ITEM 1. BUSINESS General
Foreland Corporation (the "Company") was organized in June 1985 to advance an exploration project in the Great Basin and Range geologic province in Nevada (the "Great Basin") that had been initiated by Gulf Oil Corporation ("Gulf"). Following its organization, the Company acquired rights to a geologic data base, assembled a management team with supporting consultants, obtained funding from a private placement and its initial public offering, and commenced the field geology phase of its exploration project.
The Company's field geology identified an oil source rock and porosity fairway in north and central Nevada in which the Company has concentrated its lease acquisition and exploration program. The Company has funded its exploratory drilling through arranging its own funding and obtaining funding from industry participants that agree to complete specified drilling or other exploration in order to earn an interest in an agreed area. Since 1986, the Company has identified a number of drilling targets in Pine Valley and other areas of Nevada and arranged Company and third-party funding for drilling a number of test wells.
To help fund future activities, in 1993 and 1994, the Company acquired nine shut-in wells in the Eagle Springs Field in Nevada. The Company then returned eight of these acquired wells to production and drilled a new water injection well. In August 1994, the Company entered into an agreement with Plains Petroleum Operating Company, which was acquired in August 1995 by Barrett Resources Corporation (together, "Barrett"), to fund further activities in the Eagle Springs Field. In September 1994, the Company and Barrett acquired an additional Eagle Springs lease with three previously producing wells, which have since been reworked and returned to production, and a shut-in water injection well. Pursuant to its agreement with the Company, Barrett provided $1,920,000 of $2,400,000 in well costs and thereafter, in January 1995, elected to continue to participate in the Company's Eagle Springs project, thereby earning a 40% working interest in the Company's Eagle Springs producing properties, subject to the right to make individual elections respecting participating in specific wells as they are proposed. As of March 31, 1996, the Company and Barrett have drilled and placed into production a total of eight new wells in the Eagle Springs Field, all of which are now in regular continuous production. The Company and Barrett plan to drill additional wells to test horizons productive in existing wells in a further effort to increase production.
The Company continues to increase and improve its geological and geophysical expertise respecting the Great Basin of Nevada through its own efforts and by obtaining data from third parties as part of joint exploration, property acquisition, or data sharing arrangements and from drilling and other field work in which the Company participates. In addition, all information is continuously reanalyzed as additional drilling data is gathered and as new computer modeling and other analytical tools become available to the industry. This has enabled the Company to increase substantially its understanding of the geology, location, potential, and other characteristics of the exploration process.
Nevada Exploration
During the early 1980s, the Great Basin of Nevada emerged as a possible new frontier area for oil exploration. Conventional wisdom in the oil industry at the time held that certain geological indicators pointed to north and central Nevada as a possible repository of large (by continental United States standards) petroleum deposits. Several of the nation's largest exploration companies, including Exxon USA, Inc. ("Exxon"), Texaco, Inc., Gulf, Chevron USA, Inc. ("Chevron"), Mobil Exploration and Producing USA, Inc. ("Mobil"), and Amoco Corp. ("Amoco"), acquired substantial lease holdings and initiated exploration programs in eastern and central Nevada during the early years of the decade.
Between 1980 and 1983, Gulf conducted a detailed study of the hydrocarbon potential of north and central Nevada and other frontier exploration areas. The study, conducted by Gulf personnel and by outside consultants, generated a mass of raw data pertaining to the age and depositional history of potential oil-bearing formations. In 1983, Gulf became the target of a takeover attempt by Mesa Petroleum and subsequently was acquired by Chevron. In connection with that acquisition, a number of Gulf's exploration projects were terminated, including the study of Nevada.
The acquisition of Gulf by Chevron also led to the voluntary retirement of a number of Gulf employees. One such retiree was Dr. Grant Steele, who had been manager of geology for Gulf's central exploration group and was intimately involved with the study of the Great Basin of Nevada.
Personal and professional interest in the potential of the Great Basin of Nevada continued after his early retirement from Gulf in 1983. In 1985 Dr. Steele organized the Company and recruited Kenneth L. Ransom, who had served under Dr. Steele as a senior geologist with Gulf's central exploration group and who had also been deeply involved with Gulf's study of the Great Basin of Nevada.
The Company's goal is to secure a significant position in a potential new oil province. In order to implement this plan, the Company acquired rights to Gulf's data base, conducted additional geological survey work, acquired oil and gas lease holdings in north and central Nevada, and arranged for the exploration and development of its acreage. Virtually all of the Company's financial resources were committed from the outset to this goal.
Business Strategy The Company has assembled a management and technical team of persons with specialized technical training and experience concentrated on Nevada oil exploration. In all, the Company's technical team has over 70 years of combined Nevada oil exploration experience with major oil companies such as Gulf, Mobil, and Chevron. The Company believes that the working experience of its executives in Nevada is a significant factor in the Company's exploration progress to date and in its ability to act as operator under exploration arrangements with other exploration firms such as Enserch Exploration, Inc. ("Enserch"), Berry Petroleum Company ("Berry"), Parker and Parsley Petroleum Company (successor-in-interest to Santa Fe Energy Resources, Inc.) ("P&P"), and Barrett. This team employs the following strategies in guiding the Company's Nevada exploration:
. Take full advantage of the most advanced generally available scientific exploration tools and techniques such as 3-D and reprocessed seismic data to generate drilling prospects and select specific drilling locations. . Generate promising exploration prospects in areas in which the Company holds or believes that it can acquire a preemptive lease position and upgrade lease holdings based on further prospect evaluation. . Seek joint exploration agreements with other exploration firms active in Nevada to diversify the risk and to obtain additional scientific data and expertise, land, and funding. . To increase revenues by drilling in the Eagle Springs Field to develop proven reserves and to test horizons productive in existing wells. . Continually generate prospect concepts for the long-term exploration of the Great Basin.
