generated from the contract was approximately $1.5 million for both 1991 and 1992. Contractual limitations resulted in a net loss of $267,000 from this contract during 1993. During 1994, the gross margin was $.4 million.
During 1994, the Company began a program to manage risk associated with gas prices in the Rocky Mountain region. Beginning September 1, 1994, the Company entered into a ten-year 20,000 MMBtu per day basis swap to lock in the differential between prices for Rocky Mountain region gas as compared to gas prices in the Gulf Coast market. The Company is continuing to develop an overall strategy to manage the risk associated with volatile prices in markets for its products.
Competition
The oil and gas industry is highly competitive in all its phases. Competition is particularly intense with respect to the acquisition of producing properties. There is also competition for the acquisition of oil and gas leases, in the hiring of experienced personnel and from other industries in supplying alternative sources of energy.
Competitors in acquisitions, exploration, development and production include the major oil companies in addition to numerous independent oil companies, individual proprietors, drilling and acquisition programs and others. Many of these competitors possess financial and personnel resources substantially in excess of those available to the Company. Such competitors may be able to pay more for desirable leases and to evaluate, bid for and purchase a greater number of properties than the financial or personnel resources of the Company permit. The ability of the Company to increase reserves in the future will be dependent on its ability to select and acquire suitable producing properties and prospects for future exploration and development.
Title to Properties
Title to the properties is subject to royalty, overriding royalty, carried and other similar interests and contractual arrangements customary in the oil and gas industry, to liens incident to operating agreements and for current taxes not yet due and other comparatively minor encumbrances. The majority of the value of the Company's properties is mortgaged to secure borrowings under the bank credit agreement.
As is customary in the oil and gas industry, only a perfunctory investigation as to ownership is conducted at the time undeveloped properties believed to be suitable for drilling are acquired. Prior to the commencement of drilling on a tract, a detailed title examination is conducted and curative work is performed with respect to known significant defects.
Regulation
The Company's operations are affected by political developments and federal and state laws and regulations. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic and other reasons. Numerous departments and agencies, federal, state, local and Indian, issue
rules and regulations binding on the oil and gas industry, some of which carry substantial penalties for failure to comply. The regulatory burden on the oil and gas industry increases the Company's cost of doing business, decreases flexibility in the timing of operations and may adversely affect the economics of capital projects.
In the past, the federal government has regulated the prices at which oil and gas could be sold. Prices of oil and gas sold by the Company are not currently regulated. There can be no assurance, however, that sales of the Company's production will not be subject to federal regulation in the future.
The following discussion of various statutes, rules, regulations or governmental orders to which the Company's operations may be subject is necessarily brief and is not intended to be a complete discussion thereof.
Federal Regulation of Natural Gas. Historically, the sale and transportation of natural gas in interstate commerce have been regulated under various federal and state laws including, but not limited to, the Natural Gas Act of 1938, as amended ("NGA") and the Natural Gas Policy Act of 1978 ("NGPA"), both of which are administered by FERC. However, regulation of first sales, including the certificate and abandonment requirements and price regulation, was phased out during the late 1980's and all remaining wellhead price ceilings terminated on January 1, 1993.
FERC continues to have jurisdiction over transportation and sales other than first sales. Commencing in the mid-1980's, FERC promulgated several orders designed to correct perceived market distortions resulting from the traditional role of major interstate pipeline companies as wholesalers of gas and to make gas markets more competitive by removing transportation and other barriers to market access. These orders have had and will continue to have a significant influence on natural gas markets in the United States and have, among other things, allowed non-pipeline companies, including the Company, to market gas and fostered the development of a large spot market for gas. These orders have gone through various permutations, due in significant part to FERC's response to court review of these orders. Parts of these orders remain subject to judicial review, and the Company is unable to predict the impact on its natural gas production and marketing operations of judicial review of these orders.
In April 1992, FERC issued Order 636, a rule designed to restructure the interstate natural gas transportation and marketing system to remove various barriers and practices that have historically limited non-pipeline gas sellers, including producers, from effectively competing with pipelines. The restructuring process required the "unbundling" of pipeline services (e.g., transportation, sales and storage) so that producers, marketers and end users of natural gas contract only for those services which they need and may obtain each service from the most economical source. The 1993-1994 winter heating season was the first period during which FERC Order 636 procedures were operative. To date, as management of the Company believes the Order 636 procedures have not had any significant effect on the Company.
State Regulation of Transportation of Natural Gas. Some states have adopted open-access transportation rules or policies requiring intrastate pipelines or local distribution companies to transport natural gas to the extent of available capacity. These rules or policies, like federal rules, are designed to increase competition in natural gas markets. The economic impact on the Company and gas producers generally of these rules and policies is uncertain.
State Regulation of Drilling and Production. State regulatory authorities have established rules and regulations requiring permits for drilling, reclamation and plugging bonds and reports concerning operations, among other matters. Most states in which the Company operates also have statutes and regulations governing a number of environmental and conservation matters, including the unitization or pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells. Some states also restrict production to the market demand for oil and gas. Such statutes and regulations may limit the rate at which oil and gas could otherwise be produced from the Company's properties. Some states have enacted statutes prescribing ceiling prices for gas sold within the state.
In Colorado surface owner groups have been active at both the state and local levels, and there have been a number of city and county governments who have either enacted new regulations or are considering doing so. The incidence of such local regulation increased following a decision of the Colorado Supreme Court which held that local governments could not prohibit the conduct of drilling activities which were the subject of permits issued by the Colorado Oil and Gas Conservation Commission ("COGCC"), but that they could limit those activities under their land use authority. Under this decision, local municipalities and counties may take the position that they have the authority to impose restrictions or conditions on the conduct of such operations which could materially increase the cost of such operations or even render them entirely uneconomic. The Company is not able to predict which jurisdictions may adopt such regulations, what form they may take, or the ultimate effects of such enactments on its operations. In general, however, these ordinances are aimed at increasing the involvement of local governments in the permitting of oil and gas operations, requiring additional restrictions or conditions on the conduct of operations, to reduce the impact on the surrounding community and increasing financial assurance requirements. Accordingly, the ordinances have the potential to delay and increase the cost, or in some cases, to prohibit entirely the conduct of drilling operations.
In response to the concerns of surface owners, during 1993 the COGCC adopted, regulations for the DJ Basin governing notice to and consultation with surface owners prior to the conduct of drilling operations, imposing specific reclamation requirements on operators upon the conclusion of operations and containing bonding requirements for the protection of surface owners and enhanced financial assurance requirements.
During 1994, the Colorado legislature enacted Senate Bill 940177, which gave additional authority to the COGCC to promote not only the development of oil and gas, but also to consider the health, safety and welfare of the public in its decision-making process. There are currently in effect or proposed five rule making task forces to study such matters as reclamation, well control procedures, financial assurances and protection of water quality. Although industry is a participant on the task forces, it is possible that additional restrictions could be imposed that could add to the cost of oil and gas operations in Colorado.
Environmental Regulations. Operations of the Company are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, prohibit drilling activities on certain lands lying within wilderness and other protected areas and impose substantial liabilities for pollution resulting from drilling operations. Such laws and regulations also restrict air or other pollution and disposal of wastes resulting from the operation of gas processing plants, pipeline systems and other facilities owned directly or indirectly by the Company.
In connection with its most significant acquisitions, the Company has performed environmental assessments and found no material environmental noncompliance or clean-up liabilities requiring action in the near or intermediate future, although some matters identified in the environmental assessments are subject to ongoing review. The Company has assumed responsibility for some of the matters identified. Some of the Company's properties, particularly larger units that have been in operation for several decades, may require significant costs for reclamation and restoration when operations eventually cease. Environmental assessments have not been performed on all of the Company's properties. To date, expenditures for environmental control facilities and for remediation have not been significant to the Company. The Company believes, however, that it is reasonably likely that the trend toward stricter standards in environmental legislation and regulations will continue. For instance, efforts have been made in Congress to amend the Resource Conservation and Recovery Act to reclassify oil and gas production wastes as "hazardous waste," the effect of which would be to further regulate the handling, transportation and disposal of such waste. If such legislation were to pass, it could have a significant adverse impact on the Company's operating costs, as well as the oil and gas industry in general.
