Annual Report (Form 10-K), fiscal year 1993

ITEM 1. BUSINESS
General
Snyder Oil Corporation (the "Company") is engaged in the development and acquisition of oil and gas properties primarily in the Rocky Mountain region of the United States. In addition, the Company gathers, transports, processes and markets natural gas generally in proximity to its principal producing properties. In 1992, an international exploration and development program was initiated. At December 31, 1993, the Company's net proved reserves totalled 103.6 million barrels of oil equivalents ("BOE"), having a pretax present value at constant prices of $390.4 million. The Company's properties are located in 15 states and the Gulf of Mexico and include 5,122 gross (2,187 net) producing wells and nine gas transportation and processing facilities. At December 31, 1993, the Company held undeveloped acreage totalling 539,000 gross (326,000 net) domestic acres and 4.3 million gross (3.3 million net) international acres. Approximately 90% of the present value of proved reserves is concentrated in five major producing areas located in Colorado, Wyoming and Texas. The Company operates more than 2,100 wells which account for more than 90% of its developed reserves. Headquartered in Fort Worth, Texas, the Company maintains administrative offices in Denver and New York and has eight field offices in Colorado, Wyoming, Texas, New Mexico and Nebraska. At yearend 1993, the Company had 327 employees.
Between 1983 and 1990, the Company grew rapidly through a series of acquisitions. The strategy was to accumulate a critical mass of assets during a period of industry distress. This phase of the Company's growth culminated in 1990 with the acquisition of a publicly traded limited partnership formed by the Company in 1983. This transaction added 35.9 million BOE of proved reserves. Since then, the Company has pursued a balanced strategy of development drilling and acquisitions, focusing on operating efficiency and enhanced profitability through the concentration of assets in selected geographic areas or "hubs." During this eleven-year period, revenues rose from $2.5 million to $229.9 million, net income increased from $.3 million to $25.7 million and cash flow grew from $1.1 million to $84.1 million.
Development drilling in the Rockies is currently the primary emphasis of the Company's growth strategy. In its largest area of operations, the Wattenberg Field in the Denver-Julesburg Basin ("DJ Basin") of Colorado, the Company drilled over 300 wells in 1993. That brought the total number of producing wells there to over 1,400. Aggressive cost cutting, the creative application of technology and the advantages of expanding gas facilities in the area have, together with acquisitions, leasing and a joint venture with Union Pacific Resources Company ("UPRC"), brought the inventory of potential drilling locations in the Basin to over 6,000. The Company expects that more than half of these locations will ultimately prove attractive to develop. The Company expects to drill approximately 500 Wattenberg wells in 1994 and to maintain that pace for the next several years.
The Company has embarked on a program to apply the experience gained in Wattenberg to other large scale gas development projects in the Rockies. By the end of 1993, the Company had established two such projects. In the East Washakie Project, which builds on existing gas properties and facilities in southern Wyoming, the Company holds approximately 1,200 potential drilling locations. The Western Slope Project covers portions of the Piceance Basin of Colorado and the Uinta Basin in northeastern Utah where the Company controls approximately 1,000 drilling locations. Each of these projects are expected to become significant development drilling projects over the next few years.
During 1993, the Company made substantial progress in building its international exploration and development effort. The international effort is expected to eventually provide significant growth potential for the Company. The Company's Russian venture received government approval and is expected to commence operations in the first half of 1994. A production sharing agreement covering 2.8 million gross acres was signed with the government of Mongolia and the seismic program on the Tunisian concession was completed. The Company also acquired a significant interest in a publicly traded Australian company whose international exploration experience should complement the Company's development and acquisition expertise.
During 1994, the Company intends to continue to emphasize development drilling. The drilling will continue to be focused in the DJ Basin along with increasing activity in the East Washakie and the Western Slope projects. It is expected that the continuing aggressive use of technology and cost saving techniques along with the capture of downstream margins via the Company's gas facilities will steadily improve the economics of existing properties and open new areas of opportunities. Acquisitions will continue to be used to strengthen the existing asset base and secure footholds in new areas. Finally, the effort to bring a variety of international projects to fruition will continue.
Development
General. Since 1990, development drilling has become the primary focus of the Company's growth strategy. The Company believes that its existing properties have extensive development drilling and enhancement potential, primarily in the DJ Basin of Colorado, the Washakie Basin in southern Wyoming, the Piceance and Uinta Basins in western Colorado and Utah and in the Giddings Field in southern Texas. The Company designs its major drilling programs to assure low risk, synergies with its gas management operations and the potential for continuous cost improvement. Flexibility is crucial as changing product prices and drilling results affect economics. The Company expects to continue to drill approximately 500 wells per year in the Wattenberg Field, where the size of its operations enables it to continue to refine the application of new drilling, completion and operating techniques, and to apply the experience gained there to establish other large scale development projects in the Rockies.
Assuming no material changes in product prices and capital availability, the Company estimates that it will expend from $150 to $200 million per year on development activities over the next three to five years. Development expenditures totalled $53.7 million in 1992 and $90.2 million in 1993, primarily in the Wattenberg Field.
DJ Basin
Wattenberg Field. The Wattenberg Field is the Company's largest base of operations, representing over 60% of total proved reserves. Between 1991 and 1993, the Company drilled a total of 667 wells in Wattenberg, of which 323 were drilled during 1993. At yearend, the Company had interests in more than 1,400 producing wells, of which over 1,100 were operated. Through complementary acquisitions, an extensive leasing program and a major joint venture with UPRC, the inventory of potential Wattenberg drilling locations currently exceeds 6,000 sites. The Company expects that over half of these sites will ultimately prove attractive to develop. The Company expects to drill approximately 500 wells per year in the Wattenberg Field for the foreseeable future.
At yearend 1993, the net proved reserves attributed to the Wattenberg properties were 16.9 million barrels of oil and 229.9 Bcf of gas. The reserves were attributable to 1,437 producing wells, 51 wells in progress, 1,102 proved undeveloped locations and approximately 387 proved behind pipe zones. The Company expects proved reserves to be assigned to other locations as drilling progresses.
The Company acquired its first properties in Wattenberg during 1986. In 1990, it substantially increased its acreage position by acquiring rights to the Codell and Niobrara formations underlying 32,985 net acres from Amoco Production Company ("Amoco") for $14.4 million. Several farm-ins from Amoco in 1992, financed primarily through a transfer of Section 29 tax credits, resulted in earning additional Codell/Niobrara rights as well as rights to the Sussex, J- Sand and Dakota formations in a number of locations.
During 1993, a series of purchases added nearly 9 million BOE at a net cost of under $3.50 per barrel as well as several pipeline and processing facilities that complement existing facilities. In the largest of these acquisitions, the Company paid $19.7 million and, after an exchange of interests with a third party, acquired an approximate 80% working interest in 153 producing wells and 284 undeveloped locations having total proved reserves estimated to exceed 7 million BOE. A portion of the value of the transaction lay in the large volume of undedicated gas located in close proximity to the Company's gas lines.
In early 1994, the Company finalized an agreement with UPRC under which the Company has the right for up to six years to drill wells on locations of its choosing on UPRC's previously uncommitted undeveloped acreage throughout the Wattenberg area. This transaction substantially increased Wattenberg's undeveloped acreage inventory. Many of the locations have the potential for improved economics through completion in one or more of the Shannon, Sussex, J-Sand or Dakota formations, as well as the Codell and Niobrara. During the venture's initial three-year term, the Company is required to drill a minimum of 120, 120 and 60 wells per year. After the initial period, the Company can, at its option, extend the venture annually for up to three additional years by drilling at least 150 wells per year. There is no limit on the maximum number of wells that can be drilled, and wells in excess of the required minimum in any year will 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 each well that is drilled on UPRC's mineral acreage under the venture, UPRC retains a 15% mineral owner royalty and has the option either to receive an additional 10% royalty interest after pay-out or to participate in the well as a 50% working interest owner. On leasehold acreage, UPRC does not have the right to participate in the well but will retain a royalty interest that will result in a total royalty burden of 25%. As compensation for committing its acreage position to the Company, UPRC was granted warrants to purchase two million shares of the Company's common stock at a premium to market value. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Development, Acquisition and Exploration."
Drilling. The Company began drilling operations in Wattenberg in early 1991. From 1991 to December 1993, the Company expended $149.7 million to drill 667 wells, of which 323 were drilled in 1993. At yearend, 609 of these wells were producing, 51 were in various stages of drilling and completion and seven were dry holes.
The size of the Wattenberg drilling program has resulted in numerous advantages. The Company acts as operator on all its development sites in the Wattenberg Field and much of the acreage is held by production. As a result, the Company has significant operational control over the timing of the development program. The actual drilling locations and schedule are selected to minimize costs associated with rig moves, surface facilities, location preparation and gathering system and pipeline connections and to evaluate and quantify incremental reserve potential across the acreage position.
The Company's success in continuing to reduce its costs of drilling and operations, as well as applying new technology, will be important to the full development of its undeveloped acreage in Wattenberg. The Company has selected procedures for drilling and completing wells that it believes maximize recoverable reserves and economics. The Company has also been able to reduce its costs of drilling, completing and operating wells significantly by negotiating favorable prices with suppliers of drilling and completion services because of the size of its drilling program. These cost reductions allow the Company to earn an attractive rate of return even on lower reserve wells. The reductions have been achieved by several methods. One of the most significant is the formation of alliances with selected vendors who work with Company personnel to improve coordination and reduce both parties' costs. The resultant reductions are credited wholly or in large part to the Company while vendors' margins are maintained or increased.
In addition to cost reduction, the Company seeks to employ new technology or to creatively apply existing technology to reduce costs or to produce reserves that would otherwise remain unrecovered. One example is the drilling of four or more wells from a single drilling pad in residential areas, under reservoirs and on inaccessible acreage.
The Codell formation, which is 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 have a high degree of predictability due to uniform deposition and gradual transition from high to low gas/oil ratio areas. The Company generally 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. However, the declining production of individual wells is expected to be offset by continuing development drilling.
During 1992 and 1993, the Company expanded 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 proportionately with porosity and thickness. The Dakota formation lies approximately 150 feet below the J. It is a low permeability sand occasionally naturally fractured with less predictable commercial accumulations and varied performance results. The Sussex formation is at average depths of 4,500 feet. The Sussex sands were deposited as 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 in the Wattenberg Field is relatively low risk. In addition, the Company has compiled a comprehensive geologic and production database for approximately 12,000 wells within a 4,350 square mile area between Denver and the Wyoming border and has had considerable success in predicting variations in thickness, porosity, gas/oil ratios and productivity. Of the 667 wells drilled between 1991 and 1993, only seven have been dry holes. Dry holes cost an average of only $65,000 per well. The average net cost of a completed well approximated $193,000 during 1993 with only 30 days usually elapsing between spud date and initial production.
The Company plans to develop the Wattenberg acreage within seasonal agriculture constraints which has historically reduced access to farmland between April and September. However, the expanded inventory includes a number of non-farm drillsites, which provides greater flexibility for summer drilling.
Marketing and Gas Management. A portion of the gas produced in the Wattenberg Field is gathered, processed or both by third parties under long-term contractual dedications. However, the Company's gas facilities, including a processing plant and over 600 miles of gathering systems have reduced costs and afforded flexibility. These facilities, as well as gas marketing expertise, are expected to provide greater advantages in the future as the Company capitalizes on the cost savings and flexibility afforded by the recent expansion of its gathering and processing facilities and assumes marketing responsibility for gas previously committed to others.
The gas produced from the majority of the new Wattenberg wells drilled on acreage acquired from Amoco is dedicated for the life of the lease to at Amoco's Wattenberg gas processing plant. If Amoco were to release the Company from supplying gas to its plant for any reason, including a shut-down of the plant, such release would have an short-term adverse impact on the Company. The Company has expanded its processing facilities in Wattenberg in order to process Company and third party gas that is not dedicated to Amoco. The Company intends to continue to expand its facilities during 1994 to handle additional gas developed though continued drilling activity. These facilities will enable the Company to partially mitigate the effects of frequent shut-downs at the Amoco plant. See "Gas Management - Colorado Facilities."
In 1993, the Company extended its gathering system to collect gas from the Company and third parties, in order to control or reduce gathering costs and avoid curtailments in production caused by high line pressure on existing gathering systems. This expansion, called the Enterprise system, complements the processing and other gathering facilities in the area. While future gathering rates on the systems owned by others are expected to rise, the majority of the Company's gas will be gathered on its own gathering system. To the extent that a portion of the Company's gas remains on the KN Energy, Inc. ("KN") Wattenberg gathering system, the largest gathering system in the area, the applicable gathering rate is covered by an agreement between Amoco and KN which provides some protection from future rate increases. See "Gas Management - Colorado Facilities."
Through yearend, Amoco had been responsible for marketing all residue gas and liquids attributable to the Company's gas processed through its Wattenberg plant. Historically, this arrangement has provided for average prices in excess of spot due to participation in certain fixed price contracts, many of which are expected to expire over the next two years. Under the contract with Amoco, the Company elected to market substantially all its gas and liquid products processed through the Wattenberg plant effective January 1, 1994. The Company believes that it can obtain pricing comparable to that which would have been obtainable through Amoco. Oil is sold at the average of the posted prices of Amoco, Total and Conoco in northeast Colorado.
Cheyenne. During 1993, 29 wells were placed on stream in 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 54 successful wells and six 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 61 wells in this area that produce from the Niobrara formation and plans to drill approximately 20 additional wells during 1994.