Science
The Company seeks to utilize the most advanced available scientific tools and techniques to evaluate the risk and exploration potential of specific prospects. The Company's oil exploration model for the Great Basin of Nevada was developed from a large data base collected, originally by Gulf and, since 1985, by the Company. As a result of the Company's own work as well as information sharing arrangements with others, the Company now has access to over 1,400 line miles of 2-D seismic data, much of it reprocessed with new analytical computer programs, newly acquired high resolution 3-D seismic surveys, and gravity data gathered by the Company as well as by Exxon, P&P, Mobil, Chevron, Enserch, and Berry. Data from 3-D seismic, gravity, reprocessed seismic surveys, and previous drilling are integrated as a guide to further exploration. The Company believes that it benefits from the long-term involvement of the Company's personnel in Nevada oil exploration and operations, which enhances the Company's ability to share data and expertise with industry participants.
Prospect Generation and Leasing
The Company's leasing program is coordinated with prospect generation and exploration results. As areas of interest are identified, the Company attempts to acquire leases or other exploration rights on what preliminarily appears to be the most promising prospect areas in order to establish a preemptive lease position prior to generating a specific drilling prospect. As specific prospect evaluation advances, the Company may seek leases on additional areas or relinquish leases on areas that appear less promising, thereby reducing lease holding costs. As a result, the Company has substantially increased the size of its gross acreage while, in management's opinion, improving the exploration potential of its leaseholdings.
Joint Exploration
The Company regularly seeks joint exploration arrangements with other oil exploration firms active in Nevada to obtain access to additional scientific data and technical expertise, particularly relatively expensive geophysical data, including 3-D seismic. Joint exploration arrangements are sought with firms that have significant lease positions in the prospect area and that can bear a portion of the costs of specified further exploration. The Company also utilizes joint exploration arrangements to spread the risks of specific exploration, attempting to retain a larger interest by bearing a greater proportion of the related costs in those prospect areas in which management believes that the risks and reserve potential warrant such action. In situations in which management perceives a higher degree of risk or a smaller potential for the prospect, it seeks to retain a smaller interest and bear a smaller share of related costs.
Drilling Near Existing Production
Further exploration drilling is required to delineate the extent of productive horizons in individual fields and complete development where warranted. In the Eagle Springs Field, the Company's geophysical and geological evaluation is ongoing to locate possible additional drilling locations to develop the undeveloped reserves and to test the horizons that are productive in the existing wells. The Company has surface facilities capable of handling additional production. The Company also intends to continue to drill exploration wells in the area of existing production in the Pine and Railroad Valleys to further evaluate reservoir extent and characteristics, increase production, and obtain data that might benefit the Company's overall exploration effort. The Company intends to pursue these drilling objectives in Pine Valley as well as specific prospects in Railroad Valley as involving somewhat lower risk than exploration testing in areas with relatively less drilling history or other exploration success to date.
Long-Term Exploration
Management anticipates that it will take several years to explore fully the target areas selected by the Company in the Great Basin of Nevada, as is the case in many frontier areas of exploration, and believes that it is important to provide for an ongoing presence for the Company in Nevada exploration. In such a long term exploration effort, the results of early exploration serve as a guide for identifying new prospects so it is important, in management's view, to continually identify new prospect concepts and areas for possible future exploration while advancing existing prospects to the drilling stage.
Through 1996, the Company will focus its activities on drilling in the Eagle Springs Field to develop proved undeveloped reserves and to evaluate the horizons that are productive in existing wells and in several additional exploratory prospects in the Pine, Railroad, and Huntington Valleys and Toano Draw of Nevada. In addition, the Company will continue to review the exploration potential of certain acreage under its agreement with P&P, as discussed below, and continue its acquisition of 3-D seismic data and reanalysis of existing 2-D seismic data. The Company will also continue its evaluation of data to identify additional exploration targets, expand its lease holdings where warranted, and seek additional exploration arrangements with other industry participants.
Joint Exploration Agreements
Enserch/Berry Operating Agreement
Effective March 1993, the Company entered into an operating agreement with Enserch, Dallas, Texas, and Berry, Taft, California, independent oil exploration and production firms active in Nevada (collectively, "Enserch/Berry"), to undertake a three-year, six-well joint exploration program on approximately 110,000 gross leased acres in Pine, Diamond, Little Smoky, and Antelope Valleys of northeastern Nevada. The Company is designated as the operator for the proposed drilling as well as other activities under the agreement. The Company and Enserch/Berry each contributed approximately 50% of the gross acreage and will share, on the basis of the Company 50% and Enserch/Berry 50%, in the costs of additional lease acquisition, geophysical exploration and drilling, and in the net revenues from oil produced.
The parties have identified four areas of mutual interest covering an aggregate of 500,000 acres, in which are located the 91,000 gross leased acres held during 1995. Through 1994, the parties drilled three test wells, one each in the Pine, Little Smoky, and Antelope Valleys, all three of which were dry holes that were plugged and abandoned. During 1995, the parties drilled the Hot Creek Wash test in Antelope Valley, and the Eldorado #15-1 test in Little Smoky Valley. Both tests were plugged and abandoned. The remaining well under the arrangement with Enserch/Berry, the Pinon prospect in Pine Valley, is planned to be drilled during 1996, subject to obtaining required financing. (See "Exploration Status.")
In addition to the six required wells, during the term of the agreement any party has the right to propose additional wells to explore new prospects or develop discoveries. The joint exploration program continues to May 1, 1996, at which time the acreage in Diamond Valley contributed by Foreland to the joint arrangement is returned to Foreland. The balance of the acreage and the designated acreage surrounding wells that have then been drilled under the joint arrangement remain subject to the operating agreement. If the results of the initial exploration warrant and the parties agree to proceed with additional joint exploration, the proposed exploration of the area subject to this agreement may take several years to complete.