New initiatives regulating the disposal of oil and gas waste are also pending in certain states, including states in which the Company conducts operations, and these various initiatives could have a similar impact on the Company. The COGCC has enacted rules regarding the regulation of disposal of oil field waste. These rules establish significant new permitting, record-keeping and compliance procedures relating to the operation of pits, the disposal of produced water, and the disposal and/or treatment of oil field waste, including waste currently exempt from federal regulation. These rules may require the addition of technical personnel to perform the
necessary record-keeping and compliance and may require the termination of production from some of the Company's marginal wells, for which the cost of compliance would exceed the value of remaining production. In addition, as indicated above, the COGCC has enacted regulations imposing specific reclamation requirements on operators upon the conclusion of their operations. Management believes that compliance with current applicable laws and regulations will not have a material adverse impact on the Company.
During 1995, the COGCC has scheduled rulemaking proceedings to consider, among other things, groundwater protection. It is expected that unlined pits, including buried concrete tanks, will be a focus of the proceedings. It is possible that the COGCC will prohibit new unlined pits and may require closure of unlined pits and buried concrete tanks in areas that are considered sensitive. The Company estimates that it has approximately 400 sites in Wattenberg that could be affected if the COGCC requires closure of unlined pits and buried concrete tanks throughout the Wattenberg area. The Company is unable to predict when and if the rules will be adopted and, if adopted, the number of facilities that will be affected, the period over which closure would be required or the procedures involved.
A number of states have recently established more stringent environmental regulations to ensure compliance with federal regulations, and have either proposed or are considering regulations to implement the Federal Clean Air Act. These new regulations are not expected to have a significant impact on the Company or its operation. In the longer term, regulations under the Federal Clean Air Act may increase the number and type of Company facilities that require permits, which could increase the Company's cost of operations and restrict its activities in certain areas.
Federal Leases. The Company conducts operations under federal oil and gas leases. These operations must be conducted in accordance with permits issued by the Bureau of Land Management ("BLM") and are subject to a number of other regulatory restrictions. Multi-well drilling projects on federal leases may require preparation of an environmental assessment or environmental impact statement before drilling may commence. Moreover, on certain federal leases, prior approval of drill site locations must be obtained from the Environmental Protection Agency.
Royalty Payments and Production Taxes. The federal government and many states regulate the manner of calculating and payment of royalties to the owners of mineral interests and production and severance taxes to state and local entities. The regulations governing these payments are complex and often provide for penalties for late payments and underpayments. The BLM has assessed SOCO approximately $660,000, including late payment penalties through yearend 1994, for additional royalties for production from the Barrel Springs Unit during 1986 through 1990, claiming that fees charged by a Company-owned pipeline for transporting gas from the Unit constitute fees for gathering, which are not deductible in computing royalties, rather than fees for transportation. The State of Wyoming has assessed the Company approximately $500,000, including late fees and penalties, for additional severance tax, nearly all of which is due to deduction of costs of transporting gas on Company-owned and third party pipelines, for production from 1986 through 1989 from Barrel Springs and other fields in southern Wyoming. The amount of the assessment has been paid under protest. Additional county production taxes would also be payable if the State is successful in asserting its claim. The Company believes that the transportation charges are properly deductible under applicable law and is contesting both assessments.
In December 1994 the Supreme Court of Colorado held that post- production costs incurred by working interest owners to make natural gas "marketable" are not deductible in computing payments due owners of royalty and overriding royalty owners if the instrument creating the royalty is silent on the matter. This holding is contrary to what had generally been regarded as industry custom in Colorado. The decision was decided on a certification of a legal question from a federal district court, and the court did not address a number of crucial issues that could limit or expand significantly the effect of the holding. As a result, the Company cannot currently predict the effect of the decision on its operations.
Officers
Listed below are the officers and a summary of their recent business experience.
John C. Snyder (53), a director and Chairman, founded the Company's predecessor in 1978. From 1973 to 1977, Mr. Snyder was an independent oil operator in Texas and Oklahoma. Previously, he was a director and the Executive Vice President of May Petroleum Inc. where he served from 1971 to 1973. Mr. Snyder was the first president of Canadian-American Resources Fund, Inc., which he founded in 1969. From 1964 to 1966, Mr. Snyder was employed by Humble Oil and Refining Company (currently Exxon Co., USA) as a petroleum engineer. Mr. Snyder received his Bachelor of Science Degree in Petroleum Engineering from the University of Oklahoma and his Masters Degree in Business Administration from the Harvard University Graduate School of Business Administration. Mr. Snyder is a director of the Community Enrichment Center, Inc., Fort Worth.
Thomas J. Edelman (44), a director and President, co-founded the Company. Prior to joining the Company in 1981, he was a Vice President of The First Boston Corporation. From 1975 through 1980, Mr. Edelman was with Lehman Brothers Kuhn Loeb Incorporated. Mr. Edelman received his Bachelor of Arts Degree from Princeton University and his Masters Degree in Finance from the Harvard University Graduate School of Business Administration. Mr. Edelman is a director of Command Petroleum Limited, an affiliate of the Company. In addition, Mr. Edelman serves as chairman of the board of Lomak Petroleum, Inc. and as a director of Petroleum Heat & Power Co., Inc., Wolverine Exploration Company, Enterra Corporation and Star Gas Corporation.
John A. Fanning (55), a director and Executive Vice President, joined the Company in 1987 and has been a director since 1982. Between 1985 and 1987, Mr. Fanning was a private investor. He was a director, President and Chief Executive Officer of The Western Company of North America, which provides drilling and technical services to the oil industry, until 1985. Mr. Fanning joined The Western Company in 1968 and served in various capacities including Director of Planning, Division Manager, President of Western Petroleum Services and Executive Vice President. From 1965 through 1968, he was a Planning and Financial Analyst with The Cabot Corporation. Mr. Fanning received his Bachelor of Science Degree in Physics from Holy Cross College and his Masters Degree in Industrial Management from Massachusetts Institute of Technology. Mr. Fanning is a director of TNP Enterprises Inc, a public utility holding company.
Charles A. Brown (48), Vice President - Emerging Assets, joined the Company in 1987. He was a petroleum engineering consultant from 1986 to 1987. He served as President of CBW Services, Inc., a petroleum engineering consulting firm, from 1979 to 1986 and was employed by KN from 1971 to 1979 and Amerada Hess Corporation from 1969 to 1971. Mr. Brown received his Bachelor of Science Degree in Petroleum Engineering from the Colorado School of Mines.
Steven M. Burr (38), Vice President - Planning and Engineering, joined the Company in 1987. From 1982 to 1987, he was a Vice President with the petroleum engineering consulting firm of Netherland, Sewell & Associates, Inc. ("NSAI"). From 1978 to 1982, Mr. Burr was employed by Exxon Company, U.S.A. in the Production Department. Mr. Burr received his Bachelor of Science Degree in Civil Engineering from Tulane University.
Peter E. Lorenzen (45), Vice President - General Counsel and Secretary, joined the Company in 1991. From 1983 through 1991, he was a shareholder in the Dallas law firm of Johnson & Gibbs, P.C. Prior to that, Mr. Lorenzen was an associate with Cravath, Swaine & Moore. Mr. Lorenzen received his law degree from New York University School of Law and his Bachelor of Arts Degree from The Johns Hopkins University.
David M. Posner (41), Vice President - Gas Management, joined the Company in 1991. From 1980 to 1991, he held various positions with Ladd Petroleum Corporation (a subsidiary of the General Electric Company) including Vice President of Gas Gathering, Processing and Marketing. Mr. Posner received his Bachelor of Arts from Brown University and his Master of Science in Mineral Economics from the Colorado School of Mines.
James H. Shonsey (43), Vice President - Finance, joined the Company in 1991. From 1987 to 1991, Mr. Shonsey served in various capacities including Director of Operations Accounting for Apache Corporation. From 1976 to 1987 he held various positions with Deloitte & Touche, Quantum Resources Corporation, Flare Energy Corporation and Mizel Petro Resources, Inc. Mr. Shonsey received his CPA certificate from the state of Colorado, his Bachelor of Science Degree in Accounting from Regis University and his Master of Science Degree in Accounting from the University of Denver.
George Steel (48), Vice President, joined the Company in 1994. Previously, he was President of Halliburton Geophysical Services, a leading worldwide provider of oil field services. From 1969 to 1989 Mr. Steel served the predecessor company of Halliburton Geophysical in various international assignments. Mr. Steel is a B.Sc. graduate of St. Andrews, Scotland.