East Washakie
During 1993, the Company initiated a major project to apply the cost-cutting and improved drilling and completion techniques learned in Wattenberg to develop fluvial Mesaverde sands in the eastern Washakie Basin. An eleven well pilot project was completed in 1993 to validate reduced cost levels and test drilling and completion techniques. A second drilling program is being initiated in March 1994. After final evaluation of the drilling, the Company may initiate a large scale drilling program in this area upon completion of a required environmental impact statement. The environmental impact statement was filed in October 1993, and completion is expected in the second half of 1994. Depending on the timing of environmental clearance and continued evaluation of drilling results, the Company expects to drill up to 60 wells in East Washakie during 1994.
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. See "Properties - Significant Properties" and "Gas Management - Wyoming Properties." The Company currently operates 128 wells in this area and has approximately 1,200 potential drilling locations, 98 of which were classified as proven at yearend 1993. More than half of the potential locations could ultimately prove attractive to develop. The Company currently holds interests in 95,000 gross (76,000 net) undeveloped acres in the Basin. This includes 36,000 gross (32,000 net) undeveloped acres added during 1993.
Western Slope
During 1993, the Company established a sizable position in the Piceance Basin on the Western Slope of Colorado and in the Uinta Basin in northeastern Utah. The Company formed the 53,000 acre Hunter Mesa Unit in the southeast corner of the Piceance Basin. Through purchases and farmouts, the Company obtained a majority interest and acts as unit operator. Immediately adjacent to the Hunter Mesa Unit, a 100% working interest was purchased in the 26,000 acre Divide Creek Unit for $6.2 million. The acquisition of this Unit, which has six wells producing from the Mesaverde and Cameo Coal formations, added 17.6 Bcf of proved gas reserves as well as an established operating base and access to gas transportation. Near yearend, the Company also purchased interests in 122 producing wells, 29 non-producing wells and 69 proved undeveloped locations. In total, this purchase included 55,000 net acres in various fields in the Piceance and Uinta Basins.
Through these purchases, farmouts and a leasing program, the Company currently holds over 1,000 potential drilling locations, of which 40% could ultimately prove be attractive to develop. Of these locations, 101 were classified as proven at yearend 1993. The development of the Upper Mesaverde sands in the Piceance Basin began with the spudding of the initial test well near the end of 1993. The development will continue with a 10 well test program during 1994 to validate cost reductions and improved recovery techniques. If successful, the Company may drill up to 30 wells in 1994 and approximately 100 wells per year thereafter. A key issue in the Piceance Basin is the ability to profitably transport production to market. The Company is exploring options for gathering and transporting future gas production, including the possibility of constructing Company owned facilities.
Other Development
At the end of 1992, the Company acquired interests in four large producing fields in central Wyoming from a major oil company at a cost of $56.1 million. Two of the fields, the Hamilton Dome and Riverton Dome Fields, are operated by the Company. During 1993, the Company evaluated opportunities in the fields and instituted programs to enhance production in the latter part of the year. In the Hamilton Dome Field, improvement of the water injection system and completion of two new wells increased daily production 8% above the levels projected at the time of the acquisition. A third well should be completed in the second quarter of 1994. In the Riverton Dome Field, workovers and recompletions increased daily production over 10% above the levels projected at the time of the acquisition. Additional workovers and development drilling are scheduled for both fields during 1994. The Company is attempting to work with the major oil companies that operate the other two fields purchased, both of which are producing slightly below acquisition projections.
The Company operates the Adair waterflood property in Gaines County, Texas, which it purchased in September 1991. Initial development of the Adair Unit in 1992 cost approximately $1.7 million net to the Company. Based on production response from the initial phase of development, the Company spent an additional $.9 million in 1993 to conduct a pilot program which reduced well spacing on a portion of the Unit. This program increased the unit production from 150 barrels per day to 260 barrels per day. The Company plans to spend an additional $1.1 million to implement an infill development program throughout the Unit. Once fully developed, the Adair Unit is expected to contain 52 wells operated by the Company.
In the Giddings Field in Southeast Texas, the Company has undertaken a horizontal drilling program to further exploit exising properties in the area. During 1993, the Company spent $2.2 million to re-enter or drill 10 wells, of which nine were completed and one abandoned. The Company is encouraged by the results to date and plans to increase its expenditures in the field during 1994. At yearend, 25 locations were classified as having proved undeveloped reserves.
Acquisition Program
The Company believes that acquisitions continue to be an attractive method of increasing its reserve base and cash flow. In its acquisition efforts, the Company plans to focus on purchasing properties that strengthen its strategic position and complement its large-scale gas development projects in the Rockies, as well as provide opportunities to establish meaningful positions in new areas. From 1983 through 1993 the Company, on behalf of itself, its affiliates and other investors, purchased oil and gas properties and related assets with an aggregate cost of nearly $650 million. The Company actively seeks to acquire incremental interests in existing properties, acreage with development potential, gas gathering, transportation and processing facilities and related assets, particularly in proximity to existing properties. Purchases of incremental interests or adjacent properties are generally small in size but in aggregate represent a sizeable opportunity that is relatively easy to pursue.
Due to its rate of return requirements and the high cost of pursuing potential acquisitions, the Company generally prefers negotiated transactions to auctions. Complex deals involving legal, financial or operational difficulties have frequently permitted purchase of assets at favorable prices. Past acquisitions of corporations laid the groundwork for the Wattenberg hub, and may in the future provide opportunities to expand in other areas. Acquisitions of incremental interests are being given particular emphasis to take advantage of systems and operational knowledge already in place. The Company has extensive experience in completing numerous types of acquisitions using varied financing sources in addition to internal cash flow.
During 1993 domestic acquisitions having a total cost of $51.0 million were completed, primarily to strengthen Wattenberg and establish two new projects, each of which has the potential to develop into a large scale gas development program. In Wattenberg a series of purchases added nearly 9 million BOE of proved reserves at a net cost of under $3.50 per barrel as well as several pipeline and processing facilities that complement the Company's existing gathering systems. In the largest of these acquisitions, the Company paid $19.7 million and, after an exchange of interests with a third party, acquired an approximate 80% working interest in 153 producing wells and 284 undeveloped locations having total proved reserves estimated to exceed 7 million BOE. A portion of the value of the transaction lay in the large volume of undedicated gas located in close proximity to the Company's gas lines.
In the Washakie Basin, the Company expended over $7.8 million to acquire a 25% incremental interest in its Barrel Springs properties and interests in 44 producing wells and 7 undeveloped locations, as well as a gathering system that expands the existing gathering infrastructure in the area. These acquisitions added approximately 3.6 million BOE of proved reserves and, together with an active leasing program, formed the basis for the East Washakie Project, the Company's second operating hub in the Rockies. See "Development - East Washakie Project."
Through three purchases, farmouts and leasing, the Company established a substantial position in the Piceance and Uinta Basins during 1993, forming the foundation of the Western Slope Project, a third gas development hub in the Rockies. A $6.2 million purchase gave the Company a 100% working interest in the 26,000 acre Divide Creek Unit in the southeast Piceance Basin. The Company also formed the adjacent 53,000 acre Hunter Mesa Unit and through purchases and farmouts obtained a majority working interest position and became unit operator. Near yearend the Company also acquired interests in 122 producing wells, 29 non-producing wells and 69 undeveloped locations in various fields in the Uinta and Piceance Basins. See "Development - Western Slope Project."
The following table summarizes acquisition activity since 1983:
Gas Management
General. The Company expanded its gas gathering and processing capacity during 1993 with the construction of the Enterprise system and expansion of the Roggen plant in Wattenberg, as well as the acquisition of additional gas facilities in Wattenberg and in Wyoming. By yearend, operated processing capacity had increased to more than 80 MMcf per day and gathering system capacity was increased to more than 200 MMcf per day, while marketed net volumes reached 100 MMcf per day. The gas management unit complements the Company's development and acquisition activities by providing additional cash flow and enhancing return. The segment is also increasingly profitable in its own right. During 1993, operating cash flow increased by approximately 23% to $10 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 processing plant, and a number of minor facilities. By yearend 1993, the Roggen plant capacity had reached 60 MMcf per day. During the fourth quarter of 1993, average throughput had reached 54 MMcf per day. The expanded plant is expected to process gas from currently undeveloped locations, new third party sources and permanently released locations on acreage acquired from Amoco, plus additional gas from current suppliers. Gas developed through the UPRC joint venture is not dedicated to a processing plant and will significantly increase furture volumes of gas available to be processed in the Company's facilities.
At the Roggen plant, 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. During 1993, CIG constructed approximately 14 miles of pipeline from the Roggen plant to expand residue capacity. Residue capacity is currently believed to be capable of handling 50 MMcf per day under normal conditions. A liquids line permits the direct sale of Roggen's liquids products through an Amoco line to the major interchange at Conway, Kansas. In addition, Phillips Petroleum began reactivation of an old interconnect, which should be operational by the end of the second quarter of 1994, which will connect the Roggen plant to the Phillips Powder River liquids pipeline.
The Company's Wattenberg gathering systems include over 600 miles of pipeline which collect, compress and deliver gas from over 1,400 wells to the Roggen plant. During 1993, 443 new wells, including 335 Company wells, were connected to these pipelines. The Company acquired a pipeline which expands its gathering potential to the north and which could be converted to a residue line allowing for the delivery of residue gas from the tailgate of Roggen to the Williams Natural Gas System. The Company also constructed a nine mile 16" pipeline loop on the western portion of the system, which came on line in October 1993, to provide pressure relief in the area and additional capacity for further development in the area. Gas from wells in which the Company owns an interest currently accounts for approximately 86% of the gathered volumes.
The Company earns fees from transportation on its gathering lines and processing at the Roggen plant under two arrangements. Most gas is gathered and processed under arrangements whereby the Company retains for its own use or sale a significant part of the liquids products recovered at the plants as well as a portion of the residue gas. The remainder of the gas is transported and processed for a fixed amount per unit.
During 1993, the Company substantially expanded its gathering system. This expansion is known as the Enterprise system. 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 ("CDP's") plus several newly drilled wells. Approximately eight miles of lower pressure 20" main trunk pipeline and ten miles of laterals connecting 11 CDP's were added during 1993, along with additional compression facilities, at a cost of $9.1 million. The Enterprise system has the capacity to deliver 75 MMcf per day to the Amoco Wattenberg plant.
In conjunction with the construction of the Enterprise system, CIG constructed a high pressure 16" line which connects Enterprise to an existing CIG 16" pipeline which redelivers the gas to Amoco's Wattenberg plant. Prior to completion of the CIG line in May 1993, a portion of the Company's Wattenberg gas connected to Enterprise was delivered and processed at the Roggen plant.
The Company has negotiated a transportation arrangement with CIG that, in conjunction with the gathering fees to be charged on the Enterprise system, allows the delivery of gas to the Amoco Wattenberg plant at a favorable rate. In addition to containing current and 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 Roggen plant 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 Roggen plant and, to a lesser degree, two other plants in the area, enabled the Company to produce significant volumes that would have otherwise been curtailed.
Given the continued expansion of the Company's drilling program in 1994 and beyond and the potential for third party connections, the Company is continuing to explore opportunities to expand its Wattenberg gas facilities. Subsequent to yearend, the decision was made to double the Company's processing capacity through the construction of a new plant on the west side of the field. The new plant is scheduled to be operational in late 1994.
Wyoming Facilities. The Company operates two pipeline systems in Wyoming that enhance its ability to market gas produced from its Carbon County properties. Wyoming Gathering and Production Company ("WYGAP") gathers gas produced from 53 operated wells in the Barrel Springs Unit. The system has a capacity of 26 MMcf per day. Throughput averaged 10 MMcf and 14 MMcf per day during 1992 and 1993. WYGAP delivers gas to Western Transmission Corporation ("Westrans"), a Company-owned interstate pipeline system which operates under FERC jurisdiction. At the beginning of 1993, the Company assumed operations of CIG's Carbon County Blue Gap gathering system pursuant to a lease. The Company has exercised an option to acquire the system subject to regulatory approval. The Company also purchased Blue Gap gathering facilities formerly owned by Williams Field Services. Both systems extend the Company's transportation capabilities to the south.
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 which was completed in February 1992 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 90% of its volumes, Westrans transports volumes from other operated wells and third parties. The capacity of Westrans is 65 MMcf per day. Throughput volumes generally vary from 13 to 20 MMcf per day. Daily throughput averaged 15 MMcf during 1992 and 1993. If the planned acceleration of drilling in East Washakie occurs, volumes of gas on the Company's gas pipeline in the area may be substantially increased. 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 1993 to gather gas produced from newly developed Cheyenne County properties for delivery to various markets accessible through KN. The Cheyenne system includes 9.5 miles of 4" to 6" trunkline and 6 miles of 3" lateral gathering lines. During the fourth quarter of 1993, throughput averaged 3 MMcf per day of gas from 60 producing wells. Included in the December 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 8 MMcf per day from the 28 producing wells in the Riverton Dome Field.
In conjunction with the growing level of acquisition and development activity in the Piceance and Uinta Basins, the Company is actively exploring alternatives to gather and transport future gas production in those areas. In this connection, the possibility of constructing a Company-owned gathering and transportation line is being investigated. Traditionally, the lack of sufficient pipeline capacity has been a major deterrent to development in the Piceance Basin.
International Activities
During 1993, the Company made significant progress in building its international exploration and development effort into a vehicle having significant future growth potential. During the year, the Company's Russian venture received government approval. The Company signed a production sharing agreement with the government of Mongolia and completed its seismic work program in Tunisia. Finally, the Company acquired a 42.8% interest in a publicly traded Australian exploration company that has significant international exploration experience and an extensive inventory of projects that greatly enhance the Company's international efforts.