Rustler Prospect
On September 28, 1994, the Company entered into an agreement with Mobil under which the Company had the right to commence one test well on or before September 1, 1995, on the Rustler Prospect located in White Pine County, Nevada. The Company elected not to commence such well and has no further rights or obligations under the agreement. P&P Marketing and Exploration Agreement
In December 1992, the Company entered into a three year exploration agreement, subsequently extended to December 1, 1996, with P&P's predecessor-in- interest, appointing the Company the exclusive marketing representative for P&P's fee mineral interest in northern Nevada. The Company delineates exploration areas, defines prospects, and secures drilling partners utilizing the Company's and P&P's combined geological and geophysical data base. The Company has generated five drillable prospects affecting the P&P lands in the North Humboldt and Dixie Flats prospects in Huntington Valley and the Deadman Creek and Medicine Creek prospects in Toano Draw and the Pine Creek prospect in Pine Valley. If drilling is undertaken, the Company and P&P will each retain certain rights and interest in the drilling and development of identified prospects within the lands covered by the exploration agreement.
Under the terms of the exploration agreement, the Company has access to P&P's proprietary geological and geophysical data respecting the P&P properties and adjacent lands, with the express right to reprocess seismic data, utilizing improved analytical techniques and control data now available. If the Company elects to gather or to purchase additional geological or geophysical data for a mutually agreed exploration area, P&P is precluded from granting third parties exploration rights to such exploration area for one year. P&P has certain rights of access to the data developed by the Company on the P&P property.
On any drillings of P&P lands arranged by the Company, P&P and the Company will share in lease bonuses, the right to acquire a working interest by paying a portion of drilling and completion costs on any successful well, and overriding royalties, with the option to convert the overriding royalties to working interests in certain circumstances. The Company and P&P have a right of first refusal to participate in any drilling prospects generated by the other during the term of the exploration agreement.
The Company is required to release the remaining 434,000 acres subject to the P&P agreement by December 1996, when the agreement expires, subject to any specific acreage subject to leases, farmouts, or other arrangements reached under the agreement with the Company. The Company will review the P&P acreage with a view towards identifying the most promising prospects and reaching drilling arrangements by December 1996. Originally, the agreement required the Company to release the acreage by December 1995, but P&P and the Company agreed to extend the expiration date to permit further evaluation of the properties by the Company.
As a result of the Company's review of the P&P acreage, the Company identified an exploration target in the Deadman Creek area of Toana Draw based on the Company's review of available data regarding a test drilled by another operator in the mid 1980s that encountered favorable oil shows but was not completed for production. The Company has reentered this hole for testing and, if warranted, will attempt recompletion of the well using modern completion technologies. As a result of this reentry, the Company will earn a 100% working interest in 5,013 gross acres (4,261 net acres) under the P&P agreement, subject to P&P's 15% working interest in each well after the Company has recouped costs incurred.
North Humboldt Prospect
Under the agreement with the Company discussed below, after the first three new Eagle Springs wells were placed into production in January 1995, Barrett exercised its right to earn an interest in the Company's acreage in an area of mutual interest in the North Humboldt prospect included in the P&P acreage. The Company and Barrett are undertaking a joint technical evaluation of the seismic data to select a drillsite. Upon the completion of any geophysical studies that the parties deem necessary and review of the data obtained, the parties will select a drillsite and proceed to drill, with Barrett bearing two-thirds of the cost of the initial well in each area to earn a one-half interest in the Company's acreage within the prospect area.
Hugoton/Maxwell Agreement
On January 22, 1996, the Company entered into a revised agreement with Hugoton Energy Corporation and Maxwell Petroleum, Inc. ("Hugoton/Maxwell"), respecting exploration of the Pine Creek prospect in Pine Valley, Nevada. Under this agreement, the Company and Hugoton/Maxwell each agreed to assign to the other certain acreage to consolidate the Company's position in the prospect area; Hugoton/Maxwell agreed to pay for a one-year extension of the leasehold assigned by it; the Company agreed to initiate a well on the federal acreage assigned, in order to obtain a two-year lease extension; and Hugoton/Maxwell agreed to complete and pay for a 3-D seismic study in the area or pay the Company $75,000 as liquidated damages. If the Company does not initiate a test and obtain a two-year lease extension, Hugoton/Maxwell is not required to complete the seismic study or pay damages. The total estimated dry hole cost for the Pine Creek test is $664,000, which the Company would seek to share on a 50-50 basis with other drilling participants if a drilling group can be formed. If a drilling group cannot be formed on terms acceptable to the Company, it may not drill the test.
Other Exploration Arrangements
The Company is continuing to negotiate with other interested parties to fund further drilling on defined prospects in a number of locations in the Great Basin of Nevada. The ultimate goal of the Company is to arrange for the exploration and, if oil reservoirs are discovered, development of its holdings using the Company's own limited financing, to the extent available. In some instances, the Company may reach an agreement with other firms in which all participants contribute acreage and available scientific data and bear a portion of the costs of agreed drilling or other exploration, thereby earning a shared ownership in the contributed acreage and production, if any. The nature and extent of the Company's participation, share of costs, and interest retained in various arrangements are dependent on the acreage it has under lease in the target area, the amount of scientific information it has available as compared to the other participants, the relative financial strength of the participants, and the risks and rewards perceived by the various participants. These arrangements are very project specific and will vary from drilling prospect to drilling prospect.