Edward T. Story (51), Vice President - International of the Company, joined the Company in 1991. From 1990 to 1991, Mr. Story was Chairman of the Board of a jointly-owned Thai/US company, Thaitex Petroleum Company. Mr. Story was co-founder, Vice Chairman of the Board and Chief Financial Officer of Conquest Exploration Company from 1981 to 1990. He served as Vice President Finance and Chief Financial Officer of Superior Oil Company from 1979 to 1981. Mr. Story held the positions of Exploration and Production Controller and Refining Controller with Exxon U.S.A. from 1975 to 1979. He held various positions in Esso Standard's international companies from 1966 to 1975. Mr. Story received a Bachelor of Science Degree in Accounting from Trinity University, San Antonio, Texas and a Masters of Business Administration from The University of Texas in Austin, Texas. Mr. Story is a director of Command Petroleum Limited, an affiliate of the Company. In addition, Mr. Story serves as a director of Bank Texas, Inc., a bank holding company and Hi/Lo Automotive, Inc., a distributor of automobile parts.
Diana K. Ten Eyck (48), Vice President - Investor Relations, joined the Company in 1993. From 1990 to 1993, Ms. Ten Eyck held various positions with Gerrity Oil & Gas Corporation, including Director, Senior Vice President, Chief Operating Officer, Chief Financial Officer, Chief Administrative Officer and Corporate Secretary. From 1988 to 1990, Ms. Ten Eyck held various positions with The Robert Gerrity Company including Director, Senior Vice President, Chief Operating, Chief Financial Officer and Corporate Secretary. Ms. Ten Eyck received a Bachelor of Arts Degree in Mathematics from the University of Colorado at Boulder and a Ph.D. in Mineral Economics from the Colorado School of Mines.
Stephen G. Tillman (48), Vice President - Greater Green River/DJ Basin, joined the Company in 1994. Between 1990 and 1994, Mr. Tillman was a private investor. He was Senior Vice President and District Manager of TXO Production Corporation (Texas Oil & Gas Corp.) in Denver between 1981 and 1990. Mr. Tillman joined Texas Oil & Gas Corp. in 1974 and served in various capacities including Petroleum Engineer, Drilling & Production Manager and District Manager in Houston and in Wichita, Kansas. From 1968 through 1974,
he held various engineering positions with Texaco Inc. in Texas. Mr. Tillman is a 1969 graduate of Texas A&M University with a Bachelor of Science Degree in Petroleum Engineering.
Rodney L. Waller (45), Vice President - Special Projects, joined the Company in 1977. Previously, Mr. Waller was employed by Arthur Andersen & Co. Mr. Waller received his Bachelor of Arts Degree from Harding University. Mr. Waller serves as a director of Wolverine Exploration Company.
Richard A. Wollin (42), Vice President - Gulf Coast, joined the Company in 1990. From 1983 to 1989, Mr. Wollin served in various management capacities including Executive Vice President of Quinoco Petroleum, Inc. with primary responsibility for acquisition, divestiture and corporate finance activities. From 1976 to 1983, he was employed in various capacities for The St. Paul Companies, Inc., including Senior Vice President of St. Paul Oil & Gas Corp. Mr. Wollin received his Bachelor of Science Degree from St. Olaf College and his law degree from the University of Minnesota Law School. Mr. Wollin is a member of the Minnesota Bar Association.
ITEM 2.



ITEM 2. PROPERTIES
General
The Company's reserves are concentrated in several major producing areas. These include the Wattenberg Field in Colorado, northern and southern Wyoming, the Piceance and Uinta Basins in the Western Slope of Colorado and Utah and, the Giddings area in southeast Texas.
At December 31, 1994, the Company had interests in 5,269 gross (2,651 net) producing oil and gas wells located in 15 states and in the Gulf of Mexico. As of December 31, 1994, estimated proved reserves totalled 120.2 MMBOE, including 35.0 million barrels of oil and 511.3 Bcf of gas. In addition to its oil and gas reserves, the Company holds interests in nine gas transportation and processing facilities.
Proved Reserves
The following table sets forth estimated yearend proved reserves for the three years ended December 31, 1994.
The following table sets forth pretax future net revenues from the production of proved reserves and the Pretax PW10% Value of such revenues.
The quantities and values in the preceding tables are based on prices in effect at December 31, 1994, averaging $15.25 per barrel of oil and $1.56 per Mcf of gas. Price reductions decrease reserve values by lowering the future net revenues attributable to the reserves and also by reducing the quantities of reserves that are recoverable on an economic basis. Price increases have the opposite effect. Any significant decline in prices of oil or gas could have a material adverse effect on the Company's financial condition and results of operations.
Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production.
Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods indicated or that prices and costs will remain constant. With respect to certain properties that historically have experienced seasonal curtailment, the reserve estimates assume that the seasonal pattern of such curtailment will continue in the future. There can be no assurance that actual production will equal the estimated amounts used in the preparation of reserve projections.
The present values shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is specified by the Securities and Exchange Commission ("SEC"), is not necessarily the most appropriate discount rate, and present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate. For properties operated by the Company, expenses exclude the Company's share of overhead charges. In addition, the calculation of estimated future net revenues does not take into account the effect of various cash outlays, including, among other things, general and administrative costs and interest expense.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The data in the above tables represent estimates only. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those shown above. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Results of drilling, testing and production after the date of the estimate may justify revisions. Accordingly, reserve estimates are often materially different from the quantities of oil and gas that are ultimately recovered.
Netherland, Sewell & Associates, Inc. ("NSAI"), independent petroleum consultants, prepared estimates of or audited the Company's proved reserves which collectively represent more than 80% of Pretax PW10% Value as of December 31, 1994. Approximately 58% was estimated independently by NSAI. No estimates of the Company's reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.
Producing Wells
The following table sets forth certain information at December 31, 1994 relating to the producing wells in which the Company owned a working interest. The Company also held royalty interests in 757 producing wells. Wells are classified as oil or gas wells according to their predominant production stream.
Acreage
The following table sets forth certain information at December 31, 1994 relating to acreage held by the Company. Undeveloped acreage is acreage held under lease, permit, contract, or option that is not in a spacing unit for a producing well, including leasehold interests identified for development or exploratory drilling.
Significant Properties
Emphasis has been placed on establishing hubs in certain producing basins. Interests in five producing areas accounted for approximately 86% of Pretax PW10% Value at December 31, 1994. This concentration of assets permits economic efficiencies in the management of assets and permits identification of complementary acquisition candidates. Summary information regarding reserve concentrations of the five most significant properties are set forth below. More detailed information is set forth under "Business - Development."
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries and affiliates are named defendants in lawsuits and involved from time to time in governmental proceedings, 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 for a vote of security holders during the fourth quarter of 1994.
PART II
ITEM 5.

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS
The Company's stock is listed on the New York Stock Exchange and trade under the symbol "SNY". The following table sets forth, for 1993 and 1994, the high and low sales prices for the Company's securities for New York Stock Exchange composite transactions, as reported by The Wall Street Journal.
On March 9, 1995, the closing price of the common stock was $14. Dividends were paid at the rate of $.06 per share in the first and second quarters of 1994. In the third quarter of 1994, the quarterly dividend was increased to $.065 per share. Shares of common stock receive dividends as, if and when declared by the Board of Directors. The amount of future dividends will depend on debt service requirements, dividend requirements on preferred stock, capital expenditures and other factors. On December 31, 1994, there were approximately 3,200 holders of record of the common stock and 30.2 million shares outstanding.
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected financial and operating information for each of the five years ended December 31, 1994. Share and per share amounts refer to common shares. The following information should be read in conjunction with the financial statements presented elsewhere herein.
The following table sets forth unaudited summary financial results on a quarterly basis for the two most recent years.
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
Effective December 31, 1994, the Company changed its method of accounting for oil and gas properties from the full cost method to the successful efforts method. The change was applied retroactively and prior periods presented have been restated. The following discussions of operating results are based on those restated amounts.