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 equity 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 the Company's international operations. During 1993, the Company purchased from Edward T. Story, President of SOCO International, the 10% of SOCO International held by him and canceled Mr. Story's option to purchase an additional 20% of the company. In connection with the purchase, the Company granted Mr. Story an option to purchase 10% of SOCO International through April 1998 for $600,000. The option price is subject to adjustment, in certain circumstances.
Russian Joint Venture. In early 1993, the Company formed Permtex, a joint drilling venture with Permneft, a Russian oil and gas company, to develop four major proven oil fields located in the Volga-Urals Basin of the Perm Region of Russia, approximately 800 miles east of Moscow. During 1993, Permtex was registered by the Russian authorities, representing governmental approval of the terms of the joint venture and authorization for Permtex to commence business. In early 1994, the Company executed a finance and insurance protocol with the Overseas Private Investment Corporation, an agency of the United States government that provides financing and political risk insurance for American investment in developing countries, related to the financing of Permtex.
Permtex holds exploration and development rights to over 300,000 acres in the Volga-Urals Basin. The contract area contains four major fields and four minor fields as well as a number of prospects. The Company estimates that the four major fields could ultimately produce 115 million barrels of oil. The major fields have been delineated through 45 previously drilled wells, none of which had been placed on production as of yearend 1993. It is anticipated that 25 of the existing wells will be placed on production, of which four should go on stream in the first half of 1994, and that 400 additional development wells will be drilled over the next five to ten years. The joint venture will primarily utilize Russian personnel and equipment and Western technology under joint Russian/American management.
As of March 1, 1994, the Company holds a 28.1% interest in Permtex, after giving effect to the subscriptions by each of Command Petroleum Holdings NL ("Command"), the Company's Australian affiliate, and Holland Sea Search NV ("HSSH"), a Dutch affiliate of Command, to purchase 6.25% interests in Permtex. Recently, a major Japanese trading company has also committed to purchase a 10 to 20% interest in Permtex, which would reduce the Company's interest to 20.6% if the full amount is purchased.
Command Petroleum Holdings NL. In May 1993, the Company purchased 42.8% of the outstanding shares of Command for approximately $18.2 million. At the time of the purchase, Thomas J. Edelman, President of the Company, Edward T. Story, President of SOCO International, and two other designees were elected to Command's eight-person board of directors. Command is an exploration and production company based in Sydney, Australia and listed on the Australian Stock Exchange. At yearend 1993, Command had working capital of $35 million and no debt. Its current market capitalization approximates US$150 million. Command currently holds interests in more than 20 exploration permits and production licenses primarily in the Southwestern Pacific Rim including Australia and Papua New Guinea. Until recently, Command held a 28.7% interest in HSSH, a publicly traded Dutch exploration and production company whose primary assets are an interest in the North Sea's Markham gas field. After yearend 1993, Command increased its position in HSSH to nearly 48%. Recently, Command purchased a 6.25% interest in Permtex, acquired an interest in an offshore Tunisian permit operated by Marathon and acquired an 11.4% interest in the East Shabwa Contract Area in Yemen. Command funded the expenditures with a portion of a $16.4 million privately placed equity offering which reduced the Company's ownership to 35.7%. If as expected, all of Command's warrants expiring in November 1994 are exercised, the Company's ownership would be decreased to 29.6%.
The Company believes that Command's exploration expertise, experienced technical staff and inventory of prospects complement the Company's acquisition and development expertise and position the Company to play a larger role in overseas development of oil and gas reserves. In addition, Command and HSSH provide access to international capital markets which could provide additional sources of financing for international projects.
Mongolia. The Company further expanded its international efforts by entering into a production sharing agreement with Mongol Petroleum Company, the national oil company of Mongolia. The Company believes this agreement is the first such contract ever awarded by Mongolia. The agreement covers 11,400 square kilometers, or approximately 2.8 million gross acres in the Tamstag Basin of northeastern Mongolia. In addition, the Company received a right of first refusal from Mongol Petroleum for the adjacent block which covers 11,130 square kilometers. As a consequence, the Company controls over 5 million acres in this basin which, although previously unexplored and remote from existing markets, is highly prospective. These concessions offset the Hailar Basin of China, a portion of which is included in the China National Petroleum Corporation's round of invitations for bidding in 1994. During 1993, the Company initiated seismic work to broadly define the subsurface. This work is expected to continue into 1995 at relatively modest cost.
Tunisia. During 1993 the Company completed its 400 kilometer seismic acquisition program in the Fejaj Permit area of central Tunisia. The permit area encompasses approximately 1.2 million gross acres and is predominately onshore, with a small portion extending into the Gulf of Gabes. After the Company integrates the newly acquired seismic work with over 1,400 kilometers of reprocessed data and extensive geological field information, the Company will seek industry partners for a 1995 exploratory 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, 1993.
(Dollars in thousands, except price and per barrel expenses)
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 operator, the Company charges overhead fees to all working interest owners according to the applicable operating agreements. As of the end of 1991, 1992 and 1993, respectively, the Company operated 1,442, 1,745 and 2,176 wells. The Company received overhead reimbursements for operations and drilling of $10.1 million, $12.9 million and $15.5 million during 1991, 1992 and 1993, 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 refiners and others having pipeline facilities near its properties. Where there is no access to gathering systems, crude oil is trucked to storage facilities. In 1992 and 1993, Amoco accounted for approximately 27% and 12% of revenues, respectively, as the result of the contractual dedication of a portion of the Company's natural gas and natural gas liquids produced from certain of its Wattenberg acreage. The Company exercised its option to release its natural gas and natural gas liquids and began marketing its production beginning January 1, 1994. See "Development - D J Basin - Wattenberg Field." 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.
In addition to marketing a significant portion of its own gas, in 1992 the Company initiated an effort to supplement its cash flow through the purchase and resale of gas owned by third parties. Gross margins during 1992 and 1993 from third party marketing activities was $.6 million and $1.2 million, respectively, as average third party volumes increased from 58.7 to 89.9 MMcf per day. The Company expects, to continue increasing its role in third party gas marketing.
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 facility has firm fifteen-year sales agreements with a utility company for electricity and with a tire manufacturer for steam. The effect of this contract depends on market prices for gas and its choice of alternative sources of gas (including the spot market) to meet its supply commitments. Gross margin generated from the contract was approximately $1.5 million for both 1991 and 1992. A contractual limitation of the contract sales price and rising gas purchase cost, resulted in a net loss of $267,000 on the contract during 1993. At present gas price levels, the Company foresees continued negative or breakeven margins for this contract through July 1994. At that time, the share of the sales price minimum attributable to gas will increase from 45% to 65% and margins should improve.
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 will be implemented on a pipeline-by-pipeline basis through negotiations in individual pipeline proceedings. Although Order 636 does not regulate any of the Company's material gas operations, FERC has stated that Order 636 is intended to foster increased competition in all phases of the natural gas industry. Industry commentators have predicted profound effects (which vary from commentator to commentator) on various segments of the industry as a result of this competition. Order 636 is being implemented on a pipeline-by-pipeline basis through negotiated settlements in independent pipeline service restructuring proceedings designed specifically to "unbundle" the pipelines' services (e.g., transportation, sales and storage) so that producers, marketers and end-users of natural gas may secure services from the most economical source.
The restructuring proceedings continued throughout 1993, with the majority of pipelines having received FERC orders approving their compliance filings, subject to conditions, so that the 1993-1994 winter heating season is the first period during which FERC Order 636 procedures have been operative. To date, management of the Company believes the Order 636 procedures have not had any significant effect on the Company. Because the restructuring involved wholesale changes in the operating procedures of pipelines, however, the Company is not able to predict the long term effect of the new procedures. Also, the Order and many of the pipeline procedures adopted in response thereto, will be subject to lengthy administrative and judicial review, which may result in procedures that are significantly different from those currently in effect.
When it issued Order 636, FERC recognized that in an effort to enable non-pipeline gas sellers to compete more effectively with pipelines, it should not allow pipelines to be penalized as competitors by any of their existing contracts which required the pipelines to pay above-market prices for natural gas. FERC recognized that it did not have authority to nullify these contracts, and instead encouraged pipelines and producers to negotiate in good faith to terminate or amend these contracts to align them with market conditions. During 1993, the Company renegotiated its contract with Southern Natural Gas Company ("SONAT") under which SONAT had purchased the Company's gas from the Thomasville Field at prices substantially above market value. As a result of the renegotiation, the Company received a $14 million payment and beginning January 1, 1994 the Company will receive a price that, while somewhat above current prices, will be substantially lower that the average 1993 contract price of $12.16 per Mcf.
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.
During the current session of the Colorado legislature, the Colorado Department of Natural Resources has prepared a bill ("SB 177"), which gives additional authority to the Colorado Oil and Gas Conservation Commission ("COGCC") in their regulation of the oil and gas industry. The bill has currently passed the Senate Agricultural Committee and will be presented to the full legislature in March. This bill is very similar to legislation proposed during the 1993 legislature session. Legislation of this type could increase the cost of the Company's operations and erode the traditional rights of the oil and gas industry in Colorado to make reasonable use of the surface to conduct drilling and development activities. In addition, a coalition of oil and gas industry and agriculture are working on a Surface Damage Compensation bill. The group will try to have the bill sponsored and passed in this session of the legislature. This bill, if enacted, would also increase the Company's cost of doing business.
Also at the statewide level, the surface owner groups have indicated that they may seek a statewide ballot initiative to overturn the traditional real property concept of the dominance of the mineral estate and put the surface estate as the dominate estate. These same groups are also active at the local level, 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 has increased following a recent 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 COGCC, but that they could limit those activities under their land use authority. Under these decisions, 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. Although numerous changes are expected in light of the recently adopted and pending regulatory initiatives, management is not able to predict the final form of these initiatives or their impact on the Company.
In December 1992, COGCC instituted a review of "slimhole" completions (i.e., completions using pipe having a diameter of less than 4-1/2") and expressed concerns that slimhole completions could result in the loss of reserves, cause environmental damage and result in increased abandonment costs to the State. Hearings on the matter were scheduled for February 1994. Following meetings of representatives of the Company and other major Wattenberg operators with the COGCC at which the operators discussed slimhole techniques, the hearings were postponed until May. Although the Company believes that slimhole completion is a safe and economically viable completion method, the Company is unable to predict what, if any regulations might be adopted by the COGCC or their effect on the Company. Regulations that imposed significant restrictions on slimhole completions, however, could increase the cost of the Company's drilling operations and could cause certain locations to become uneconomic.
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.
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 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.
Officers
In early 1993, the Company restructured its organization, dividing operations into four separate business units and decentralized a number of staff functions. Each business unit has bottom line responsibility in order to reduce administrative costs, increase efficiency and increase focus on enhancing asset value. The flatter organization structure should also assist the Company in capitalizing on opportunities that may result in significant growth, including acquisitions and additional enhancement projects.
Listed below are the officers and a summary of their recent business experience.
John C. Snyder (52), 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 Fort Worth Country Day School.
Thomas J. Edelman (43), 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 Holdings NL, 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 and Total Energy Services Corporation.
John A. Fanning (54), 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 (47), 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 (37), 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.
Robert J. Clark (49), President of SOCO Gas Systems Inc. and Vice President - Gas Management of the Company, joined the Company in 1988. From 1985 to 1988, Mr. Clark was Vice President - Natural Gas for Ladd Petroleum Corporation, a subsidiary of General Electric Company. From 1967 to 1985, Mr. Clark served in various management capacities with Northern Illinois Gas Company, NICOR Exploration Company and Reliance Pipeline Company, all of which were subsidiaries of NICOR, Inc. Mr. Clark received his Bachelor of Science Degree in Accounting from Bradley University and his Masters Degree in Business Administration from Northern Illinois University.
Gary R. Haefele (51), Vice President - DJ Basin, rejoined the Company in 1993. Mr. Haefele was a consultant to the Company in 1992. From 1981 to 1991, Mr. Haefele worked for the Company as Senior Vice President, Production. Mr. Haefele served as Vice President, Engineering and International Operations for Hamilton Brothers from 1979 to 1981. Mr. Haefele held various production and reservoir engineering positions for Chevron from 1965 to 1979. Mr. Haefele has a Bachelor of Science Degree in Petroleum Engineering from the University of Wyoming.
Peter E. Lorenzen (44), 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 Johns Hopkins University.
James H. Shonsey (42), Vice President - Controller, 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.
Edward T. Story (50), President of SOCO International, Inc. and 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 Holdings NL, 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 (47), 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.
Rodney L. Waller (44), 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 (41), Vice President - Asset Rationalization, 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 director of Oxford Consolidated, Inc., a public oil and gas company, and 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, central and southern Wyoming, the Piceance and Uinta Basins in the Western Slope of Colorado and Utah, the Giddings area in South Texas, the Spraberry Trend in West Texas, waterflood units in Texas, and the Appalachian Basin in eastern Ohio and Pennsylvania. See "Significant Properties."
At December 31, 1993, the Company had interests in 5,122 gross (2,187 net) producing oil and gas wells located in 15 states and in the Gulf of Mexico. As of December 31, 1993, estimated proved reserves totalled 31.9 million barrels of oil and 430.1 Bcf of gas. In addition to its oil and gas reserves, the Company holds interests in nine gas transportation and processing facilities. See "Business - - Gas Management."
Proved Reserves
The following table sets forth estimated yearend proved reserves for the three years ended December 31, 1993.