Eagle Springs
In July 1993, the Company acquired an approximately 2,800 gross acre lease in Railroad Valley, Nevada, which included a portion of the Eagle Springs Field, with nine oil wells, then shut in, and one water injection well. In connection with the acquisition, the Company implemented certain in-field environmental remediation measures and resolved issues raised by various regulatory agencies and the claims of entities which asserted an ownership interest or had advanced funds or services to the field. In September 1994, the Company, with Barrett, acquired Kanowa's interest in a 240-acre lease on the remainder of the Eagle Springs Field with three wells with limited intermittent production and related equipment.
Wells drilled during the 1960s on the Eagle Springs property produced until late 1992 from depths of from 5,900 to 7,200 feet and had total cumulative production, as reported to the Nevada Department of Minerals, of 2,825,000 barrels of oil. The 14 wells drilled during development of the field between 1954 and 1965 reportedly had average per well daily production of approximately 150 barrels per day for the first year and approximately 100 barrels per day for the first three years of production. During the last 12 months that the wells acquired by the Company were in production, they produced an aggregate of approximately 120 barrels of oil per day.
In the year following acquisition of the Eagle Springs properties in July 1993, the Company completed substantial work and returned eight of the acquired wells in the Eagle Springs Field to production and drilled a water injection well. Under the agreement with Barrett discussed below, during 1994 and early 1995, the Company and Barrett drilled and placed into production three wells in the Eagle Springs Field. In January 1995, after these three wells were placed into production, Barrett elected to continue to participate in the Eagle Springs Field and in mid-1995, the Company and Barrett commenced the development drilling program in Eagle Springs based on the Company's own 3-D seismic study to develop additional production and evaluate at additional locations horizons that are productive in existing wells. The Company and Barrett have drilled and placed into production five additional wells of this program, for a total of eight new wells drilled by the Company and Barrett. According to the Company's year-end independent reserve report completed by Malkewicz Hueni Associates, Inc., Golden, Colorado, there are eight proved undeveloped drilling locations within the estimated perimeter of the Eagle Springs Field. A 3-D seismic survey has been completed on the field, and the 3-D seismic information continues to be evaluated and integrated with additional available drilling results as an ongoing guide for drilling. Initial evaluation of the 3-D seismic information provided the basis of the Company's decision to purchase Kanowa's interest in the 240-acre lease in the Eagle Springs field in September 1994. It is anticipated that the eight proved undeveloped locations identified in the reserve report will be scheduled to be drilled in 1996 and 1997, subject to available financing. As these locations are drilled, additional locations will be identified and evaluated for drilling in the Company's Eagle Springs program to the extent warranted by results as drilling progresses and the availability of required funding, and subject to unexpected delays, downtime, and similar unforeseen circumstances.
When reworking the nine wells to return them to production, the Company also substantially renovated and upgraded surface facilities such as tank batteries, piping, separators, and other equipment in order to create substantial excess capacity of field production facilities available to service new wells and to reduce production costs. Increased production resulting from additional drilling would be sold under the Company's existing sales agreement and trucking arrangement.
The Company intends to evaluate engineering data from existing wells together with any additional wells that may be productive to determine whether a reduced well spacing from 20 acres to 10 acres, which is the spacing approved by regulatory authorities, may be economically beneficial. If the Company concludes that reduced well spacing would increase the financial return from the field, the total number of available well locations would be increased, which would correspondingly extend beyond 1997, the period during which the Eagle Springs Field could be developed. In addition, the Company has initiated a larger ongoing reservoir study of the Eagle Springs Field oriented toward development of a secondary or tertiary improved oil recovery project.
Further activities in the Eagle Springs Field are currently being conducted jointly with Barrett as discussed below.
Barrett Agreement
On August 9, 1994, the Company entered into an agreement with Plains Petroleum Operating Company, which was acquired in August 1995 by Barrett Resources Corporation (together, "Barrett"), under which Barrett provided $1,920,000 of $2,400,000 in well costs to earn a 40% interest in the Company's Eagle Springs producing properties and obtained the right to participate in other specified Company exploration projects under agreed terms, including the North Humboldt prospect, as discussed above.
Under the agreement with Barrett, in September 1994, the Company and Barrett acquired for $225,000 in Company stock and cash an additional Eagle Springs lease on approximately 240 gross acres with three previously producing wells, then shut-in, and a shut-in water injection well. Of these wells, one was returned to production in 1994 and two were reworked and returned to production in July 1995. Two of the first new Eagle Springs wells drilled with Barrett are located on this acquired acreage.
The Company and Barrett drilled three new producing wells in the Eagle Springs Field in late 1994 and early 1995. In January 1995, after the first three new Eagle Springs wells were placed into production, Barrett elected to continue to participate in Eagle Springs, thereby earning a 40% working interest in the Company's Eagle Springs project, subject to the right to make individual elections respecting participating in future wells proposed by the Company. In mid-1995, the Company and Barrett commenced a multi-well drilling program on the proved nonproducing and proved undeveloped acreage in the field, to test at additional locations horizons that are productive in existing wells, and to increase proved reserves. The Company and Barrett are proceeding to prioritize the proved undeveloped locations as identified in the reserve report and anticipate those eight locations as additional wells to be drilled during 1996 and 1997. Barrett or Foreland may elect, on a well-by-well basis, to participate in the wells planned for 1996 and 1997 but has no obligation to participate in any well.
Barrett also has elected to earn an interest in the Company's acreage in an area of mutual interest in the North Humboldt prospect, developed by the Company on P&P mineral interests under the Company's agreement with P&P. (See "Joint Exploration Arrangements" above.) Barrett has declined further participation in the Dixie Flats prospect in Huntington Valley. In January 1995, Barrett elected not to participate in the Pine Valley 3-D survey, indicating that the full study was too large for Barrett's revised exploration budget. Activities under the joint exploration arrangement with Barrett are conducted by the Company as operator, under the overall direction of a technical committee made up of representatives of both parties. In addition to joint exploration in each of the exploration areas under this agreement through 1998, the Company has granted to Barrett the right to participate in any other exploration prospects that the Company elects to offer to third parties.