Comparison of 1994 results to 1993. Total revenues in 1994 rose 15% to $262.3 million. The revenue increase was primarily the result of a 26% growth in oil and gas production calculated in barrels of oil equivalent ("BOE") and greater gas processing and transportation throughput. The revenue rise was limited by a 12% decline in the average price per BOE. This price decline reduced current year revenues by $18.8 million. Net income for 1994 was $12.4 million, compared to $19.5 million in 1993. In addition to the price decline, the decrease resulted from increased expenses for exploration, interest and depletion. Net income per common share was $.07 in 1994, compared to $.45 in 1993, as higher preferred dividends compounded the effect of declining earnings. Due to conversion of the 8% preferred stock at yearend 1994, preferred dividends will drop 44% in 1995.
The gross margin from production in 1994 increased 10% to $87.8 million, due to the rise in oil and gas production. The average price received for oil production decreased 4% in 1994 to $14.80 per barrel while gas prices dropped 14% to $1.67 per Mcf. Total operating expenses increased 12% during 1994, however, operating costs per BOE decreased to $4.29 from $4.83 in 1993. Of the 11% decrease, almost half resulted from a reallocation of certain internal overhead costs from operating expense to general and administrative expense. The remainder of the expense per BOE decrease was due to cost efficiencies gained with increasing production in concentrated hub areas.
Average daily production during 1994 was 31,966 BOE, up 26% from 1993. By December 1994, average daily production had reached 12,351 barrels and 145.6 MMcf (36,618 BOE). The production increase resulted from continued development activities and acquisitions. In 1994, the Company drilled and completed 466 wells. Of the wells placed on production, 360 were in the DJ Basin of eastern Colorado, 34 in the Green River Basin of southern Wyoming, 23 in the Giddings Field of southeast Texas and 20 in the Piceance Basin of western Colorado. In the DJ Basin, an additional 90 wells were recompleted to enhance production. The Company completed $44.7 million in production acquisitions, the majority of which were for incremental interests in wells in or around current hubs. The significant decline in natural gas prices since mid-year resulted in the Company curtailing its gas development plans for 1995. However, 1995 production is expected to grow by more than 15%, despite the reduced capital budget.
The gross margin from gas processing, transportation and marketing activities for 1994 increased 42% to $13.1 million from $9.2 million in 1993. The increase was primarily attributable to a 45% ($3.7 million) rise in processing and transportation margins as a result of the facilities expansion. In October 1994, operations began at a newly constructed gas processing plant in the DJ Basin. The plant is capable of processing 80 MMcf of gas per day and should add to margins in 1995. During the fourth quarter of 1994, throughput at the DJ Basin processing facilities averaged 72.0 MMcf per day compared to a 1993 annual average of 47.9 MMcf. In the Green River Basin, transportation throughput for fourth quarter 1994 averaged 27.1 MMcf per day compared to 15.3 MMcf for all of 1993. The growth was a direct result of the development drilling in the area. The marketing gross margin increased 16% to total $1.1 million in 1994. However, late in 1994 margins narrowed due to the decrease in price differentials available with the precipitous decline in spot market gas prices. The Company has suspended its involvement in third party marketing until the markets recover.
Other income for 1994 was $17.2 million, up $9.4 million from 1993. The increase resulted from a $3.5 million gain from the sale of a portion of the Company's interest in the Permtex joint venture in Russia, a $3.1 million gain from the sale of equity securities by the Company's Australian affiliate and $2.0 million in gains on sales of properties. After these transactions, the Company's interests in Command and Permtex were reduced to 29% and 21%, respectively.
General and administrative expenses, net of reimbursements, were 3.4% of revenues in 1994, compared to 3.0% of revenues in 1993. The rise was due in part to the previously mentioned change in the allocation of certain internal overhead costs. Interest and other expense was $12.5 million in 1994 compared to $7.3 million in 1993. The increase was the result of a rise in outstanding debt levels due to capital project expenditures, as well as increasing interest rates.
Depletion, depreciation and amortization expense for 1994 increased 30% ($17.8 million) from the prior year. Of the increase, $16.4 million was related to the 26% rise in oil and gas production, with the remainder due to an increase in unevaluated property impairments as provided under successful efforts.
The Company adopted FASB Statement No. 109, "Accounting for Income Taxes," effective January 1, 1992. In 1993, the income tax provision was reduced from the statutory rate of 35% to zero due to the elimination of deferred taxes upon realization of tax basis in excess of financial basis. In 1994, the income tax provision was reduced from the statutory rate by $3.8 million from the realization of the remaining excess tax basis.
Comparison of 1993 results to 1992. Total revenues rose 92% in 1993 to $228.9 million. Net income before extraordinary items increased 54% to reach $22.5 million in 1993. The increase was lead by a rapid rise in production and assisted by an increase in gas processing and transportation margins. After the effect of a $3.0 million 1993 extraordinary charge on early retirement of debt, earnings per common share were $.45 in 1993, compared to $.43 in 1992.
The gross margin from production operations for 1993 increased 62% to $79.7 million, which was primarily related to a growth in oil and gas production. For the year ended December 31, 1993, average daily production was 25,472 BOE, a 65% increase from 1992. The production increase resulted primarily from acquisitions and continuing development drilling in the DJ Basin of Colorado. The price received per equivalent barrel decreased by 3% to $13.41. Total operating expenses including production taxes increased 60% during 1993 although the operating cost per BOE decreased to $4.83 from $4.99 in 1992. Expense reductions gained from wells added in the DJ Basin, where operating costs averaged $2.76 per BOE, were partially offset by the late 1992 acquisition of Wyoming wells from ARCO where operating costs averaged $7.45 per BOE.
The gross margin from gas processing, transportation and marketing activities for 1993 increased 13% to $9.2 million from $8.1 million in 1992. The increase was primarily attributable to a $2.2 million (36%) rise in transportation and processing margins as a result of additional DJ Basin production and the expansion of the related facilities. Gas marketing margins for 1993 decreased by $1.1 million due to reduced margins on the Oklahoma cogeneration supply contract, which declined as a result of an imposed limitation of the contract sales price and rising gas purchase costs. The margin reduction was partially offset by a $667,000 (126%) rise in gas marketing margins resulting from increased third party marketing.
Other income was $9.4 million during 1993, compared to $3.0 million in 1992. The $6.4 million increase resulted from a $3.5 million gas contract settlement received in April, a $1.7 million litigation settlement and greater gains on the sales of securities. General and administrative expenses, net of reimbursements, for 1993 represented 3.0% of revenues compared to 5.6% in 1992 as expenses were held essentially flat while revenues grew 92%. Interest and other expenses increased 28%, primarily as a result of a rise in outstanding debt balances due to development expenditures and acquisitions.
Depletion, depreciation and amortization during 1993 increased 87% from the prior year, a $27.3 million rise. Of the increase, $22.5 million was a direct result of the 65% rise in equivalent production between years, while $3.8 million was due to greater depreciation for plants, pipelines and other equipment. The remaining increase was the result of property impairments and a rise in the depletion rate per equivalent barrel.
Development, Acquisition and Exploration
During 1994, the Company incurred $279.3 million in capital expenditures; including $156.9 million for oil and gas development, $70.3 million for acquisitions, $41.5 million for gas facility expansion, $5.5 million for exploration and $5.1 million for field and office equipment.
Of the total development expenditures, $90.3 million was concentrated in the DJ Basin of Colorado. A total of 360 wells were placed on production there in 1994 with 63 in progress at yearend. Ten wells spudded during the year were plugged and abandoned. The rate of drilling was lower than had been previously estimated as a result of delays associated with permitting difficulties, the impact of declining gas prices and disappointing results on certain outlying Wattenberg acreage, including part of the lands under option from Union Pacific Resources. With the continued declines in gas prices subsequent to yearend 1994, the Company has reduced its DJ Basin drilling plans for 1995 to less than 100 wells.
The Company expended $66.6 million for other development and recompletion projects during 1994 as activity was expanded to other projects. In the Green River Basin of southern Wyoming, 34 wells were placed on sales with eight in progress at yearend. In the horizontal drilling program in the Giddings Field of southeast Texas, 23 wells were placed on sales in 1994, with nine in progress at yearend and one well abandoned. In the Piceance Basin of western Colorado, 20 wells were placed on sales, with five wells in progress at yearend and one well abandoned. The Uinta Basin development program in northeast Utah is still in its early stages with two wells placed on sales and seven wells in progress at yearend. Anticipated drilling expenditures for 1995 will be limited to $70 million in the absence of a rebound in the gas markets.