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, 1993, averaging $12.54 per barrel of oil and $2.27 per Mcf of gas. Price reductions decrease reserve values by lowering the future net revenues attributable to the reserves and will reduce 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 such 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, 1993. Approximately 38% of the yearend Pretax PW10% Value was estimated internally by the Company and 62% 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, 1993 relating to the producing wells in which the Company owned a working interest. The Company also held royalty interests in 240 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, 1993 relating to acreage held by the Company. Undeveloped acreage is all a 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
Although the Company's properties are widely dispersed geographically, emphasis has been placed on establishing "hubs" in certain producing basins. Interests in five producing areas accounted for approximately 90% of Pretax PW10% Value at December 31, 1993. This concentration of assets results in economic efficiencies in the management of assets and permits identification of complementary acquisition candidates. Summary information regarding reserve concentrations and more detailed information regarding the four most significant properties are set forth below.
On March 9, 1994, the closing price of the common stock was $19-1/2. Dividends were paid quarterly at the rate of $.05 per share in 1992. Due to revised payment timing, two payments were made at the $.05 rate in the second quarter of 1992. Dividends were paid at the rate of $.05 per share in the first and second quarter of 1993. In the third quarter of 1993, dividends were increased to $.06 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 the Company's preferred stock, capital expenditures and other factors. On December 31, 1993, there were approximately 3,500 holders of record of the common stock and 23.3 million shares outstanding.
On March 9, 1994 the closing price of the $4 Convertible Preferred Stock was $106. Shares of $4 Convertible Preferred Stock receive quarterly dividends of $1.00 if declared by the Board of Directors. Any cumulative dividends in arrears must be paid prior to payment of any dividends on the common stock. On December 31, 1993, there were 24 holders of record of the $4 Convertible Preferred Stock and 1.2 million shares outstanding. The $4 Convertible Preferred Stock may be called beginning on January 1, 1995 at a price of $52.50 per share.
On March 9, 1994 the closing price of the depositary shares representing the $6 Convertible Preferred Stock was $27-7/8. Each depositary share represents a one-quarter interest in a share of $100 liquidation value $6 Convertible Preferred Stock. Shares of $6 Convertible Preferred Stock receive quarterly dividends of $1.50 ($.375 per depositary share) if declared by the Board of Directors. A dividend was paid June 30, 1993 at the rate of $1.17 per share ($.29 per depositary share), reflecting a partial rate since issuance in April 1993. Any cumulative dividends in arrears must be paid prior to payment of any dividends on the common stock. On December 31, 1993 there were 43 holders of records of the $6 Convertible Preferred Stock and 4.1 million depositary shares outstanding. The $6 Convertible Preferred Stock may be called beginning on March 31, 1996 at a price of $104.10 per share ($26.05 per depositary share).
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected financial and operating information for each of the five years ended December 31, 1993. 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. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
Comparison of 1993 results to 1992. Total revenues rose 91% in 1993 to $229.9 million. Net income before taxes and extraordinary items more than doubled to reach $34.9 million in 1993. The increase was led by a rapid rise in production and assisted by an increase in gas processing and transportation margins. Before the effect of a favorable $3.8 million income tax accounting change in 1992 and a $1.9 million 1993 extraordinary charge on early retirement of debt, earnings per common share were $.80 in 1993 compared to $.53 in 1992, a 51% increase.
The gross margin from production operations for 1993 increased 62% to $79.7 million, which was primarily related to a 65% growth in oil and gas production. The price received per equivalent barrel decreased by 3% to $13.41. Total operating expenses including production taxes increased 60% during 1993 although operating cost per equivalent barrel ("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 1993 operating costs averaged $7.45 per BOE.
For the year ended December 31, 1993, average daily production per BOE was 25,472 Bbls, a 65% increase from 1992. Average daily production in the fourth quarter of 1993 climbed to 10,314 barrels and 105.6 MMcf (27,917 barrels of oil equivalent). The production increases resulted primarily from acquisitions and continuing development drilling in the DJ Basin of Colorado. Domestically, $51.0 million in properties were acquired in 1993, primarily in and around existing hubs in Colorado and Wyoming. The acquisitions included a significant number of development locations and should continue to add to production into 1994. In 1993, 311 wells were placed on production in the DJ Basin, with 51 wells in various stages of drilling and completion at yearend. Because the majority of the wells were added in the latter part of the year, production will not be fully impacted until 1994. Additionally, significant downtime was experienced in the fourth quarter at the major processing plant in the area and much of the gas had to be diverted, which increased line pressures and hampered production. To a lesser extent, this situation continued into early 1994.
The gross margin from gas processing, transportation and marketing activities for 1993 increased 23% to $10.0 million from $8.1 million in 1992. The increase was primarily attributable to a $3.0 million (33%) rise in transportation and processing margins as a result of additional DJ Basin production and the recent 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. In 1993 the net contract margin was a loss of $267,000, which was $1.8 million less than 1992. At present gas price levels, the Company foresees continued negative or breakeven margins for the cogeneration contract through July 1994. At that time, the share of the sales price minimum attributable to gas will increase from 45% to 65% and the margin should improve. The cogeneration margin reduction was partially offset by a $667,000 (126%) rise in other gas marketing margins resulting from increased third party marketing.
Other income was $10.4 million during 1993, compared to $4.2 million in 1992. The $6.2 million increase resulted from a $3.5 million gas contract settlement received in April, a $1.7 million litigation judgment and greater gains on the sales of securities. General and administrative expenses, net of reimbursements, for 1993 represented 3% of revenues compared to 5.6% in 1992 as expenses were held essentially flat while revenues grew 91%. Interest and other expenses increased 28% primarily as a result of a rise in outstanding debt balances. Senior debt was paid down in April 1993 with proceeds from a preferred offering, but increased through yearend as a result of development expenditures, acquisitions, the investment in Command Petroleum and the retirement of the $25.0 million in subordinated debt.
Depletion, depreciation and amortization during 1993 increased 60% from the prior year. The increase was the direct result of the 65% rise in equivalent production between years. The producing depletion rate per equivalent barrel for 1993 was reduced to $4.75 from $4.79 in 1992. The rate was reduced by an ongoing drilling cost reduction program, partially offset by an increase from the discontinuation of converting Thomasville production to equivalent quantities based on relative gas prices.
The Company adopted FASB Statement No. 109, "Accounting for Income Taxes," effective January 1, 1992. Net income for 1992 was increased by $3.8 million for the cumulative effect of the change in method of accounting for income taxes. In 1992 the income tax provision was reduced from the statutory rate of 34% by $5.5 million due to the elimination of deferred taxes as a result of tax basis in excess of financial basis. In 1993 the income tax provision was reduced from the newly enacted rate of 35% by $4.7 million upon full realization of the excess basis benefit. The Company anticipates deferred taxes will be provided in 1994 and beyond based on the full statutory rate.
Comparison of 1992 results to 1991. Revenues rose 30% in 1992 to $120.2 million, compared to $92.5 million in 1991. Net income for 1992 was $20.6 million, a 134% jump from the $8.8 million in 1991. The increases resulted from greater oil and gas production volumes, lower interest expense, reduced general and administrative expenses and a $3.8 million reversal of the cumulative effect of prior year deferred taxes with the adoption of a change in the method of accounting for income taxes.
Average daily production for 1992 rose 24% to 15,408 equivalent barrels due mostly to development drilling in the DJ Basin of Colorado as 189 wells were placed on production there. As a result, the gross margin from production increased 22% to $49.3 million in 1992. The price per equivalent barrel of oil and gas production decreased 4% during 1992.
The gross margin from gas processing, transportation and marketing activities for 1992 increased 12% to $8.1 million from $7.3 million in 1991. The growth was primarily the result of increased marketing of third party gas in New Mexico, Colorado and Wyoming. Gas processing and transportation margins increased moderately as volumes were increased late in the year by expansions of pipeline and plant facilities to take advantage of increasing DJ Basin production. Other income for 1992 decreased 26% to $4.2 million from a reduction in gains on sales of securities and lower interest on notes receivable.
Direct operating expenses including production taxes increased only 13% during 1992 as the operating cost per equivalent barrel decreased to $4.99 from $5.47 in 1991, due to increased DJ Basin production where operating costs have been significantly lower than average. General and administrative expenses, net of reimbursements, for 1992 represented less than 6% of revenues compared to 8% in 1991, as revenues rose 30%. Interest and other expenses dropped 39% in 1992 due to lower average outstanding senior debt after the application of proceeds from a preferred stock offering in late 1991.
Development, Acquisition and Exploration
During 1993 the Company incurred $93.1 million for oil and gas property development and exploration, $51.0 million for acquisitions and $22.6 million for gas facility expansion and other assets, for a total of $166.7 million in property and equipment expenditures. Additionally, the Company made an $18.2 million investment in an Australian based exploration and production company.
The Company has concentrated a significant portion of its development activities in the DJ Basin of Colorado. Capital expenditures for DJ Basin development totalled $75.4 million during 1993. A total of 311 newly drilled wells were placed on production there in 1993 and 51 were in progress at yearend. Additionally, 42 recompletions were performed in 1993, with seven in process at yearend. In December 1993, 16 drilling rigs were in operation in the DJ Basin. The Company anticipates putting 500 or more wells per year on production in the DJ Basin for the next few years. With additional leasing activity and through drilling costs reductions that add infill locations as proven as they become economic, the Company has increased the inventory of available drillsites. In December, the Company entered into a letter of intent with Union Pacific Resources Corporation whereby the Company will gain the right to drill wells on UPRC's previously uncommitted acreage throughout the Wattenberg area. This transaction significantly increased the Company's undeveloped Wattenberg inventory. UPRC will retain a royalty and the right to participate as a 50% working interest owner in each well, and received grants for warrants to purchase two million shares of Company stock. Of the warrants, one million expire three years from the date of grant, and are exercisable at $25 per share, while the other one million expire in four years and are exercisable at $27 per share. One year from the date of grant (February 8, 1994), the exercise prices may be reduced to 120% of the average closing price of the Company stock for the preceding 20 consecutive trading days, but not to lower than an exercise price of $21.60 per share. At that time the expiration date of the warrants may also be extended one year if the average closing price over the 20 day trading period is less than $16.50 per share.
The Company expended $14.8 million for other development and recompletion projects and $2.9 million for exploration during 1993. In Nebraska, 29 wells were added to production in 1993 as an extension of a drilling program initiated in 1992. An additional 20 wells are planned in Nebraska for 1994. In southern Wyoming, 11 wells in the East Washakie Basin development program were successfully drilled and completed during the last half of 1993 with three in process at yearend. In this program, significant cost- cutting measures were applied based on the experience gained in the DJ Basin. In central Wyoming on the properties acquired from ARCO in late 1992, efforts have been focused on increasing operating efficiency with limited development drilling and workover activity. In 1993, three successful wells were drilled in the fourth quarter and selected development and recompletion activity is scheduled for 1994. In the Piceance Basin of western Colorado, a three well test program was started in December of 1993 on acreage acquired there during the year, with one well undergoing completion, the second in progress and a third scheduled for early 1994. Current plans include a minimum of 25 wells in the basin during 1994. In South Texas, a combined operated and non-operated program was initiated, with nine wells completed in 1993 and one well abandoned. A total of 25 additional horizontal locations have been identified and drilling should continue with as many as 15 wells planned in 1994. In its domestic exploration efforts, the Company initiated a seismic program in Louisiana and began drilling early in the fourth quarter. Advanced seismic techniques are being used to identify further prospects in Louisiana and expectations are to drill up to 20 wells in 1994.
A total of $51.0 million in domestic acquisitions were completed in 1993. In May 1993, the Company purchased an interest in 121 producing wells and over 70 drilling locations in the DJ Basin area for $3.3 million. In July, an incremental 25% interest in the Company's Barrel Springs and Duck Lake Fields in Wyoming was purchased for $6.1 million. The properties are 90% gas and include 44 producing wells and 46 undeveloped locations. In August, the Company acquired interests in 225 producing wells and 272 proved undeveloped locations in the DJ Basin for $19.7 million. The proved reserves are 70% gas with more than two-thirds requiring future development to produce. Late in the year, two acquisitions were completed in the Piceance and Uinta Basins of Western Colorado for a total of $12.5 million. The majority of the value was in undeveloped locations as only 128 wells were currently producing. Numerous other producing and undeveloped acquisitions totalling $9.4 million were completed, mostly in or close to the Company's principal operating areas.
The Company's gas gathering and processing facilities have been undergoing significant transformation since late 1992. In 1993, the Company expended $20.1 million to further develop its gas related assets. The Company spent $9.4 million toward the second phase of its DJ Basin gathering expansion to construct a high pressure line to deliver gas directly to the major gas processing plant in the area and expand its gathering network for the increased drilling activity. An additional $2.6 million was expended to expand the Roggen Plant for the production increases. A total of $5.6 million in additional transportation and gathering facilities were constructed in the DJ Basin including a nine mile 16" interconnect line completed in October to relieve high line pressures, a 20" western gathering extension and numerous other extensions and connections. A gathering system that delivers third party gas to the Roggen Plant was purchased for $703,000. The Company expended $1.4 million to complete construction of a system to gather gas from its Nebraska drilling project. These projects are intended to take advantage of the significant increase in drilling activity in these areas.
In the international arena, progress continues as well. In May 1993, the Company acquired 42.8% of the outstanding shares of Command Petroleum Holdings N.L., an Australian exploration and production company, for $18.2 million. The Sydney based company is listed on the Australian Stock Exchange, and at December 31, 1993 had 950,000 barrels of proven oil reserves and $19.9 million of working capital. In addition, it holds interests in more than 20 exploration permits and licenses and a 28.7% interest in a Netherlands exploration and production company whose assets are located primarily in the North Sea. In Russia, the Permtex joint venture received central government approval in August and the Company executed a finance and insurance protocol with the Overseas Private Investment Corporation ("OPIC"), a United States government agency. Current plans call for 25 of the existing 45 shut-in wells to be placed on production in 1994, and that 400 development wells will be drilled over the next ten years. Extensive seismic work began in the fourth quarter of 1993 for 400 kilometers of data in Tunisia and 500 kilometers in Mongolia.