North Willow Creek and Tomera Ranch Discoveries
North Willow Creek
The initial discovery well in this field, the North Willow Creek SPLC no. 1-27 well, drilled in 1987, discovered an oil bearing structure at a depth of from 5,818 to 6,358 feet. Two additional wells, the North Willow Creek no. 6-27 and no. 5-27 have been drilled, extending the productive area of the field. The Company continues to experience production difficulties and management has concluded that the wells are not producing to the potential indicated by initial tests and engineering and geologic evaluations. The Company continues to receive limited production from two wells in this field.
Tomera Ranch
In August 1987, the Tomera Ranch discovery well, the SPLC no. 1-5, drilled by another operator under a joint exploration arrangement with the Company, was completed for production in the Indian Wells formation at between 1,864 and 1,950 feet. This well subsequently produced intermittently in limited amounts. When this well was placed into production, the Company could not obtain access to a water disposal well necessary to continue production and was forced to shut in the well. In 1992, the Company converted the SPLC no. 1-5 well to a water disposal well and drilled an adjacent well, the SPLC no. 1-5R, as a replacement production well. In 1990, the no. 33-1 well was completed for production in the Tomera Ranch Field, but was not placed into production until the Company completed the water injection well at Tomera Ranch in 1992. Since then, the SPLC no. 1-5R and no. 33-1 Tomera Ranch wells have had limited sustained production. In December 1993, the Company acquired the working interest of the previous operator in the Tomera Ranch field, and since then has continued to evaluate the productive potential of the area. Both the North Willow Creek and Tomera Ranch wells hold acreage over productive zones that the Company believes can be produced at higher rates with additional evaluation and reworking, including chemical treatments, heat treatments, hydraulic fracturing treatments, and other alternative measures. There can be no assurance that such efforts will be successful or that the wells will produce in paying quantities. If such efforts are successful, the Company plans additional evaluation drilling as warranted. The Company's petroleum engineer is evaluating the North Willow Creek and Tomera Ranch Fields and is making recommendations for improvement of production.
Exploration Status
Pine Valley
The Company has participated in two wells in the Hay Ranch area. The first, the West Hay Ranch no. 12-1, was drilled by another operator and was subsequently plugged and abandoned. In 1993, after evaluating the results of the West Hay Ranch no. 12-1, the Company drilled the Hay Ranch no. 1-17. Oil shows were encountered over a 1,000 foot thick interval, and a drillstem test was performed on one of the lower zones. This test well has been temporarily abandoned, and additional testing, directional drilling, and deepening operations are all being considered for the future. The rock section with oil shows in the no. 1-17 well is not present in the no. 12-1 well, indicating a "pinchout" of those prospective horizons, a common geological phenomenon which is often associated with oil traps.
Three exploratory test wells in which the Company participated were drilled in the northern part of Pine Valley within five miles of the Tomera Ranch Field. Each had varying degrees of oil shows. The most encouraging was the Tomera Ranch South no. 9-1, drilled by another operator in 1993. Promising oil shows were encountered in this test well, but attempts to log and test this hole were prevented by unstable hole conditions shallow in the well. The drilling results are being integrated with the geophysical data to guide further testing of this prospect. In December 1993, the Company increased its acreage position in this area by acquiring all of the previous operator's acreage in the Tomera Ranch area, including the previous operator's interest in the Tomera Ranch no. 33-1 well. The Company will now proceed with additional seismic exploration for use in positioning potential drilling sites.
The Company conducts exploration efforts in this area with Enserch/Berry pursuant to the operating agreement entered into by the parties. With funding provided jointly by the Company and Enserch/Berry, the Company acquired additional seismic data and defined two drilling prospects to be drilled in Pine Valley. In December 1994, the Trout Creek No. 26-1 exploratory well, the first well to be drilled in Pine Valley by the parties, was plugged and abandoned. The Pinon prospect in Pine Valley, the final well to be drilled under the Company's agreement with Enserch/Berry, is planned to be drilled during 1996, subject to obtaining required financing.
The Company and Hugoton/Maxwell are currently pursuing activities in the Pine Valley area pursuant to the revised agreement dated January 22, 1996, between the parties. Both parties contributed acreage under the agreement to consolidate the Company's position in the Pine Creek prospect. Hugoton/Maxwell obtained a one-year extension of the leasehold assigned by it and has agreed to complete and pay for a 3-D seismic study in the area or pay the Company $75,000 as liquidated damages, provided that the Company initiates a test well and obtains a two-year lease extension. The Company has had the Pine Creek unit designated by the Bureau of Land Management and plans to drill this prospect in the latter part of the second quarter, subject to forming a drilling group on terms acceptable to the Company.
Little Smoky and Antelope Valley
The Company continues active exploration of these two valleys under the agreement with Enserch/Berry. Substantial seismic surveys were completed late in 1993, leading to the drilling of two test wells. Although these tests were plugged and abandoned, these wells both added significantly to the Company's information in these two sparsely drilled yet promising prospect valleys. The Company and Enserch/Berry drilled an additional test well in each of these valleys during 1995, the Hot Creek Wash no. 15-1 in Antelope Valley and the Eldorado #15-1 in Little Smoky Valley. Both were plugged and abandoned.
Newark Valley
The Company is utilizing the extensive seismic information available to it through its agreement with Mobil for ongoing geological evaluation of this area. The two test wells in which the Company participated in this valley, the Buck Station and the Indian Springs prospects, encountered encouraging oil shows which were subsequently tested, but both tests were plugged and abandoned. The well information is being integrated with the seismic data to identify a potential "up dip" location to the Buck Station test for future drilling. On September 28, 1994, the Company entered into an agreement with Mobil under which it could drill one test well on or before September 1, 1995, on the Rustler Prospect located in White Pine County, Nevada, to earn an interest in such prospect area. The Company elected not to commence such well and has no further rights or obligations under the agreement.