In 1994, the Company expended $70.3 million for domestic acquisitions, of which $44.7 million was for producing properties and $25.6 million for acreage. The most notable producing acquisitions were $13.9 million for a 50% interest in properties the Company operates in the Green River Basin, $6.6 million for properties in the Piceance Basin, $5.0 million in the DJ Basin, $4.3 million in the Giddings area of southeast Texas and $6.6 million for a controlling interest in DelMar Petroleum, Inc., a company that owns and operates properties in the Gulf of Mexico. In October 1994, the Company closed a $9.7 million acquisition in northeast Louisiana of which $3.0 million was proven and $6.7 million was for 330,000 net mineral acres. The remaining producing interests were acquired mostly in existing Company hub areas. The remaining unproved acreage was also predominantly in or around our existing hubs.
The Company's gas gathering and processing facility operations continue to grow with $41.5 million of capital expenditures in 1994. The work was heavily concentrated in the Wattenberg area of the DJ Basin. Construction of a new $21.3 million gas processing plant on the west end of the Wattenberg Field began operations in October 1994. The project was financed with a capital lease. A total of $8.7 million was expended to increase the Company's gathering systems in the DJ Basin to add pipelines, feeder lines, an additional compressor and new well connections for the continuing drilling activity in the area. At the Roggen Wattenberg plant, $2.9 million was expended to add a new de-ethanizer station, improve metering and boost compression, among other projects. In the Piceance Basin in western Colorado, a $5.0 million gathering system was constructed. The other $3.6 million in expenditures were for system expansions in the Washakie Basin, Nebraska and Utah. Subsequent to yearend 1994, the Company announced that it is considering the sale of its Wattenberg gas facilities to increase its financial flexibility.
Exploration costs for 1994 were $5.5 million, primarily for geological and other studies on the newly acquired undeveloped acreage. Only $213,000 was expended on international projects. In Russia, commercial production began late in the year with pipeline construction still in progress in the southernmost field in the contract area. Three industry partners committed $11.25 million to the joint venture to fully fund the western participants' anticipated equity requirements, of which $8.5 million was received in 1994. In June 1994, a commitment letter was executed with the Overseas Private Investment Corporation ("OPIC") whereby OPIC will commit $40 million to the Russian Permtex project. It is expected that the final OPIC agreement and associated debt financing will be put in place during the second quarter of 1995. In Mongolia and Tunisia, seismic acquisition and processing continues. In January 1995, agreements were reached whereby 100% of the Tunisia project was sold to Command for stock and 10% of the Mongolia properties were sold for cash at gains of $602,000 and $456,000, respectively. In Tunisia, the gain recorded in 1995 could increase by up to $750,000 if a farm out on certain of the acreage is completed. Additionally, an exploratory well is planned and the Company will receive additional proceeds if reserves are discovered. In Mongolia, the Company has a carried interest in two exploratory wells.
Financial Condition and Capital Resources
At December 31, 1994, the Company had total assets of $673.2 million. Total capitalization was $595.8 million, of which 46% was represented by stockholder's equity, 36% by senior debt, 17% by subordinated debt and the remainder by deferred taxes. During 1994, cash provided by operations was $86.5 million, an increase of 26% over 1993. As of December 31, 1994, commitments for capital expenditures totalled $9.9 million. The Company anticipates that 1995 expenditures for development drilling and gas facilities will approximate $80 million. The level of these and other future expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities and market conditions. The Company plans to finance its ongoing development, acquisition and exploration expenditures using internally generated cash flow, asset sales proceeds and existing credit facilities. In addition, joint ventures or future public and private offerings of debt or equity securities may be utilized.
In 1994, the Company renegotiated its bank credit facility and increased it to $500 million. The new facility is divided into a $100 million short-term portion and a $400 million long-term portion that expires on December 31, 1998. Management's policy is to renew the facility on a regular basis. Credit availability is adjusted semiannually to reflect changes in reserves and asset values. The borrowing base was increased to $250 million in the fourth quarter of 1994. The majority of the borrowings currently bear interest at LIBOR plus .75% with the remainder at prime. The Company also has the option to select CD plus .75%. The margin on LIBOR or CD loans will increase to 1% if the Company's consolidated senior debt becomes greater than 80% of its tangible net worth. During 1994 the average interest rate on the revolver was 5.5%. Financial covenants limit debt, require maintenance of minimum working capital and restrict certain payments, including stock repurchases, dividends and contributions or advances to unrestricted subsidiaries. Such restricted payments are limited by a formula that includes underwriting proceeds, cash flow and other items. Based on such limitations, more than $100 million was available for the payment of dividends and other restricted payments as of December 31, 1994.
In May 1994, the Company issued $86.4 million of 7% Convertible Subordinated Notes due 2001 in an underwritten public offering for net proceeds of $83.6 million. The net proceeds of the offering were used to repay a portion of the borrowings under the bank credit facility.
In early 1994, the Company executed an agreement with Union Pacific Resources Corporation ("UPRC") whereby the Company gained the right to drill wells on UPRC's previously uncommitted acreage in the Wattenberg area. The transaction significantly increased the Company's inventory of undeveloped Wattenberg acreage. UPRC retained a royalty and the right to participate as a 50% working interest owner in each well, and received warrants to purchase two million shares of Company stock. On February 8, 1995, the exercise prices were reset to $21.60 per share and their expiration extended one year. One million of the warrants expire in February 1998 and the other million expire in February 1999. For financial reporting purposes, the warrants were valued at $3.5 million, which was recorded as an increase to oil and gas properties and capital in
excess of par value. In early 1995, the Company paid UPRC $400,000 for an extension of the time period to drill the commitment wells and released a portion of the outlying acreage committed to the venture.
In 1992, an institutional investor agreed to contribute $7 million to a partnership formed to monetize Section 29 tax credits to be realized from the Company's properties, mainly in the DJ Basin. The initial $3 million was contributed in 1992, an additional $3 million contributed during 1993 and $1 million received in March 1994. In June 1994, the arrangement was extended and an additional $1.8 million was received. In early 1995, a second investor was added and the limited partners committed to contribute an additional $5.0 million. As a result, this transaction is anticipated to increase cash flow and net income through 1996. A revenue increase of more than $.40 per Mcf is realized on production generated from qualified Section 29 properties in this partnership. The Company recognized $780,000, $3.8 million and $3.0 million, respectively, of this revenue during 1992, 1993 and 1994.
The Company maintains a program to divest marginal properties and assets which do not fit its long range plans. During 1993 and 1994, the Company received $5.5 million and $2.8 million, respectively, in proceeds from sales of properties. The 1993 proceeds included $4.0 million of cash receipts previously accrued for late 1992 sales. Subsequent to yearend 1994, the Company announced that it is considering the sale of its Wattenberg gas facilities and certain non-strategic assets.
The Company believes that its capital resources are adequate to meet the requirements of its business. However, future cash flows are subject to a number of variables including the level of production and oil and gas prices, and there can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or that increased capital expenditures will not be undertaken.
Inflation and Changes in Prices
While certain of its costs are affected by the general level of inflation, factors unique to the petroleum industry result in independent price fluctuations. Over the past five years, significant fluctuations have occurred in oil and gas prices. Although it is particularly difficult to estimate future prices of oil and gas, price fluctuations have had, and will continue to have, a material effect on the Company.
The following table indicates the average oil and gas prices received over the last five years and highlights the price fluctuations by quarter for 1993 and 1994. Average gas prices prior to 1994 exclude Mississippi gas production sold under a high price contract. During 1993, the Company renegotiated the gas contract and received a substantial payment. As of January 1994, the Company still receives a higher than market price for the Mississippi gas sales, however the price is significantly below the previously received average price of over $12.00 per Mcf. Average price computations exclude contract settlements and other nonrecurring items to provide comparability. Average prices per equivalent barrel indicate the composite impact of changes in oil and gas prices. Natural gas production is converted to oil equivalents at the rate of 6 Mcf per barrel.
In December 1994, the Company received an average of $14.87 per barrel and $1.63 per Mcf for its production.
ITEM 8.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Reference is made to the Index to Financial Statements on page 32 for financial statements and notes thereto. Quarterly financial data is presented on page 24 of this Form 10-K. Supplementary schedules have been omitted as not required or not applicable because the information required to be presented is included in the financial statements and related notes.
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES.
None.