Financial Condition and Capital Resources
At December 31, 1993, the Company had total assets of $480 million and working capital of $1.3 million. Total capitalization was $412 million, of which 28% was represented by senior debt and the remainder by stockholders' equity. During 1993, the Company fully retired its $25 million of 13.5% subordinated notes and the related cumulative participating interests. During 1993, cash provided by operations was $68.3 million, an increase of 43% over 1992. As of December 31, 1993, commitments for capital expenditures totalled $7.5 million, primarily for DJ Basin drilling. The level of 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, proceeds from property dispositions and existing credit facilities. In addition, joint ventures or future public and private offerings of securities may be utilized.
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 October 1992, and at first payout in June 1993 the second contribution of $1.5 million was received. An additional $1.5 million was received in October 1993. This transaction should increase the Company's cash flow and net income through 1994. 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 $3.8 million of this revenue during 1993. Discussions are in progress to expand this transaction so that the benefits would be extended through at least 1996.
In April 1993, the Company sold 4.1 million depositary shares (each representing a one quarter interest in one share of $100 liquidation value stock) of convertible preferred stock through an underwriting for $103.5 million. A portion of the net proceeds of $99.3 million was used to retire the entire outstanding balance under the revolving credit facility at that time. The preferred stock pays a 6% dividend and is convertible into common stock at $21.00 per share. At the Company's option, the preferred stock is exchangeable into 6% convertible debentures on any dividend payment date on or after March 31, 1994. The stock is redeemable at the option of the Company on or after March 31, 1996.
Effective July 1, 1993, the Company renegotiated its bank credit facility and increased it from $150 million to $300 million. The new facility is divided into a $50 million short-term portion and a $250 million long-term portion that expires on December 31, 1997. However, management's policy is to renew the facility annually. Credit availability is adjusted semiannually to reflect changes in reserves and asset values. At December 31, 1993, the elected borrowing base was $150 million. The majority of the borrowings currently bear interest at LIBOR plus 1.25% with the remainder at prime. The Company also has the option to select CD plus 1.375%. 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. Based on such limitations, $86.5 million would have been available for the payment of dividends and other restricted payments as of December 31, 1993. The Company does not currently plan to make, and is not committed to make, any advances or contributions to unrestricted subsidiaries that would materially affect its ability to pay dividends under this limitation.
During 1993, the Company fully retired its $25.0 million of 13.5% subordinated notes and the related cumulative participating interests. An extraordinary charge to earnings of $1.9 million (net of income taxes) was made in 1993, representing the amount paid in excess of principal and accrued interest through the retirement dates. These notes were retired early in order to reduce the Company's ongoing cost of debt.
The Company maintains a program to divest marginal properties and assets which do not fit its long range plans. For 1992 and 1993, proceeds from these sales were $3.0 million and $5.5 million, respectively. Included in the 1993 proceeds were $4.0 million of cash receipts previously accrued for late 1992 sales. The Company intends to continue to evaluate and dispose of nonstrategic assets.
In 1990, the Company was granted a judgment in litigation regarding a leasehold assignment from the early 1980's. The Oklahoma Supreme Court refused certiorari and the judgment was upheld. As a result, a total of $1.7 million was accrued and reported in other income in 1993. The full amount was collected in January 1994. In April 1992, a jury found for the plaintiffs in a gas contract dispute related to an offshore property. In April 1993, the dispute was settled by an agreement to pay the Company a net of $5.3 million. The initial $3.5 million was received and reflected as other income in second quarter 1993. The remaining $1.8 million was received in third quarter 1993, but reflected as a reserve for possible contingencies. 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 financial statements reflect these judgments only upon receipt of cash or final judicial determination.
The Company believes that its capital resources are more than 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. While such fluctuations have had, and will continue to have a material effect, the Company is unable to predict them.
The following table indicates the average oil and gas prices received over the last five years and highlights the price fluctuations by quarter for 1992 and 1993. Average gas prices exclude the Thomasville gas production. During 1993, the Company renegotiated its Thomasville gas contract and beginning in January 1994, the Company will receive a somewhat higher than market price for its Thomasville gas sales, significantly below its 1993 average price of $12.16 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. Equivalent prices prior to 1993 have been restated to reflect elimination of the conversion of Thomasville gas volumes based on its price relative to the Company's other gas production.
In December 1993, the Company was receiving an average of $12.54 per barrel and $2.27 per Mcf (excluding the Thomasville contract) for its production. Beginning in December 1992, the average oil price was effectively reduced by the oil production added from the Wyoming acquisition, which sells at a significant discount to West Texas Intermediate posting due to the presence of low gravity sour crude in two of the fields.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Reference is made to the Index to Financial Statements on page 35 for financial statements and notes thereto. Supplementary schedules are presented at the end of Part III following page 55. Quarterly financial data is presented on page 28 of this Form 10-K. Schedules I, III, IV, VII, VIII, IX, XI, XII, and XIII 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. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES.
None.
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 1992, 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, 1993. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules 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 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
As explained in Note 7 to the financial statements, effective January 1, 1992, the Company changed its method of accounting for income taxes.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the index to financial statements and schedules are presented for purposes of complying with the Securities and Exchange Commission's rules and are not a part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Forth Worth, Texas February 25, 1994
LIABILITIES AND STOCKHOLDERS' EQUITY
SNYDER OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Snyder Oil Corporation (the "Company") is engaged in the acquisition, production, development and to a lesser degree exploration of primarily domestic oil and gas properties. The Company is also involved in gas processing, transportation, gathering and marketing. The Company, a Delaware corporation, is the successor to a company formed in 1978. 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.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements include the accounts of Snyder Oil Corporation and its subsidiaries (collectively, the "Company"). 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.
The Company follows the "full cost" accounting method. All costs of exploration and development are capitalized as incurred. Depletion, depreciation and amortization ("depletion") is provided on the unit-of-production method based on proved reserves. Gas is converted to equivalent barrels at the rate of six Mcf per barrel. The depletion rates per equivalent barrel produced were $4.68, $4.79 and $4.75, respectively, in 1991, 1992 and 1993. In 1993, the practice of converting Thomasville production to equivalent quantities based on its price relative to other gas production was discontinued. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed. Expenditures which enhance the value of the properties are capitalized. Depreciation on gas processing and transportation facilities is generally provided on a straight-line basis over 15 years.
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 received. The affiliate's functional currency is the Australian dollar. The reported foreign currency translation adjustment is the result of the translation of the Australian balance sheet into United States dollars at year-end and the related impact of exchange rates subsequent to purchase.
All highly liquid investments with a maturity of three months or less are considered to be cash equivalents. Earnings per share are computed based on the weighted average number of common shares outstanding. Differences between primary and fully diluted earnings per share were insignificant for all periods presented. General and administrative expenses are reduced by reimbursements for well operations, drilling and management of partnerships. Reimbursements amounted to $11.1 million, $14.3 million and $17.8 million, respectively, in 1991, 1992 and 1993.
Certain amounts in the 1991 and 1992 financial statements have been reclassified to conform with the 1993 presentation.
(3) INDEBTEDNESS
The following indebtedness was outstanding on the respective dates:
The Company maintains a $300 million revolving credit facility. The facility is divided into a $250 million long-term portion and a $50 million short-term portion. However, management's policy is to renew the facility annually. The elected borrowing base available under the facility at December 31, 1993 was $150 million. The majority of the borrowings currently bear interest at LIBOR plus 1.25% with the remainder at prime. During 1993, the average borrowing cost was 4.9%. The Company pays certain fees based on the borrowing base and outstanding loans. 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. At December 31, 1992, the Company recorded the $49.8 million Wyoming acquisition commitment as other senior debt. The cash flow statement did not reflect the commitment as an increase in indebtedness until final payment was disbursed in February 1993.
The subordinated notes bore interest at 13.5% and were due in four annual payments commencing November 15, 1993. The notes were subject to optional redemption at 102% of principal after November 1994 and at par after November 1995. Cumulative rights to receive additional interest based on net cash flow above certain minimum levels were issued in connection with the notes. Cash flow has substantially exceeded the minimum since 1991, and the Company has since made the maximum payments. At December 31, 1992, based on existing market rates the subordinated notes and cumulative interest rights had a combined fair value of $27.7 million, which the Company believes approximated its cost of funds for notes with similar terms. In March 1993, the Company retired 40% of the cumulative rights. The portion of the payment representing prepaid interest was expensed as an extraordinary item, net of income taxes, for $384,000. In August 1993, the Company retired $10 million (40%) of the subordinated notes. The portion of the payment representing prepaid interest was expensed as an extraordinary item, net of income taxes, for $462,000. In November 1993, the Company retired the remaining $15 million of the subordinated notes and the related 60% of cumulative rights, with the portion of the payment representing prepaid interest expensed as an extraordinary item, net of income taxes, for $1.1 million. The Company expensed $1.1 million, $1.1 million and $516,000 as interest expense for cumulative rights in 1991, 1992 and 1993, respectively.
Scheduled maturities of indebtedness are $15,000 for 1994, $17,000 for 1995 and 1996, and $114.9 million in 1997. The long-term portion of the revolving credit facility is scheduled to expire in 1997; however, management's policy is to renew the facility annually.
Cash payments for interest expense were $7.9 million, $5.4 million and $9.2 million, respectively, for 1991, 1992 and 1993.
(4) INVESTMENTS
The Company has investments in foreign and domestic energy companies and notes receivable, which at December 31, 1992 and 1993, had a total book value of $7.4 million and $29.4 million, respectively, with corresponding fair market values of $9.8 million and $54.2 million.
In May 1993, the Company acquired 92 million (42.8%) of the outstanding shares of Command Petroleum Holdings N.L. ("Command"), an Australian exploration and production company, for $18.2 million. The Sydney based company is listed on the Australian Stock Exchange, and holds interests in more than 20 exploration permits and licenses as well as a 28.7% interest in a publicly traded Netherlands exploration and production company whose assets are located primarily in the North Sea. The market value of the Company's investment in Command based on Command's closing price at December 31, 1993 was $39.1 million. The investment is accounted for by the equity method. Command has outstanding stock options covering the issuance of up to 53.3 million common shares that expire November 30, 1994. Given that the exercise price of the options is 44% below the year-end stock price, the Company assumes they will be exercised. In January 1994, Command completed an offering of 43 million of its common shares. As a result of this offering, the Company's ownership was reduced to 35.7%. If, as expected, all of the November 1994 options were exercised, the Company's ownership would be reduced to 29.6%.
The Company has investments in securities of publicly traded domestic energy companies, not accounted for by the equity method, having a book value and total cost at December 31, 1992 and 1993 of $680,000 and $9.7 million, respectively. The market value of these securities at December 31, 1992 and 1993 approximated $2.9 million and $13.3 million, respectively. In the first quarter of 1994, the Company will be required to adopt SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." Under the provisions of SFAS No. 115, at December 31, 1993 the Company would have increased its investments by $3.6 million and increased stockholders' equity by $2.3 million and deferred tax liability by $1.3 million.
The Company holds $1.8 million in notes receivable due from privately held corporations. All notes are secured by certain assets, including stock and oil and gas properties. At December 31, 1992 and 1993, the fair value of the notes receivable, based on existing market conditions and the anticipated future net cash flow related to the notes, was believed to be equal to their book value.
(5) OIL AND GAS PROPERTIES
The cost of oil and gas properties at December 31, 1992 and 1993 includes $4.0 million and $9.8 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:
In December 1992, the Company acquired certain producing properties located in north central Wyoming from a major oil company for $56.1 million. An initial cash payment of $6.3 million was made in December 1992. The remaining $49.8 million was recorded as senior debt on the consolidated balance sheet at December 31, 1992, but not reflected on the Company's cash flow statement as an acquisition until payment was made in February 1993. Costs incurred above also differ from the cash flow statement as a result of certain cost recoveries and accrual items. The remaining 1992 acquisitions were primarily for producing properties in Wyoming, North Dakota and Texas. In May 1993, the Company purchased an interest in 121 producing wells and over 70 drilling locations in the DJ Basin of Colorado for $3.3 million. In July 1993, an incremental 25% interest in the Company's Barrel Springs and Duck Lake Fields was purchased for $6.1 million. In August 1993, the Company acquired interests in 225 producing wells and 272 undeveloped locations in the DJ Basin for $19.7 million. In late 1993, two acquisitions were completed in the Piceance and Uinta Basins of Western Colorado for a total of $12.5 million. A number of other producing and undeveloped acquisitions totalling $9.4 million were completed during 1993 as well, mostly in or close to the Company's principal operating areas. In late 1992, the Company initiated projects to further develop its gas gathering and processing facilities. A $4.5 million DJ Basin low pressure gathering system expansion was completed to provide new sources of inlet gas to the Roggen plant. Simultaneously, a $2.0 million expansion at Roggen raised plant capacity by 60% to 55 MMcf per day. An additional $848,000 was expended in 1992 to acquire a Roggen net profits interest and a pipeline in the area. In 1993, the Company expended $9.4 million toward the second phase of its DJ Basin gathering expansion to construct a high pressure line to deliver gas directly to the major gas processing plant in the area and expand its gathering network for the increased drilling activity. A total of $5.6 million in additional transportation and gathering facilities were constructed in 1993 in the DJ Basin including a nine mile 16" diameter interconnect line completed in October to relieve high line pressures, a 20" diameter western gathering extension and numerous other extensions and connections. In 1993, the Roggen plant was further enhanced with $2.6 million of capital expenditures. The Company expended $1.4 million to complete construction of a system to gather gas from its Nebraska drilling project. A number of lesser facilities were purchased in 1993 to expand the Company's gathering and processing capabilities in its active hub areas.