Deadman Creek
The Company has completed lease acquisition over its Deadman Creek prospect in the Toano Draw area of Elko County with the purchase of leases on approximately 10,000 acres, which supplement the approximately 12,300 acres previously acquired. This prospect was generated by the Company during 1994 and 1993. In November 1995, the Company reentered an existing hole drilled by a previous operator in the mid-1980s for testing to determine whether recompletion is warranted using modern completion technologies. The Company has opened additional zones and swabbing operations have recovered oil and drilling and testing fluids. Representative samples of the oil and mud recovered from the swabbing are being analyzed to determine the appropriate fluids to use for breaking down the perforations. This test is on P&P acreage covered by P&P's agreement with the Company.
Competition and Markets
The Company competes with numerous other firms and individuals in its activities. The Company's competitors include major oil companies and other independent operators, many of which have financial resources, staffs, and facilities substantially larger than those of the Company. Competition in the oil and gas industry is intense.
The Company faces intense competition in obtaining risk capital for test drilling within the Great Basin province. Management believes that competition for drilling funds from such sources is principally dependent on an analysis by the potential industry participant of the costs of drilling and related activities, the likelihood of discovering oil or other hydrocarbons in commercial quantities, and the potential size of oil reserves which geologic and engineering analyses indicate may eventually be established.
The Company believes that an important consideration in obtaining risk capital for drilling, new exploration rights, and joint exploration and development arrangements with other industry participants is the amount and quality of the Company's scientific data and exploration experience in Nevada. The Company also believes that it benefits from its use of reprocessed 2-D seismic and 3-D seismic data and its experience in correlating that data with the results of actual drilling.
In its efforts to obtain oil leases within the Great Basin, the Company encounters competition from lease speculators, independent oil firms, and major oil companies. The ability to acquire leases is generally determined by the amount of cash paid to acquire the lease, the royalty or other interest retained by the transferor, and the nature of any commitment to drill on the lease acreage. The Company seeks to acquire leases in those areas that have been identified through geological and geophysical data as having potential to produce oil in sufficient quantities to be economic.
The availability of a ready market for production and the prices obtained for production of oil depend on a number of factors beyond the Company's control, the effects of which cannot be predicted accurately. Such factors include the extent of domestic production and imports of oil; the competitive position of oil as a source of energy as compared to gas, coal, nuclear energy, hydroelectric power, and other energy forms; the refining capacity of prospective purchasers; transportation costs; the availability and capacity of pipelines and other means of transportation; and the effect of federal and state regulation on production, transportation, and sale of oil.
Government Regulation
The exploration for and production of oil in the United States are subject to extensive regulation by both federal and state authorities. The following discussion concerning regulation of the oil and gas industry is necessarily brief and is not intended to constitute a complete discussion of the various statutes, rules, regulations, and governmental orders to which operations of the Company may be subject.
Environmental Regulations
Operations of the Company are subject to numerous laws and regulations governing the discharge of materials into the environment, the remediation of environmental impacts, and other matters relating to environmental protection, which affect the Company's operations and costs. It is probable that state and federal environmental laws and regulations will become more stringent in the future. Proposed legislation to reauthorize the Federal Resource Conservation and Recovery Act would have reclassified a significantly greater portion of oil and gas production waste as "hazardous waste." If this proposed legislation had been enacted, the stricter disposal requirements for hazardous wastes would have had a significant impact on the operating costs of the Company and the oil and gas industry in general, resulting in a significant number of wells becoming uneconomic. There can be no assurance that measures to further regulate the disposal of oil waste may not be adopted. Environmental laws and regulations are frequently changed so the Company is unable to predict the ultimate cost of compliance.
In connection with the acquisition of the Eagle Springs property, the Company performed limited environmental inquiries and agreed to undertake certain work to remediate a contaminated drilling pit at a former water injection well site. That work was completed in coordination with federal and state supervising agencies in early 1994 at a cost of $110,604. As a negotiated term of the acquisition of the Eagle Springs lease, the Company agreed to indemnify the secured creditor from which the Company acquired a portion of its property interests against claims for environmental liability. The Company does not believe that it has any material continuing financial obligation respecting remediation of environmental matters involving the Eagle Springs property. However, there can be no assurance that new remediation issues will not arise in the future.
State and Local Regulation of Drilling and Production
State regulatory authorities have established rules and regulations requiring permits for drilling, drilling bonds, and reports concerning operations. Such regulations also cover the location of wells, the method of drilling and casing wells, the surface use and restoration of well locations, and the plugging and abandoning of wells. Nevada also has statutes and regulations governing a number of environmental and conservation matters, including the unitization and pooling of oil properties and establishment of maximum rates of production from oil wells.
Federal Leases
The Company conducts significant portions of its activities under federal oil and gas leases. These operations must be conducted in accordance with detailed federal regulations and orders which regulate, among other matters, drilling and operations on these leases and calculation and disbursement of royalty payments to the federal government.
Title to Properties
Substantially all of the Company's working interests are held pursuant to leases from third parties. The Company performs only a minimal title investigation before acquiring undeveloped properties, and a title opinion is typically obtained only prior to the commencement of drilling operations. The Company has obtained other documentary confirmation of title on its principal producing properties and believes that it has satisfactory title to such properties. The Company's properties are subject to customary royalty interests, liens for current taxes, and other common burdens which the Company believes do not materially interfere with the use of such properties and whose economic effect has been appropriately reflected in the Company's acquisition costs of such properties.