Page
Report of Independent Public Accountants . . . . . . . . . . . . .32
Consolidated Balance Sheets as of December 31, 1993 and 1994 . . .33
Consolidated Statements of Operations for the years ended December 31, 1992, 1993 and 1994 . . . . . . . . . . . . . .34
Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 1992, 1993 and 1994 . . . .35
Consolidated Statements of Cash Flows for the years ended December 31, 1992, 1993 and 1994 . . . .36
Notes to Consolidated Financial Statements . . . . . . . . . . . .37
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of Snyder Oil Corporation:
We have audited the accompanying consolidated balance sheets of Snyder Oil Corporation (a Delaware corporation) and subsidiaries as of December 31, 1993 and 1994, and the related consolidated statements of operations, changes in stockholders' equity, and cash flows for each of the three years in the period ended December 31, 1994. 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 financial position of Snyder Oil Corporation and subsidiaries as of December 31, 1993 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
As explained in Note 2 to the financial statements, in 1994, the Company changed its method of accounting for its oil and gas properties from "full cost" to "successful efforts." All prior period financial statements presented have been restated.
ARTHUR ANDERSEN LLP
Fort Worth, Texas, March 3, 1995
SNYDER OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Snyder Oil Corporation (the "Company") is primarily engaged in the acquisition, production, development and exploration of domestic oil and gas properties. The Company is also involved in gas processing, transportation, gathering and marketing. The Company is engaged to a modest but growing extent in international acquisition, development and exploration and maintains a number of special purpose subsidiaries which are engaged in ancillary activities including gas transmission, water disposal and management of oil and gas assets on behalf of institutional investors. The Company, a Delaware corporation, is the successor to a company formed in 1978.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements include the accounts of Snyder Oil Corporation and its subsidiaries (collectively, the "Company"). Affiliates in which the Company owns more than 50% are fully consolidated, with the related minority interest being deducted from subsidiary earnings and stockholders' equity. The Company accounts for its interest in joint ventures and partnerships using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are consolidated with other operations.
In 1994, the Company changed from the full cost to the successful efforts method of accounting for its oil and gas properties, in order to more accurately reflect its results as it continues to expand its development and exploration efforts. Accordingly, 1992 and 1993 statements of operations and the 1993 balance sheet have been restated to conform to successful efforts. The cumulative effect was to reduce January 1, 1992, retained earnings by $9.5 million. For the 1992 and 1993 years previously reported, the effect of the accounting change restatement, was to reduce net income by $6.0 million ($.27 per share) and $6.1 million ($.26 per share), respectively. Under successful efforts, oil and gas leasehold costs are capitalized when incurred. Unproved properties are assessed periodically on a property-by-property basis and impairments in value are charged to expense. Exploratory expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs, including stratigraphic test wells, are initially capitalized, but charged to expense if and when the well is determined to be unsuccessful. Costs of productive wells, developmental dry holes and productive leases are capitalized and amortized on a unit-of- production basis over the life of the remaining proved reserves. Gas is converted to equivalent barrels at the rate of 6 Mcf to 1 barrel. Generally, amortization of capitalized costs is provided on a property-by-property basis.
Generally, the Company provides an impairment reserve for significant proved and unproved oil and gas property groups to the extent that net capitalized costs exceed the undiscounted future value. During 1992, 1993 and 1994, the Company provided impairment reserves of $3.4 million, $4.4 million and $5.8 million, respectively.
The Company's investment in its Australian affiliate is accounted for using the equity method, whereby the cash basis investment is increased for equity in earnings and decreased for dividends, if any were received. The affiliate's functional currency is the Australian dollar. The foreign currency translation adjustments reported in the balance sheet are the result of the translation of the Australian dollar balance sheet into United States dollars at yearend and the changes in the exchange rate subsequent to purchase.
To a limited extent, the Company enters into commodities contracts to hedge the price risk of a portion of its production. In 1994, the Company entered into certain gas sales arrangements in order to lock in the price differential between the Rocky Mountain and the NYMEX Henry Hub prices to reduce exposure to the Rocky Mountain spot prices. The contracts included 31,000 MMBtu per day, 20,000 MMBtu for a period of ten years and 11,000 MMBtu through July 1995. At December 31, 1994, the net present value of the contracts was estimated to be $4.9 million with no recorded carrying value.
All liquid investments with a maturity of three months or less are considered to be cash equivalents. General and administrative expenses are reduced by reimbursements for well operations, drilling, management of partnerships and services provided to unconsolidated affiliates. Reimbursements amounted to $14.3 million, $17.8 million and $25.4 million, respectively, in 1992, 1993 and 1994.
Certain amounts in the 1992 and 1993 financial statements have been reclassified to conform with the 1994 presentation.
(3) INDEBTEDNESS
The following indebtedness was outstanding on the respective dates:
The Company maintains a $500 million revolving credit facility. The facility is divided into a $400 million long-term portion and a $100 million short-term portion. The borrowing base available under the facility at December 31, 1994 was $250 million. The majority of the borrowings under the facility currently bear interest at LIBOR plus .75% with the remainder at prime, with an option to select CD plus .75%. The margin on LIBOR or CD will increase to 1% if the Company's consolidated senior debt becomes greater than 80% of its tangible net worth. During 1994, the average interest rate under the revolver was 5.5%. The Company pays certain fees based on the unused portion of the borrowing base. Covenants require maintenance of minimum working capital, limit the incurrence of debt and restrict dividends, stock repurchases, certain investments, other indebtedness and unrelated business activities. Such restricted payments are limited by a formula that includes underwriting proceeds, cash flow and other items. Based on such limitations, over $100 million was available for the payment of dividends and other restricted payments as of December 31, 1994.
In May 1994, the Company issued $86.3 million of 7% convertible subordinated notes due May 15, 2001. The net proceeds were $83.4 million. The notes are convertible into common stock at $23.16 per share, and are redeemable at the option of the Company on or after May 15, 1997, initially at 103.51% of principal, and at prices declining to 100% at May 15, 2000, plus accrued interest. At December 31, 1994, the fair market value of the notes, based on their closing price on the New York Stock Exchange, was $75.9 million.
In November 1994, the Company entered into an agreement with a bank whereby the bank purchased the recently constructed West Wattenberg Gas Plant from the Company for $21 million and leased it back. The lease has a term of seven years and includes an option to repurchase the plant at the end of the lease for $4.2 million. As a capital lease, the asset and related debt are recorded on the balance sheet of the Company. At December 31, 1994, the Company's future minimum rentals under the lease were $24.0 million. At December 31, 1994, the present value of net minimum capital lease payments recorded as a liability in the accompanying balance sheet was $20.6 million, of which $1.7 million was classified as current.
In 1993, the Company retired $25 million of subordinated notes and the related cumulative participating rights. The portion of the payment in excess of principal and accrued interest was expensed as an extraordinary item for $3.0 million.
Scheduled maturities of indebtedness for the next five years are $1.7 million in 1995, $2.1 million in 1996, $2.2 million in 1997, $218.5 million in 1998 and $2.5 million in 1999. The long-term portion of the revolving credit facility is scheduled to expire in 1998; however, it is management's policy to renew the facility and extend the maturity on a regular basis.
Cash payments for interest were $5.4 million, $9.2 million and $9.9 million, respectively, for 1992, 1993 and 1994.
(4) INVESTMENTS
The Company has investments in foreign and domestic energy companies and long term notes receivable, which at December 31, 1993 and 1994, had a book cost of $29.4 million and $46.5 million, respectively. The corresponding fair market values were $54.2 million and $48.2 million at December 31, 1993 and 1994, respectively. In 1994, the Company adopted SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." Per the pronouncement, investments carried on the cost basis must be adjusted to their market value with a corresponding increase or decrease to stockholders' equity. The pronouncement does not apply to investments accounted for by the equity method.
In May 1993, the Company acquired 42.8% of the outstanding shares of Command Petroleum Limited ("Command"), an Australian exploration and production company, for $18.2 million. The investment is accounted for by the equity method. The Sydney based company is listed on the Australian Stock Exchange, and holds interests in various international exploration and production permits and licenses as well as a 45.4% interest in a publicly traded Netherlands exploration and production company whose assets are located primarily in the North Sea. In January 1994, Command completed an offering of 43 million of its common shares, and in February 1994 paid $1.1 million in cash and issued 2.5 million of its common shares in return for an incremental interest in the Netherlands company. Additionally in 1994, 51.9 million of stock options were exercised and 4.7 million partly paid shares were issued. As a result of these transactions, the Company's ownership in Command was reduced to 29.0% and a $3.1 million gain was recognized. The market value of the Company's investment in Command based on Command's closing price at December 31, 1994 was $30.0 million, compared to a cost basis of $25.1 million.