Acquisitions are accounted for utilizing the purchase method. The following unaudited pro forma information shows the effect on the consolidated statements of operations assuming that the 1992 significant acquisitions were consummated as of January 1, 1992. Individual 1993 acquisitions did not meet the significance test, therefore no 1993 pro forma information is presented. Future results may differ substantially from pro forma results due to changes in oil and gas prices, production declines and other factors. Therefore, pro forma statements cannot be considered indicative of future operations.
(6) STOCKHOLDERS' EQUITY
A total of 75 million common shares, $.01 par value, are authorized of which 23.3 million were issued and outstanding at December 31, 1993. In 1992, the Company issued 234,000 shares and repurchased 215,000 shares. 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. The Company made five quarterly dividend payments of $.05 per share in 1992 due to an acceleration in the quarterly payment date. In 1993, the Company paid first and second quarter dividends of $.05 per share and increased dividends to $.06 per share in the third and fourth quarters.
A total of 10 million preferred shares, $.01 par value, are authorized. In December 1991, 1.2 million shares of convertible exchangeable preferred stock were sold through an underwriting. The net proceeds were $57.4 million. The preferred stock carries an 8% dividend and is convertible into common stock at $9.07 per share. The stock is exchangeable at the option of the Company for 8% convertible subordinated debentures on any dividend payment date. The stock is redeemable at the option of the Company on or after December 31, 1994. The liquidation preference is $50.00 per share, plus accrued and unpaid dividends. During 1995, the stock is redeemable at $52.50 per share if the closing price exceeds 150% of the prevailing conversion price (currently $13.61 per share) for 20 of the preceding 30 trading days. After 1995, no minimum stock price is required. The redemption price declines $.50 per year to $50.00 per share in 2000. In 1993, 14,000 preferred shares were converted into 77,000 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 convertible preferred stock were sold through an underwriting. The net proceeds were $99.3 million. The preferred stock carries a 6% dividend and is convertible into common stock at $21.00 per share. The stock is exchangeable at the option of the Company for 6% convertible subordinated debentures on any dividend payment date on or after March 31, 1994. The 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 $4.8 million and $9.1 million, respectively, in preferred dividends during 1992 and 1993.
The Company maintains a stock option plan for Company employees providing for the issuance of options at prices not less than fair market value. Options to acquire up to 3 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, 1993, 1.4 million options were outstanding under both plans at exercise prices of $4.53 to $19.25 per share. At December 31, 1993, a total of 600,000 of such options were vested having exercise prices of $4.53 to $13.00 per share. During 1992, 223,000 options were exercised at prices of $3.02 to $6.00 per share, and 52,000 were forfeited. During 1993, 309,000 options were exercised at prices of $4.53 to $9.13 per share, and 23,000 were forfeited.
(7) FEDERAL INCOME TAXES
The Company adopted FASB Statement No. 109, "Accounting for Income Taxes," effective January 1, 1992. Net income for 1992 was increased by $3.8 million for the cumulative effect of the change in method of accounting for income taxes as a result of tax basis in excess of financial basis. At December 31, 1993, 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 Company's net deferred asset and liability at December 31, 1992 and 1993, respectively, were:
For tax purposes, the Company had net operating loss carryforwards of $69.1 million at December 31, 1993. These carryforwards expire between 1997 and 2008. At December 31, 1993, the Company had alternative minimum tax credit carryforwards of $1.4 million and depletion carryforwards of $1.1 million, both of which are available indefinitely. Current income taxes shown in the financial statements reflect estimates of alternative minimum taxes due. Cash payments during 1992 and 1993 were $1.0 million and $75,000, respectively.
(8) SALES TO MAJOR CUSTOMERS
In 1991, 1992 and 1993, Amoco Production Company accounted for 17%, 27% and 12%, 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 October 1992, and at first payout in June 1993 the second contribution of $1.5 million was received. An additional $1.5 million was received in October 1993. 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 of this revenue during 1992 and $3.8 million during 1993.
(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 $2.1 million for 1994, $2.2 million for 1995, $2.3 million for 1996 and 1997, and $2.1 million for 1998.
In 1990, the Company was granted a judgment in litigation regarding a disputed leasehold assignment from the early 1980's. The Oklahoma Supreme Court refused certiorari and the judgment was upheld. As a result, a total of $1.7 million was accrued and reported in other income in 1993. The full amount was collected in January 1994. In April 1992, the Company was granted a judgment in a gas contract dispute related to an offshore property. The dispute was settled in April 1993 by an agreement to pay the Company a net of $5.3 million. The Company received theses monies in 1993 and reflected $3.5 million as other income with the remaining $1.8 million recorded as a liability for possible contingencies. 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 or final judicial determination.
(11) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION:
Independent petroleum consultants directly evaluated 51%, 74%, and 62% of proved reserves at December 31, 1991, 1992 and 1993, 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.
PART II
ITEM 5.



ITEM 5. MARKET FOR THE REGISTRANT'S SECURITIES AND RELATED SECURITY HOLDER MATTERS
The Company's stock is listed on the New York Stock Exchange. The common stock began trading under the symbol "SNY" in March 1990. The Company's $4.00 Convertible Exchangeable Preferred Stock ("$ 4 Convertible Preferred Stock") began trading on the New York Stock Exchange under the symbol "SNY Pr" in November 1991. Depositary shares representing a quarter interest in the Company's $6.00 Convertible Exchangeable Preferred Stock ("$6 Convertible Preferred Stock") began trading on the New York Stock Exchange under the symbol "SNY Pr A" on April 14, 1993. Prior to those dates, there were no markets for these securities. The following table sets forth, for 1992 and 1993, the high and low sales prices for the Company's securities for New York Stock Exchange composite transactions reported by The Wall Street Journal.
On March 9, 1994, the closing price of the common stock was $19-1/2. Dividends were paid quarterly at the rate of $.05 per share in 1992. Due to revised payment timing, two payments were made at the $.05 rate in the second quarter of 1992. Dividends were paid at the rate of $.05 per share in the first and second quarter of 1993. In the third quarter of 1993, dividends were increased to $.06 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 the Company's preferred stock, capital expenditures and other factors. On December 31, 1993, there were approximately 3,500 holders of record of the common stock and 23.3 million shares outstanding.
On March 9, 1994 the closing price of the $4 Convertible Preferred Stock was $106. Shares of $4 Convertible Preferred Stock receive quarterly dividends of $1.00 if declared by the Board of Directors. Any cumulative dividends in arrears must be paid prior to payment of any dividends on the common stock. On December 31, 1993, there were 24 holders of record of the $4 Convertible Preferred Stock and 1.2 million shares outstanding. The $4 Convertible Preferred Stock may be called beginning on January 1, 1995 at a price of $52.50 per share.
On March 9, 1994 the closing price of the depositary shares representing the $6 Convertible Preferred Stock was $27-7/8. Each depositary share represents a one-quarter interest in a share of $100 liquidation value $6 Convertible Preferred Stock. Shares of $6 Convertible Preferred Stock receive quarterly dividends of $1.50 ($.375 per depositary share) if declared by the Board of Directors. A dividend was paid June 30, 1993 at the rate of $1.17 per share ($.29 per depositary share), reflecting a partial rate since issuance in April 1993. Any cumulative dividends in arrears must be paid prior to payment of any dividends on the common stock. On December 31, 1993 there were 43 holders of records of the $6 Convertible Preferred Stock and 4.1 million depositary shares outstanding. The $6 Convertible Preferred Stock may be called beginning on March 31, 1996 at a price of $104.10 per share ($26.05 per depositary share).
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, 1993. 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
Comparison of 1993 results to 1992. Total revenues rose 91% in 1993 to $229.9 million. Net income before taxes and extraordinary items more than doubled to reach $34.9 million in 1993. The increase was led by a rapid rise in production and assisted by an increase in gas processing and transportation margins. Before the effect of a favorable $3.8 million income tax accounting change in 1992 and a $1.9 million 1993 extraordinary charge on early retirement of debt, earnings per common share were $.80 in 1993 compared to $.53 in 1992, a 51% increase.
The gross margin from production operations for 1993 increased 62% to $79.7 million, which was primarily related to a 65% growth in oil and gas production. The price received per equivalent barrel decreased by 3% to $13.41. Total operating expenses including production taxes increased 60% during 1993 although operating cost per equivalent barrel ("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 1993 operating costs averaged $7.45 per BOE.
For the year ended December 31, 1993, average daily production per BOE was 25,472 Bbls, a 65% increase from 1992. Average daily production in the fourth quarter of 1993 climbed to 10,314 barrels and 105.6 MMcf (27,917 barrels of oil equivalent). The production increases resulted primarily from acquisitions and continuing development drilling in the DJ Basin of Colorado. Domestically, $51.0 million in properties were acquired in 1993, primarily in and around existing hubs in Colorado and Wyoming. The acquisitions included a significant number of development locations and should continue to add to production into 1994. In 1993, 311 wells were placed on production in the DJ Basin, with 51 wells in various stages of drilling and completion at yearend. Because the majority of the wells were added in the latter part of the year, production will not be fully impacted until 1994. Additionally, significant downtime was experienced in the fourth quarter at the major processing plant in the area and much of the gas had to be diverted, which increased line pressures and hampered production. To a lesser extent, this situation continued into early 1994.
The gross margin from gas processing, transportation and marketing activities for 1993 increased 23% to $10.0 million from $8.1 million in 1992. The increase was primarily attributable to a $3.0 million (33%) rise in transportation and processing margins as a result of additional DJ Basin production and the recent 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. In 1993 the net contract margin was a loss of $267,000, which was $1.8 million less than 1992. At present gas price levels, the Company foresees continued negative or breakeven margins for the cogeneration contract through July 1994. At that time, the share of the sales price minimum attributable to gas will increase from 45% to 65% and the margin should improve. The cogeneration margin reduction was partially offset by a $667,000 (126%) rise in other gas marketing margins resulting from increased third party marketing.
Other income was $10.4 million during 1993, compared to $4.2 million in 1992. The $6.2 million increase resulted from a $3.5 million gas contract settlement received in April, a $1.7 million litigation judgment and greater gains on the sales of securities. General and administrative expenses, net of reimbursements, for 1993 represented 3% of revenues compared to 5.6% in 1992 as expenses were held essentially flat while revenues grew 91%. Interest and other expenses increased 28% primarily as a result of a rise in outstanding debt balances. Senior debt was paid down in April 1993 with proceeds from a preferred offering, but increased through yearend as a result of development expenditures, acquisitions, the investment in Command Petroleum and the retirement of the $25.0 million in subordinated debt.
Depletion, depreciation and amortization during 1993 increased 60% from the prior year. The increase was the direct result of the 65% rise in equivalent production between years. The producing depletion rate per equivalent barrel for 1993 was reduced to $4.75 from $4.79 in 1992. The rate was reduced by an ongoing drilling cost reduction program, partially offset by an increase from the discontinuation of converting Thomasville production to equivalent quantities based on relative gas prices.
The Company adopted FASB Statement No. 109, "Accounting for Income Taxes," effective January 1, 1992. Net income for 1992 was increased by $3.8 million for the cumulative effect of the change in method of accounting for income taxes. In 1992 the income tax provision was reduced from the statutory rate of 34% by $5.5 million due to the elimination of deferred taxes as a result of tax basis in excess of financial basis. In 1993 the income tax provision was reduced from the newly enacted rate of 35% by $4.7 million upon full realization of the excess basis benefit. The Company anticipates deferred taxes will be provided in 1994 and beyond based on the full statutory rate.
Comparison of 1992 results to 1991. Revenues rose 30% in 1992 to $120.2 million, compared to $92.5 million in 1991. Net income for 1992 was $20.6 million, a 134% jump from the $8.8 million in 1991. The increases resulted from greater oil and gas production volumes, lower interest expense, reduced general and administrative expenses and a $3.8 million reversal of the cumulative effect of prior year deferred taxes with the adoption of a change in the method of accounting for income taxes.
Average daily production for 1992 rose 24% to 15,408 equivalent barrels due mostly to development drilling in the DJ Basin of Colorado as 189 wells were placed on production there. As a result, the gross margin from production increased 22% to $49.3 million in 1992. The price per equivalent barrel of oil and gas production decreased 4% during 1992.
The gross margin from gas processing, transportation and marketing activities for 1992 increased 12% to $8.1 million from $7.3 million in 1991. The growth was primarily the result of increased marketing of third party gas in New Mexico, Colorado and Wyoming. Gas processing and transportation margins increased moderately as volumes were increased late in the year by expansions of pipeline and plant facilities to take advantage of increasing DJ Basin production. Other income for 1992 decreased 26% to $4.2 million from a reduction in gains on sales of securities and lower interest on notes receivable.
Direct operating expenses including production taxes increased only 13% during 1992 as the operating cost per equivalent barrel decreased to $4.99 from $5.47 in 1991, due to increased DJ Basin production where operating costs have been significantly lower than average. General and administrative expenses, net of reimbursements, for 1992 represented less than 6% of revenues compared to 8% in 1991, as revenues rose 30%. Interest and other expenses dropped 39% in 1992 due to lower average outstanding senior debt after the application of proceeds from a preferred stock offering in late 1991.
Development, Acquisition and Exploration
During 1993 the Company incurred $93.1 million for oil and gas property development and exploration, $51.0 million for acquisitions and $22.6 million for gas facility expansion and other assets, for a total of $166.7 million in property and equipment expenditures. Additionally, the Company made an $18.2 million investment in an Australian based exploration and production company.