Operational Hazards and Insurance
The Company's operations are subject to the usual hazards incident to the drilling for and the production of oil, such as blowouts, cratering, explosions, uncontrollable flows of oil or well fluids, fires, pollution, releases of toxic gas, and other environmental hazards and risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations.
The Company maintains insurance of various types to cover its operations. The Company has general liability insurance of $1 million per occurrence, with a $2 million aggregate limitation, including coverage for certain oil industry activities. Management believes that the Company's current insurance coverage is adequate; however, the Company's insurance does not cover every potential risk associated with the drilling and production of oil. In particular, coverage is not available for certain types of environmental hazards. The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a materially adverse effect on the Company. Moreover, no assurance can be given that adequate insurance will be available at reasonable rates or that the Company or the operators of wells in which the Company owns an interest will elect to maintain certain types or amounts of insurance.
Employees
The Company has 13 employees, including five executive officers (all of whom are also directors), four technical employees in addition to the executive officers, two field operations employees, and two administrative employees. (See "ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.")
ITEM 2.

ITEM 2. PROPERTIES The Company's principal oil and gas properties are located in Nevada.
In the oil and gas industry and as used herein, the word "gross" well or acre is a well or acre in which a working interest is owned; the number of gross wells is the total number of wells in which a working interest is owned. A "net" well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres.
Proved Reserves
The following table sets forth the estimated oil reserves, net to the Company's interest, of oil and gas properties as of December 31. 1995, giving effect to Barrett' election on January 25, 1995, to continue to participate in the Eagle Springs Field and to receive a 40% working interest in the field effective August 1, 1994. The reserve information is based on the independent appraisal prepared by Malkewicz Hueni Associates, Inc., Golden, Colorado, and was calculated in accordance with the rules and regulations of the Securities and Exchange Commission. (See "ITEM 1. BUSINESS.")
Estimated Future Net Revenues Estimated Discounted Reserve Category Oil (bbls) at 10% (1) - ------------------------- --------------- ----------------
Proved Developed Producing Eagle Springs 1,111,000 $3,918,600 North Willow Creek 17,100 50,200
Proved Developed Nonproducing Eagle Springs 47,400 123,200
Proved Undeveloped Eagle Springs 830,900 2,106,700 Total Proved 2,006,400 $6,198,700 =============== ==============
(1)Neither prices nor costs have been escalated. (See "ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.") The discounted figures have been reduced by the Company's share of estimated development costs in the amount of $2,754,000.
Wells and Acreage
Shown below is a tabulation of the productive wells owned by the Company in Nevada as of December 31, 1995, which gives effect to Barrett's 40% working interest in the Eagle Springs field.
Productive Oil Wells - -----------------------
Gross Net - ---------- ----------
21.0 14.2
Set forth below is information respecting the developed and undeveloped acreage owned by the Company in Nevada as of December 31, 1995, which gives effect to Barrett's 40% working interest in the Eagle Springs Field.
Developed Acreage Undeveloped Acreage
Gross Net Gross Net
4,120 2,728 209,480 154,024
The Company's leases in Eagle Springs (3,040 gross and 1,648 net acres), Tomera Ranch (680 gross and 680 net acres), and North Willow Creek (400 gross and 400 net acres) are held by production. The Company's undeveloped leases have various primary terms ranging from one to ten years. Management believes that the expiration of any individual or group of related undeveloped leasehold interests would not have a material adverse effect on the Company. Annual rentals on all undeveloped leases aggregate approximately $125,000. In addition to the above acreage, the Company has certain marketing and exploration rights to approximately 434,000 gross acres of P&P mineral interest in northern Nevada until December 1996.
Drilling Activities
Set forth below is a tabulation of wells completed in the period indicated in which the Company has participated and the results thereof for each of the periods indicated. Year Ended December 31, ---------------------------------
1993 1994 1995 --------- ---------- ----------
Gro Net Gro Net Gro Net ss ss ss Exploratory: Dry................ 6 3.5 3 1.05 2.0 0.84 Oil................ -- -- -- -- -- -- Gas................ -- -- -- -- -- -- ---- ----- ----- ----- ---- ------
Totals......... 6 3.5 3 1.05 2.0 0.84
Development: Dry................ -- -- -- -- -- -- Oil................ 1 1 3 1.8 5.0 3.0 Gas................ -- -- -- -- -- -- ---- ----- ----- ----- ---- ------
Totals......... 1 1 3 1.8 5.0 3.0 ==== ===== ===== ===== ==== ======
Production and Sale of Oil
The following table summarizes certain information relating to the Company's net oil produced and sold from the Company's Nevada properties, after royalties, during the periods indicated.
Year Ended December 31, ----------------------------
1993(1) 1994(2) 1995(2)
Average net daily production of 16 121 236 oil (Bbls)
Average sales price of oil ($ $11.45 $10.80 $11.62 per Bbl)(3)
Average production cost ($ per $ 7.95 $ 8.09 $4.06 Bbl)(3)
(1)Represents production from the Company's North Willow Creek and Tomera Ranch properties only. (2)Represents production from North Willow Creek, Tomera Ranch and Eagle Springs. (3)Includes lifting costs (electricity, fuel, water, disposal, repairs, maintenance, pumper, and similar items), and production taxes. The amount excludes costs related to completion of remediation of a contaminated drilling pit at a former water injection drillsite.
Production from Eagle Springs started in January 1994, and currently accounts for about 92% of the Company's oil production. This consists of oil produced and sold net to the Company's interest from the eleven wells the Company acquired, reworked, and returned to production commencing in early January 1994 plus the eight new wells subsequently drilled and placed into production, net of production royalties. However, certain of the wells have been shut-in from time to time, sometimes for several months. Other wells have been shut-in for shorter periods during particular months because of mechanical problems. Currently, one well is temporarily shut-in and not in production. The Company intends to undertake remedial work when its schedule permits, when appropriate rig and equipment are available in the area, and when funds are available.