In early 1993, the Company formed the Permtex joint venture to develop proven oil fields in the Volga-Urals Basin of Russia. To finance its portion of planned development expenditures, the Company sold a portion of its investment in the project to three industry participants. As a result, its equity basis investment was reduced from 50% to 20.6% and a $3.5 million net gain was recorded. The Russian investment had a cost and fair value at December 31, 1994 of $3.1 million.
The Company has investments in securities of publicly traded domestic energy companies, not accounted for by the equity method, with a total cost at December 31, 1993 and 1994 of $9.7 million and $15.4 million, respectively. The market value of these securities at December 31, 1993 and 1994 approximated $13.3 million and $12.2 million, respectively. Accordingly, at December 31, 1994, investments were decreased by $3.2 million, stockholders' equity was decreased by $2.1 million and deferred taxes payable were decreased by $1.1 million as required by SFAS No. 115.
The Company holds $2.9 million in long term notes receivable due from privately held corporations. All notes are secured by certain assets, including stock and oil and gas properties. At December 31, 1993 and 1994, the fair value of the notes receivable, based on existing market conditions and the anticipated future net cash flow related to the notes, approximated their book value.
(5) OIL AND GAS PROPERTIES AND GAS FACILITIES
The cost of oil and gas properties at December 31, 1993 and 1994 includes $6.3 million and $23.7 million, respectively, of unevaluated leasehold. Such properties are held for exploration, development or resale and are excluded from amortization. The following table sets forth costs incurred related to oil and gas properties and gas processing and transportation facilities:
Development expenditures for the year ended December 31, 1994, were concentrated primarily in the DJ Basin of Colorado where expenditures totalled $90.3 million. A total of 360 wells were placed on production there in 1994, 90 were recompleted and 63 more were in progress at December 31. In the Green River Basin of southern Wyoming, 34 wells were placed on production with eight in progress at yearend. In the horizontal drilling program in the Giddings Field of southeast Texas, 23 wells were placed on production in 1994, with nine in progress at yearend and one well abandoned. In the Piceance Basin of western Colorado, 20 wells were placed on production, with five wells in progress at yearend and one well abandoned. The Uinta Basin development program in northeast Utah is still in its early stages with two wells placed on production and seven wells in progress at yearend.
During 1994, the Company expended $70.3 million for domestic acquisitions, of which $44.7 million was for proven properties and $25.6 million for unproven acreage. The most notable production acquisitions were $13.9 million for an incremental interest in the Barrel Springs unit in Wyoming, $6.6 million for properties in the Piceance Basin, $5.0 million in the DJ Basin, $4.3 million in the Giddings area of southeast Texas and $6.6 million for a controlling interest in Del Mar Petroleum, Inc., a company that owns and operates properties in the Gulf of Mexico. The most substantial acreage purchase involved a $9.7 million acquisition in northeast Louisiana, of which $3.0 million related to production and $6.7 million was for 330,000 net mineral acres which are classified as unproven. Acquisitions are accounted for utilizing the purchase method. The pro forma effect of the acquisitions was not material to the Company's results of operations.
The Company's gas facilities expansion continued with $41.5 million expended during 1994, primarily on facilities in the DJ Basin. Construction of a new gas processing plant on the west end of the Wattenberg Field with a cost of $21.3 million was completed in the fourth quarter. Financing was obtained for the full project cost under a seven-year capital lease with a fixed 8.2% interest rate. A total of $8.7 million was expended to increase the Company's gathering systems in the DJ Basin to add pipelines, feeder lines, an additional compressor and new well connections for the continuing drilling activity in the area. At the Roggen plant, $2.9 million was expended to add a new de-ethanizer station, improve metering and boost compression, among other projects. Another $8.6 million in expenditures were for system expansions in the Piceance Basin, Nebraska and the Washakie Basin.
(6) STOCKHOLDERS' EQUITY
A total of 75 million common shares, $.01 par value, are authorized of which 30.2 million were issued at December 31, 1994. In 1993, the Company issued 386,000 shares, with 309,000 shares issued primarily for the exercise of stock options by employees and 77,000 shares issued on conversion of 14,000 preferred shares. In 1994, the Company issued 6,949,000 shares, with 414,000 shares issued primarily for the exercise of stock options by employees (for which 122,000 shares were received as consideration in lieu of cash and are held in treasury) and 6,535,000 shares issued on conversion of all remaining shares of the 8% preferred. In 1993, the Company paid first and second quarter dividends at the rate of $.05 per share and increased the rate to $.06 per share in the third quarter. In the third quarter of 1994, the dividend rate increased to $.065 per share.
A total of 10 million preferred shares, $.01 par value, are authorized. In December 1991, 1.2 million shares of 8% convertible exchangeable preferred stock were sold through an underwriting. The net proceeds were $57.4 million. In 1993, 14,000 of the preferred shares were converted into 77,000 common shares. Effective December 31, 1994, the remaining 8% convertible preferred shares were converted into 6,535,000 common shares.
In April 1993, 4.1 million depositary shares (each representing a one quarter interest in one share of $100 liquidation value stock) of 6% preferred stock were sold through an underwriting. The net proceeds were $99.3 million. The stock is convertible into common stock at $21.00 per share and is exchangeable at the option of the Company for 6% convertible subordinated debentures on any dividend payment date. The 6% convertible preferred stock is redeemable at the option of the Company on or after March 31, 1996. The liquidation preference is $25.00 per depositary share, plus accrued and unpaid dividends. The Company paid $9.1 million and $10.8 million, respectively, in preferred dividends during 1993 and 1994.
The Company maintains a stock option plan for employees providing for the issuance of options at prices not less than fair market value. Options to acquire up to three million shares of common stock may be outstanding at any given time. The specific terms of grant and exercise are determinable by a committee of independent members of the Board of Directors. The majority of currently outstanding options vest over a three-year period (30%, 60%, 100%) and expire five to seven years from date of grant.
In 1990, the shareholders adopted a stock grant and option plan (the "Directors' Plan") for non-employee Directors of the Company. The Directors' Plan provides for each non-employee director to receive 500 common shares quarterly in payment of their annual retainer. It also provides for 2,500 options to be granted annually to each non-employee Director. The options vest over a three-year period (30%, 60%, 100%) and expire five years from date of grant.
At December 31, 1994, a total of 1.5 million options were outstanding at exercise prices of $4.53 to $20.38 per share. At December 31, 1994, a total of 533,000 of such options were vested having exercise prices of $4.53 to $19.25 per share. During 1993, 309,000 options were exercised at prices of $4.53 to $9.13 per share, and 23,000 were forfeited. During 1994, 414,000 options were exercised at prices of $4.53 to $13.00 per share, and 2,000 were forfeited.
Earnings per share are computed by dividing net income, less dividends on preferred stock, by average common shares outstanding. Net income available to common for the three years ended December 31, 1994, was $9.8 million, $10.4 million and $1.6 million, respectively. Differences between primary and fully diluted earnings per share were insignificant for all periods presented.
(7) FEDERAL INCOME TAXES
The Company adopted FASB Statement No. 109, "Accounting for Income Taxes," effective January 1, 1992. At December 31, 1994, the Company had no liability for foreign taxes. A reconciliation of the United States federal statutory rate to the Company's effective income tax rate follows:
For book purposes the components of the net deferred asset and liability at December 31, 1993 and 1994, respectively, were:
For tax purposes, the Company had net operating loss carryforwards of $162.6 million at December 31, 1994. These carryforwards expire between 1997 and 2009. At December 31, 1994, the Company had alternative minimum tax credit carryforwards of $1.4 million and depletion carryforwards of $1.5 million, both of which are available indefinitely. Current income taxes shown in the financial statements reflect estimates of alternative minimum taxes. Cash payments during 1992, 1993 and 1994 were $1.0 million, $75,000 and $10,000, respectively.