The Company has concentrated a significant portion of its development activities in the DJ Basin of Colorado. Capital expenditures for DJ Basin development totalled $75.4 million during 1993. A total of 311 newly drilled wells were placed on production there in 1993 and 51 were in progress at yearend. Additionally, 42 recompletions were performed in 1993, with seven in process at yearend. In December 1993, 16 drilling rigs were in operation in the DJ Basin. The Company anticipates putting 500 or more wells per year on production in the DJ Basin for the next few years. With additional leasing activity and through drilling costs reductions that add infill locations as proven as they become economic, the Company has increased the inventory of available drillsites. In December, the Company entered into a letter of intent with Union Pacific Resources Corporation whereby the Company will gain the right to drill wells on UPRC's previously uncommitted acreage throughout the Wattenberg area. This transaction significantly increased the Company's undeveloped Wattenberg inventory. UPRC will retain a royalty and the right to participate as a 50% working interest owner in each well, and received grants for warrants to purchase two million shares of Company stock. Of the warrants, one million expire three years from the date of grant, and are exercisable at $25 per share, while the other one million expire in four years and are exercisable at $27 per share. One year from the date of grant (February 8, 1994), the exercise prices may be reduced to 120% of the average closing price of the Company stock for the preceding 20 consecutive trading days, but not to lower than an exercise price of $21.60 per share. At that time the expiration date of the warrants may also be extended one year if the average closing price over the 20 day trading period is less than $16.50 per share.
The Company expended $14.8 million for other development and recompletion projects and $2.9 million for exploration during 1993. In Nebraska, 29 wells were added to production in 1993 as an extension of a drilling program initiated in 1992. An additional 20 wells are planned in Nebraska for 1994. In southern Wyoming, 11 wells in the East Washakie Basin development program were successfully drilled and completed during the last half of 1993 with three in process at yearend. In this program, significant cost- cutting measures were applied based on the experience gained in the DJ Basin. In central Wyoming on the properties acquired from ARCO in late 1992, efforts have been focused on increasing operating efficiency with limited development drilling and workover activity. In 1993, three successful wells were drilled in the fourth quarter and selected development and recompletion activity is scheduled for 1994. In the Piceance Basin of western Colorado, a three well test program was started in December of 1993 on acreage acquired there during the year, with one well undergoing completion, the second in progress and a third scheduled for early 1994. Current plans include a minimum of 25 wells in the basin during 1994. In South Texas, a combined operated and non-operated program was initiated, with nine wells completed in 1993 and one well abandoned. A total of 25 additional horizontal locations have been identified and drilling should continue with as many as 15 wells planned in 1994. In its domestic exploration efforts, the Company initiated a seismic program in Louisiana and began drilling early in the fourth quarter. Advanced seismic techniques are being used to identify further prospects in Louisiana and expectations are to drill up to 20 wells in 1994.
A total of $51.0 million in domestic acquisitions were completed in 1993. In May 1993, the Company purchased an interest in 121 producing wells and over 70 drilling locations in the DJ Basin area for $3.3 million. In July, an incremental 25% interest in the Company's Barrel Springs and Duck Lake Fields in Wyoming was purchased for $6.1 million. The properties are 90% gas and include 44 producing wells and 46 undeveloped locations. In August, the Company acquired interests in 225 producing wells and 272 proved undeveloped locations in the DJ Basin for $19.7 million. The proved reserves are 70% gas with more than two-thirds requiring future development to produce. Late in the year, two acquisitions were completed in the Piceance and Uinta Basins of Western Colorado for a total of $12.5 million. The majority of the value was in undeveloped locations as only 128 wells were currently producing. Numerous other producing and undeveloped acquisitions totalling $9.4 million were completed, mostly in or close to the Company's principal operating areas.
The Company's gas gathering and processing facilities have been undergoing significant transformation since late 1992. In 1993, the Company expended $20.1 million to further develop its gas related assets. The Company spent $9.4 million toward the second phase of its DJ Basin gathering expansion to construct a high pressure line to deliver gas directly to the major gas processing plant in the area and expand its gathering network for the increased drilling activity. An additional $2.6 million was expended to expand the Roggen Plant for the production increases. A total of $5.6 million in additional transportation and gathering facilities were constructed in the DJ Basin including a nine mile 16" interconnect line completed in October to relieve high line pressures, a 20" western gathering extension and numerous other extensions and connections. A gathering system that delivers third party gas to the Roggen Plant was purchased for $703,000. The Company expended $1.4 million to complete construction of a system to gather gas from its Nebraska drilling project. These projects are intended to take advantage of the significant increase in drilling activity in these areas.
In the international arena, progress continues as well. In May 1993, the Company acquired 42.8% of the outstanding shares of Command Petroleum Holdings N.L., an Australian exploration and production company, for $18.2 million. The Sydney based company is listed on the Australian Stock Exchange, and at December 31, 1993 had 950,000 barrels of proven oil reserves and $19.9 million of working capital. In addition, it holds interests in more than 20 exploration permits and licenses and a 28.7% interest in a Netherlands exploration and production company whose assets are located primarily in the North Sea. In Russia, the Permtex joint venture received central government approval in August and the Company executed a finance and insurance protocol with the Overseas Private Investment Corporation ("OPIC"), a United States government agency. Current plans call for 25 of the existing 45 shut-in wells to be placed on production in 1994, and that 400 development wells will be drilled over the next ten years. Extensive seismic work began in the fourth quarter of 1993 for 400 kilometers of data in Tunisia and 500 kilometers in Mongolia.
Financial Condition and Capital Resources
At December 31, 1993, the Company had total assets of $480 million and working capital of $1.3 million. Total capitalization was $412 million, of which 28% was represented by senior debt and the remainder by stockholders' equity. During 1993, the Company fully retired its $25 million of 13.5% subordinated notes and the related cumulative participating interests. During 1993, cash provided by operations was $68.3 million, an increase of 43% over 1992. As of December 31, 1993, commitments for capital expenditures totalled $7.5 million, primarily for DJ Basin drilling. The level of 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, proceeds from property dispositions and existing credit facilities. In addition, joint ventures or future public and private offerings of securities may be utilized.
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 October 1992, and at first payout in June 1993 the second contribution of $1.5 million was received. An additional $1.5 million was received in October 1993. This transaction should increase the Company's cash flow and net income through 1994. 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 $3.8 million of this revenue during 1993. Discussions are in progress to expand this transaction so that the benefits would be extended through at least 1996.
In April 1993, the Company sold 4.1 million depositary shares (each representing a one quarter interest in one share of $100 liquidation value stock) of convertible preferred stock through an underwriting for $103.5 million. A portion of the net proceeds of $99.3 million was used to retire the entire outstanding balance under the revolving credit facility at that time. The preferred stock pays a 6% dividend and is convertible into common stock at $21.00 per share. At the Company's option, the preferred stock is exchangeable into 6% convertible debentures on any dividend payment date on or after March 31, 1994. The stock is redeemable at the option of the Company on or after March 31, 1996.
Effective July 1, 1993, the Company renegotiated its bank credit facility and increased it from $150 million to $300 million. The new facility is divided into a $50 million short-term portion and a $250 million long-term portion that expires on December 31, 1997. However, management's policy is to renew the facility annually. Credit availability is adjusted semiannually to reflect changes in reserves and asset values. At December 31, 1993, the elected borrowing base was $150 million. The majority of the borrowings currently bear interest at LIBOR plus 1.25% with the remainder at prime. The Company also has the option to select CD plus 1.375%. 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. Based on such limitations, $86.5 million would have been available for the payment of dividends and other restricted payments as of December 31, 1993. The Company does not currently plan to make, and is not committed to make, any advances or contributions to unrestricted subsidiaries that would materially affect its ability to pay dividends under this limitation.
During 1993, the Company fully retired its $25.0 million of 13.5% subordinated notes and the related cumulative participating interests. An extraordinary charge to earnings of $1.9 million (net of income taxes) was made in 1993, representing the amount paid in excess of principal and accrued interest through the retirement dates. These notes were retired early in order to reduce the Company's ongoing cost of debt.
The Company maintains a program to divest marginal properties and assets which do not fit its long range plans. For 1992 and 1993, proceeds from these sales were $3.0 million and $5.5 million, respectively. Included in the 1993 proceeds were $4.0 million of cash receipts previously accrued for late 1992 sales. The Company intends to continue to evaluate and dispose of nonstrategic assets.
In 1990, the Company was granted a judgment in litigation regarding a leasehold assignment from the early 1980's. The Oklahoma Supreme Court refused certiorari and the judgment was upheld. As a result, a total of $1.7 million was accrued and reported in other income in 1993. The full amount was collected in January 1994. In April 1992, a jury found for the plaintiffs in a gas contract dispute related to an offshore property. In April 1993, the dispute was settled by an agreement to pay the Company a net of $5.3 million. The initial $3.5 million was received and reflected as other income in second quarter 1993. The remaining $1.8 million was received in third quarter 1993, but reflected as a reserve for possible contingencies. 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 financial statements reflect these judgments only upon receipt of cash or final judicial determination.
The Company believes that its capital resources are more than 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. While such fluctuations have had, and will continue to have a material effect, the Company is unable to predict them.
The following table indicates the average oil and gas prices received over the last five years and highlights the price fluctuations by quarter for 1992 and 1993. Average gas prices exclude the Thomasville gas production. During 1993, the Company renegotiated its Thomasville gas contract and beginning in January 1994, the Company will receive a somewhat higher than market price for its Thomasville gas sales, significantly below its 1993 average price of $12.16 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. Equivalent prices prior to 1993 have been restated to reflect elimination of the conversion of Thomasville gas volumes based on its price relative to the Company's other gas production.
In December 1993, the Company was receiving an average of $12.54 per barrel and $2.27 per Mcf (excluding the Thomasville contract) for its production. Beginning in December 1992, the average oil price was effectively reduced by the oil production added from the Wyoming acquisition, which sells at a significant discount to West Texas Intermediate posting due to the presence of low gravity sour crude in two of the fields.
ITEM 8.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Reference is made to the Index to Financial Statements on page 35 for financial statements and notes thereto. Supplementary schedules are presented at the end of Part III following page 55. Quarterly financial data is presented on page 28 of this Form 10-K. Schedules I, III, IV, VII, VIII, IX, XI, XII, and XIII 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.
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 1992, 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, 1993. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules 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 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
As explained in Note 7 to the financial statements, effective January 1, 1992, the Company changed its method of accounting for income taxes.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the index to financial statements and schedules are presented for purposes of complying with the Securities and Exchange Commission's rules and are not a part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Forth Worth, Texas February 25, 1994
LIABILITIES AND STOCKHOLDERS' EQUITY
SNYDER OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Snyder Oil Corporation (the "Company") is engaged in the acquisition, production, development and to a lesser degree exploration of primarily domestic oil and gas properties. The Company is also involved in gas processing, transportation, gathering and marketing. The Company, a Delaware corporation, is the successor to a company formed in 1978. 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.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements include the accounts of Snyder Oil Corporation and its subsidiaries (collectively, the "Company"). 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.
The Company follows the "full cost" accounting method. All costs of exploration and development are capitalized as incurred. Depletion, depreciation and amortization ("depletion") is provided on the unit-of-production method based on proved reserves. Gas is converted to equivalent barrels at the rate of six Mcf per barrel. The depletion rates per equivalent barrel produced were $4.68, $4.79 and $4.75, respectively, in 1991, 1992 and 1993. In 1993, the practice of converting Thomasville production to equivalent quantities based on its price relative to other gas production was discontinued. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed. Expenditures which enhance the value of the properties are capitalized. Depreciation on gas processing and transportation facilities is generally provided on a straight-line basis over 15 years.
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 received. The affiliate's functional currency is the Australian dollar. The reported foreign currency translation adjustment is the result of the translation of the Australian balance sheet into United States dollars at year-end and the related impact of exchange rates subsequent to purchase.
All highly liquid investments with a maturity of three months or less are considered to be cash equivalents. Earnings per share are computed based on the weighted average number of common shares outstanding. Differences between primary and fully diluted earnings per share were insignificant for all periods presented. General and administrative expenses are reduced by reimbursements for well operations, drilling and management of partnerships. Reimbursements amounted to $11.1 million, $14.3 million and $17.8 million, respectively, in 1991, 1992 and 1993.
Certain amounts in the 1991 and 1992 financial statements have been reclassified to conform with the 1993 presentation.
(3) INDEBTEDNESS
The following indebtedness was outstanding on the respective dates:
The Company maintains a $300 million revolving credit facility. The facility is divided into a $250 million long-term portion and a $50 million short-term portion. However, management's policy is to renew the facility annually. The elected borrowing base available under the facility at December 31, 1993 was $150 million. The majority of the borrowings currently bear interest at LIBOR plus 1.25% with the remainder at prime. During 1993, the average borrowing cost was 4.9%. The Company pays certain fees based on the borrowing base and outstanding loans. 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. At December 31, 1992, the Company recorded the $49.8 million Wyoming acquisition commitment as other senior debt. The cash flow statement did not reflect the commitment as an increase in indebtedness until final payment was disbursed in February 1993.
The subordinated notes bore interest at 13.5% and were due in four annual payments commencing November 15, 1993. The notes were subject to optional redemption at 102% of principal after November 1994 and at par after November 1995. Cumulative rights to receive additional interest based on net cash flow above certain minimum levels were issued in connection with the notes. Cash flow has substantially exceeded the minimum since 1991, and the Company has since made the maximum payments. At December 31, 1992, based on existing market rates the subordinated notes and cumulative interest rights had a combined fair value of $27.7 million, which the Company believes approximated its cost of funds for notes with similar terms. In March 1993, the Company retired 40% of the cumulative rights. The portion of the payment representing prepaid interest was expensed as an extraordinary item, net of income taxes, for $384,000. In August 1993, the Company retired $10 million (40%) of the subordinated notes. The portion of the payment representing prepaid interest was expensed as an extraordinary item, net of income taxes, for $462,000. In November 1993, the Company retired the remaining $15 million of the subordinated notes and the related 60% of cumulative rights, with the portion of the payment representing prepaid interest expensed as an extraordinary item, net of income taxes, for $1.1 million. The Company expensed $1.1 million, $1.1 million and $516,000 as interest expense for cumulative rights in 1991, 1992 and 1993, respectively.
Scheduled maturities of indebtedness are $15,000 for 1994, $17,000 for 1995 and 1996, and $114.9 million in 1997. The long-term portion of the revolving credit facility is scheduled to expire in 1997; however, management's policy is to renew the facility annually.
Cash payments for interest expense were $7.9 million, $5.4 million and $9.2 million, respectively, for 1991, 1992 and 1993.
(4) INVESTMENTS
The Company has investments in foreign and domestic energy companies and notes receivable, which at December 31, 1992 and 1993, had a total book value of $7.4 million and $29.4 million, respectively, with corresponding fair market values of $9.8 million and $54.2 million.
In May 1993, the Company acquired 92 million (42.8%) of the outstanding shares of Command Petroleum Holdings N.L. ("Command"), an Australian exploration and production company, for $18.2 million. The Sydney based company is listed on the Australian Stock Exchange, and holds interests in more than 20 exploration permits and licenses as well as a 28.7% interest in a publicly traded Netherlands exploration and production company whose assets are located primarily in the North Sea. The market value of the Company's investment in Command based on Command's closing price at December 31, 1993 was $39.1 million. The investment is accounted for by the equity method. Command has outstanding stock options covering the issuance of up to 53.3 million common shares that expire November 30, 1994. Given that the exercise price of the options is 44% below the year-end stock price, the Company assumes they will be exercised. In January 1994, Command completed an offering of 43 million of its common shares. As a result of this offering, the Company's ownership was reduced to 35.7%. If, as expected, all of the November 1994 options were exercised, the Company's ownership would be reduced to 29.6%.
The Company has investments in securities of publicly traded domestic energy companies, not accounted for by the equity method, having a book value and total cost at December 31, 1992 and 1993 of $680,000 and $9.7 million, respectively. The market value of these securities at December 31, 1992 and 1993 approximated $2.9 million and $13.3 million, respectively. In the first quarter of 1994, the Company will be required to adopt SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." Under the provisions of SFAS No. 115, at December 31, 1993 the Company would have increased its investments by $3.6 million and increased stockholders' equity by $2.3 million and deferred tax liability by $1.3 million.
The Company holds $1.8 million in notes receivable due from privately held corporations. All notes are secured by certain assets, including stock and oil and gas properties. At December 31, 1992 and 1993, the fair value of the notes receivable, based on existing market conditions and the anticipated future net cash flow related to the notes, was believed to be equal to their book value.
(5) OIL AND GAS PROPERTIES
The cost of oil and gas properties at December 31, 1992 and 1993 includes $4.0 million and $9.8 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:
In December 1992, the Company acquired certain producing properties located in north central Wyoming from a major oil company for $56.1 million. An initial cash payment of $6.3 million was made in December 1992. The remaining $49.8 million was recorded as senior debt on the consolidated balance sheet at December 31, 1992, but not reflected on the Company's cash flow statement as an acquisition until payment was made in February 1993. Costs incurred above also differ from the cash flow statement as a result of certain cost recoveries and accrual items. The remaining 1992 acquisitions were primarily for producing properties in Wyoming, North Dakota and Texas. In May 1993, the Company purchased an interest in 121 producing wells and over 70 drilling locations in the DJ Basin of Colorado for $3.3 million. In July 1993, an incremental 25% interest in the Company's Barrel Springs and Duck Lake Fields was purchased for $6.1 million. In August 1993, the Company acquired interests in 225 producing wells and 272 undeveloped locations in the DJ Basin for $19.7 million. In late 1993, two acquisitions were completed in the Piceance and Uinta Basins of Western Colorado for a total of $12.5 million. A number of other producing and undeveloped acquisitions totalling $9.4 million were completed during 1993 as well, mostly in or close to the Company's principal operating areas. In late 1992, the Company initiated projects to further develop its gas gathering and processing facilities. A $4.5 million DJ Basin low pressure gathering system expansion was completed to provide new sources of inlet gas to the Roggen plant. Simultaneously, a $2.0 million expansion at Roggen raised plant capacity by 60% to 55 MMcf per day. An additional $848,000 was expended in 1992 to acquire a Roggen net profits interest and a pipeline in the area. In 1993, the Company expended $9.4 million toward the second phase of its DJ Basin gathering expansion to construct a high pressure line to deliver gas directly to the major gas processing plant in the area and expand its gathering network for the increased drilling activity. A total of $5.6 million in additional transportation and gathering facilities were constructed in 1993 in the DJ Basin including a nine mile 16" diameter interconnect line completed in October to relieve high line pressures, a 20" diameter western gathering extension and numerous other extensions and connections. In 1993, the Roggen plant was further enhanced with $2.6 million of capital expenditures. The Company expended $1.4 million to complete construction of a system to gather gas from its Nebraska drilling project. A number of lesser facilities were purchased in 1993 to expand the Company's gathering and processing capabilities in its active hub areas.
Acquisitions are accounted for utilizing the purchase method. The following unaudited pro forma information shows the effect on the consolidated statements of operations assuming that the 1992 significant acquisitions were consummated as of January 1, 1992. Individual 1993 acquisitions did not meet the significance test, therefore no 1993 pro forma information is presented. Future results may differ substantially from pro forma results due to changes in oil and gas prices, production declines and other factors. Therefore, pro forma statements cannot be considered indicative of future operations.
(6) STOCKHOLDERS' EQUITY
A total of 75 million common shares, $.01 par value, are authorized of which 23.3 million were issued and outstanding at December 31, 1993. In 1992, the Company issued 234,000 shares and repurchased 215,000 shares. 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. The Company made five quarterly dividend payments of $.05 per share in 1992 due to an acceleration in the quarterly payment date. In 1993, the Company paid first and second quarter dividends of $.05 per share and increased dividends to $.06 per share in the third and fourth quarters.
A total of 10 million preferred shares, $.01 par value, are authorized. In December 1991, 1.2 million shares of convertible exchangeable preferred stock were sold through an underwriting. The net proceeds were $57.4 million. The preferred stock carries an 8% dividend and is convertible into common stock at $9.07 per share. The stock is exchangeable at the option of the Company for 8% convertible subordinated debentures on any dividend payment date. The stock is redeemable at the option of the Company on or after December 31, 1994. The liquidation preference is $50.00 per share, plus accrued and unpaid dividends. During 1995, the stock is redeemable at $52.50 per share if the closing price exceeds 150% of the prevailing conversion price (currently $13.61 per share) for 20 of the preceding 30 trading days. After 1995, no minimum stock price is required. The redemption price declines $.50 per year to $50.00 per share in 2000. In 1993, 14,000 preferred shares were converted into 77,000 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 convertible preferred stock were sold through an underwriting. The net proceeds were $99.3 million. The preferred stock carries a 6% dividend and is convertible into common stock at $21.00 per share. The stock is exchangeable at the option of the Company for 6% convertible subordinated debentures on any dividend payment date on or after March 31, 1994. The 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 $4.8 million and $9.1 million, respectively, in preferred dividends during 1992 and 1993.
The Company maintains a stock option plan for Company employees providing for the issuance of options at prices not less than fair market value. Options to acquire up to 3 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, 1993, 1.4 million options were outstanding under both plans at exercise prices of $4.53 to $19.25 per share. At December 31, 1993, a total of 600,000 of such options were vested having exercise prices of $4.53 to $13.00 per share. During 1992, 223,000 options were exercised at prices of $3.02 to $6.00 per share, and 52,000 were forfeited. During 1993, 309,000 options were exercised at prices of $4.53 to $9.13 per share, and 23,000 were forfeited.
(7) FEDERAL INCOME TAXES
The Company adopted FASB Statement No. 109, "Accounting for Income Taxes," effective January 1, 1992. Net income for 1992 was increased by $3.8 million for the cumulative effect of the change in method of accounting for income taxes as a result of tax basis in excess of financial basis. At December 31, 1993, 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 Company's net deferred asset and liability at December 31, 1992 and 1993, respectively, were:
For tax purposes, the Company had net operating loss carryforwards of $69.1 million at December 31, 1993. These carryforwards expire between 1997 and 2008. At December 31, 1993, the Company had alternative minimum tax credit carryforwards of $1.4 million and depletion carryforwards of $1.1 million, both of which are available indefinitely. Current income taxes shown in the financial statements reflect estimates of alternative minimum taxes due. Cash payments during 1992 and 1993 were $1.0 million and $75,000, respectively.
(8) SALES TO MAJOR CUSTOMERS
In 1991, 1992 and 1993, Amoco Production Company accounted for 17%, 27% and 12%, 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 October 1992, and at first payout in June 1993 the second contribution of $1.5 million was received. An additional $1.5 million was received in October 1993. 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 of this revenue during 1992 and $3.8 million during 1993.
(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 $2.1 million for 1994, $2.2 million for 1995, $2.3 million for 1996 and 1997, and $2.1 million for 1998.
In 1990, the Company was granted a judgment in litigation regarding a disputed leasehold assignment from the early 1980's. The Oklahoma Supreme Court refused certiorari and the judgment was upheld. As a result, a total of $1.7 million was accrued and reported in other income in 1993. The full amount was collected in January 1994. In April 1992, the Company was granted a judgment in a gas contract dispute related to an offshore property. The dispute was settled in April 1993 by an agreement to pay the Company a net of $5.3 million. The Company received theses monies in 1993 and reflected $3.5 million as other income with the remaining $1.8 million recorded as a liability for possible contingencies. 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 or final judicial determination.
(11) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION:
Independent petroleum consultants directly evaluated 51%, 74%, and 62% of proved reserves at December 31, 1991, 1992 and 1993, 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.
PART III
ITEM 10.



ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
*
ITEM 11.

ITEM 11. MANAGEMENT AND REMUNERATION
*
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
*
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
*
*The information required in these four items is incorporated by reference to the Company's definitive Proxy Statement for its 1994 Annual Meeting of Stockholders, which will be filed with the SEC no later than April 30, 1994.
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 beenomitted 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 to the Registrant's Registration Statement on Form S-4 (Registration No.33-33455).
4.1.3 - Certificate of Amendment to Certificate ofIncorporation of Registrant filed May 22, 1991 -incorporated by reference from Exibit 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 ofIncorporation 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 - Certificate of Designations, Powers, Preferences and Rights of the Registrant's $4.00 Convertible Exchange Preferred Stock - incorporated by reference from Exhibit 3.1.3 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1991 (File No.1-10509).
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 nonemployee Directors - incorporated by reference from Exhibit 10.4 to the 	 Retistrant's Registration Statment 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 Quartly Report on Form 10-Q for the quarterended 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 - SOCO Holdings Inc. 1984 Stock Option Plan -incorporated by reference from Exhibit 10.6 to the Registrant's Registration Statement of Form S-4 (Registration No. 33-33455).
10.3.1 - Amendment to SOCO Holdings Inc. 1984 Stock Option Plan dated July 18, 1985 - incorporated by reference from Exhibit 10.6.1 to the Registrant's Registration Statement on Form S-4 (Registration No. 33-33455).
10.3.2 - Amendment to SOCO Holdings Inc. 1984 Stock Option Plan dated May 24, 1988 - incorporated by reference from Exhibit 10.6.2 to the Registrant's Registration Statement on Form S-4 (Registration No. 33-33455).
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 Quartly Report on Form 10-Q forthe 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.*
10.9 - Purchase and Sale Agreement dated December 11, 1992 between Atlantic Richfield Company and Registrant - incorporated by reference to the Report on 8-K dated December 11, 1992 (File No. 1-8440).
10.10 - Warrant dated February 8, 1994 issued by Registrant to Union Pacific Resource Company.*
11.1 - Computation of Per Share Earnings.*
22.1 - Subsidiaries of the Registrant - incorporated byreference 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 & Co.*
23.2 - Consent of Netherland, Sewell & Associates, Inc.*
28.1 - Report of Netherland, Sewell & Associates, Inc. dated February 10, 1994 relating to certain of the Registrant's property interest.*
28.2 - 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 1993
* Filed herewith.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused the report to be signed on its behalf by the undersigned thereunto duly authorized.
/s/ John C. Snyder Director and Chairman of the Board John C. Snyder (Principal Executive Officer) March 11, 1994
/s/ Thomas J. Edelman Director and President Thomas J. Edelman Principal Financial Officer) March 11, 1994
/s/ John A. Fanning Director and Executive John A. Fanning Vice President March 11, 1994
/s/ Roger W. Brittain Director Roger W. Brittain March 11, 1994
/s/ John A. Hill Director John A. Hill March 11, 1994
/s/ B. J. Kellenberger Director B. J. Kellenberger March 11, 1994
/s/ John H. Lichtblau Director John H. Lichtblau March 11, 1994
/s/ James E. McCormick Director James E. McCormick March 11, 1994
/s/ Alfred M. Micallef Director Alfred M. Micallef March 11, 1994
/s/ James H. Shonsey Vice President and Controller James H. Shonsey Principal Accounting Officer) March 11, 1994