(8) MAJOR CUSTOMERS
In 1992, 1993 and 1994, Amoco Production Company accounted for 27%, 12% and 11%, respectively, of revenues. Management believes that the loss of any individual purchaser would not have a material adverse impact on the financial position or results of operations of the Company.
(9) DEFERRED CREDITS
In 1992, an institutional investor agreed to contribute $7 million to a partnership formed to monetize Section 29 tax credits to be realized from the Company's properties, mainly in the DJ Basin. The initial $3 million was contributed in 1992, an additional $3 million contributed during 1993 and $1 million received in March 1994. In June 1994, the arrangement was extended and an additional $1.8 million was received. In early 1995, a second investor was added and the limited partners committed to contribute an additional $5.0 million. As a result, this transaction is anticipated to increase cash flow and net income through 1996. A revenue increase of more than $.40 per Mcf is realized on production generated from qualified Section 29 properties in this partnership. The Company recognized $780,000, $3.8 million and $3.0 million of this revenue during 1992, 1993 and 1994, respectively.
(10) COMMITMENTS AND CONTINGENCIES
The Company rents office space and gas compressors at various locations under non-cancelable operating leases. Minimum future payments under such leases approximate $2.4 million for 1995, $2.5 million for 1996 and 1997, $2.4 million for 1998, and $2.0 million for 1999.
In 1993, the Company received a $5.3 million settlement on a gas contract dispute. Of the proceeds, $3.5 million was reflected as other income in 1993, with the remaining $1.8 million reflected as a reserve for possible contingencies. In 1994, $232,000 was paid and the remaining $1.6 million reported as income. In April 1993, the Company was granted a $2.7 million judgment in litigation involving the allocation of proceeds from a pipeline dispute. The judgment has been appealed. The Company is a party to various other lawsuits incidental to its business, none of which are anticipated to have a material adverse impact on its financial position or results of operations. The financial statements reflect favorable legal judgments only upon receipt of cash, final judicial determination or execution of a settlement agreement.
(11) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION:
Independent petroleum consultants directly evaluated 74%, 62%, and 58% of proved reserves at December 31, 1992, 1993 and 1994, respectively, and performed a detailed review of properties which comprised in excess of 80% of proved reserve value. All reserve estimates are based on economic and operating conditions at that time. Future net cash flows as of each year-end were computed by applying then current prices to estimated future production less estimated future expenditures (based on current costs) to be incurred in producing and developing the reserves. All reserves are located onshore in the United States and in the waters of the Gulf of Mexico.
The Company's interests in the Russian joint venture (Permtex) and its Australian affiliate (Command) are accounted for under the equity method. At December 31, 1994, the Company's equity in Permtex and Command proved reserves was 8,038 MBOE and 5,931 MBOE, respectively.
PART IV
ITEM 14.







ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) 1. Reference is made to Item 8 on page 34. 2. Schedules otherwise required by Item 8 have been omitted as not required or not applicable.
3. Exhibits
4.1.1 - Certificate of Incorporation of Registrant - incorporated by reference from Exhibit 3.1 to the Registrant's Registration Statement on Form S-4 (Registration No. 33-33455).
4.1.2 - Certificate of Amendment to Certificate of Incorporation of Registrant filed February 9, 1990 - incorporated by reference from Exhibit 3.1.1 to the Registrant's Registration Statement on Form S-4 (Registration No. 33-33455).
4.1.3 - Certificate of Amendment to Certificate of Incorporation of Registrant filed May 22, 1991 - incorporated by reference from Exhibit 3.1.2 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-43106).
4.1.4 - Certificate of Amendment to Certificate of Incorporation of Registrant filed May 24, 1993 - incorporated by reference from Exhibit 3.1.5 to the Registrant's Form 10-Q for the quarter ended June 30, 1993 (File No. 1-10509)
4.1.5 - Indenture dated as of May 1, 1994 between the Registrant and Texas Commerce Bank National Association relating to Registrant's 7% Convertible Subordinated Notes due 2001.*
4.1.6 - Certificate of Designations of the Registrant's $6.00 Convertible Exchangeable Preferred Stock - incorporated by reference from Exhibit 3.1.5 to the Registrant's Form 10-Q for the quarter ended June 30, 1993 (File No. 1-10509).
10.1 - Snyder Oil Corporation 1990 Stock Option Plan for Non-Employee Directors - incorporated by reference from Exhibit 10.4 to the Registrant's Registration Statement on Form S-4 (Registration No. 33-33455).
10.1.1 - Amendment dated May 20, 1992 to the Registrant's 1990 Stock Plan for Non-Employee Directors - incorporated by reference to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 1993 (File No. 1- 10509).
10.2 - Registrant's Restated 1989 Stock Option Plan - incorporated by reference to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 1992 (File No. 1-10509).
10.3 - Regstrant's Deferred Compensation Plan for Select Employees, adopted effective June 1, 1994.*
10.4 - Registrant's Profit Sharing & Savings Plan and Trust as amended and restated effective October 1, 1993 - incorporated by reference to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 1993 (File No. 1-10509).
10.5 - Form of Indemnification Agreement - incorporated by reference from Exhibit 10.15 to the Registrant's Registration Statement on Form S-4 (Registration No. 33-33455).
10.6 - Form of Change in Control Protection Agreement - incorporated by reference from Exhibit 10.11 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-43106).
10.7 - Long-term Retention and Incentive Plan and Agreement between the Registrant and Charles A. Brown - incorporated by reference to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 1993 (File No. 1-10509).
10.8 - Agreement dated as of April 30, 1993 between the Registrant and Edward T. Story - incorporated by reference from Exhibit 10.8 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1993 (File No. 1-10509).
10.9 - Purchase and Sale Agreement dated December 11, 1992 between Atlantic Richfield Company and Registrant - incorporated by reference to Report on 8-K dated December 11, 1992 (File No. 1-10509).
10.10 - Warrant dated February 8, 1994 issued by Registrant to Union Pacific Resource Company - incorporated by reference from Exhibit 10.10 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1993 (File No. 1-10509).
10.11 - Fifth Restated Credit Agreement dated as of June 30, 1994 among the Registrant and the banks party thereto - incorporated by reference from Exhibit 10.11 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 1994 (File No. 1-10509).
10.12 - Master Equipment Lease Agreement dated November 3, 1994 between Registrant and NationsBank Leasing Corporation ("NBL"), together with Equipment Lease Schedule No. 1 dated November 3, 1994 between Registrant and NBL and Facility Agreement dated November 3, 1994 between Registrant and NBL.*
11.1 - Computation of Per Share Earnings.*
12 - Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.*
22.1 - Subsidiaries of the Registrant - incorporated by reference from Exhibit 22.1 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1991 (File No. 1-10509).
23.1 - Consent of Arthur Andersen LLP.*
23.2 - Consent of Netherland, Sewell & Associates, Inc.*
27 - Financial Data Schedule.*
99.1 - Report of Netherland, Sewell & Associates, Inc. dated February 10, 1994 relating to certain of the Registrant's property interests.*
99.2 - Report of Netherland, Sewell & Associates, Inc. dated February 11, 1994 relating to their audit of reserve estimates.*
(b) No reports on Form 8-K in the fourth quarter of 1994
* Filed herewith.
SIGNATURE
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.
/s/ John C. Snyder March 14, 1995 - --------------------- John C. Snyder Director and Chairman of the Board (Principal Executive Officer)
/s/ Thomas J. Edelman March 14, 1995 - --------------------- Thomas J. Edelman Director and President (Principal Financial Officer)
/s/ John A. Fanning March 14, 1995 - --------------------- John A. Fanning Director and Executive Vice President
/s/ Roger W. Brittain March 14, 1995 - --------------------- Roger W. Brittain Director
/s/ John A. Hill March 14, 1995 - --------------------- John A. Hill Director
/s/ William J. Johnson March 14, 1995 - --------------------- William J. Johnson Director
/s/ B. J. Kellenberger March 14, 1995 - ---------------------- B. J. Kellenberger Director
/s/ John H. Lichtblau March 14, 1995 - ---------------------- John H. Lichtblau Director
/s/ James E. McCormick March 14, 1995 - ---------------------- James E. McCormick Director
/s/ Alfred M. Micallef March 14, 1995 - ---------------------- Alfred M. Micallef Director
/s/ James H. Shonsey March 14, 1995 - --------------------- James H. Shonsey Vice President - Finance (Principal Accounting Officer)