The oil from the Eagle Springs and Pine Valley, Nevada, wells is sold to Crysen Refining, Inc., Salt Lake City, Utah, an unrelated purchaser, under agreements continuing through August 1996, and from month-to-month thereafter, unless terminated by either party, at a price equal to Amoco Oil Company's Wyoming per barrel sour crude oil posted price, adjusted for gravity and oil quality, less transportation of $3.05 or $2.90 per barrel, depending on the producing field, but in no case less than $9.50 per barrel after deduction of all charges. For example, during the month of January 1996, the Company received a net price of $12.36 per barrel, after deducting transportation charges. The sale of oil is subject to price adjustments, production curtailments, and similar provisions common in oil purchase contracts.
Production costs relating to Nevada production for 1993 include costs associated with various production testing measures on the Tomera Ranch and North Willow Creek wells and fixed costs allocable to a limited number of wells. The substantial increase in average daily production in 1994 and 1995 is attributable to returning the Eagle Springs wells to production and drilling additional wells during such periods. Production costs in 1994 were inordinately high per barrel of oil being produced due to start up costs associated with the revamped production facility and repairs to equipment that had been shut down without maintenance for over a year. In early 1994, the Company incurred additional costs of operating in winter due to energy costs for heating the oil and operating the wells using propane as its main fuel to generate power for the pumping units. Production costs in 1995 decreased dramatically due to higher production, improved production facilities, and utilization of more cost-efficient energy sources used in operations Overall operating costs are a combination of costs associated with each well and costs associated with operation of the entire field. As additional wells are added to the production system, the field operating costs will be spread among additional wells, lowering the impact of such costs on each well and per barrel produced. In addition, the Company has been changing to more cost effective energy sources for continuing production in a further effort to control costs. This consists principally of a large capacity boiler that the Company intends to eventually fuel by natural gas from the wells, which requires no propane fuel and, because its large capacity heats the oil to higher temperatures, will reduce costs for well treatment chemicals and increases production efficiencies. Because of the foregoing, the Company expects that production costs per barrel will continue to decrease as production increases sufficiently to obtain economics of scale and dilute the impact of fixed operating costs. In addition, operating costs may continue to vary materially due to the costs of ongoing treatment or reworking of existing wells and the impact of the other factors discussed above.
The Company has only minor gas production which is used in operations to reduce energy costs.
Texas Interests
The Company's wholly owned subsidiary, Krutex Energy Corporation ("Krutex"), previously held an interest in approximately 125 producing shallow oil and gas wells in the West Salt Flat Field encompassing approximately 495 gross acres in Caldwell County, Texas. Pursuant to an April 1993 agreement with an unrelated third party operator (the "Operator"), the Operator received all revenues from production from the properties and bore all operating expenses through November 1, 1994. Prior to that date, the Operator had the right to earn 75% of Krutex's interest in the properties upon completing specified reworking of 16 wells located in the field. If the Operator timely completed the well reworking or established continuous production at a rate of at least 300 barrels per day by November 1, 1994, the Operator had the right to purchase Krutex's remaining interest at a price equivalent to Krutex's share of the proved developed oil and gas reserves estimated to be recoverable in 10 years, multiplied by 10 % of the price for west Texas crude oil for November 1994. On signing the agreement, the Operator agreed to pay Krutex $150,000 in monthly installments of $5,555. In October 1994, Krutex entered into a new agreement with the Operator under which it agreed to a cash payment of $50,000 to Krutex in lieu of the well reworking obligation referred to above to earn 75% of Krutex's working interest in the field. In addition, the Operator waived a payment of $12,500 by Krutex respecting the previous acquisition of certain third-party interests affecting the leases, and the Company waived the last two payments on the $150,000 note. Pursuant to the agreement, the Operator purchased Krutex's remaining 25% working interest for $25,000 in January 1995, so Krutex no longer has any interest in such Texas properties. The foregoing Texas properties are not included in the Company's principal oil and gas properties described in the tables above.
Offices
The Company's principal executive offices located at 12596 West Bayaud, Suite 300, Lakewood, Colorado 80228-2019, are rented from an unrelated party under a lease expiring September 1, 1998, and requiring monthly payments of $3,553 plus certain common area charges. The Company also maintains a field operations office at 2561 South 560 West, Suite 200, Woods Cross, Utah 84087.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS The Company is not a party to any material legal proceeding, and none has been threatened by or, to the best of the Company's knowledge, against the Company.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of the shareholders during the fourth quarter of 1995.
PART II ITEM 5.

ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock is traded in the over-the-counter market and is quoted on Nasdaq under the symbol "FORL." The following table sets forth the high and low closing bid quotations for the Company's Common Stock as quoted by Nasdaq for the periods indicated, based on interdealer bid quotations, without markup, markdown, commissions, or adjustments (which may not reflect actual transactions). Common Stock
High Low
First Quarter........... $3.50 $2.25 Second Quarter.......... $2.68 $2.06 Third Quarter........... $2.625 $2.25 Fourth Quarter.......... $3.188 $1.938
First Quarter........... $2.125 $1.5625 Second Quarter.......... 2.50 1.375 Third Quarter .......... 2.4375 1.75 Fourth Quarter.......... 1.31 2.13
On April 11, 1996, the closing bid price of the Company's Common Stock on Nasdaq was approximately $1.25. The Company has approximately 2,000 Common Stock shareholders of record.
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA The following selected financial data should be read in conjunction with the Consolidated Financial Statements of the Company and related notes included elsewhere in this Prospectus. The financial data as of December 31, 1995, 1994 and 1993, and for the years then ended have been derived from the Consolidated Financial Statements of the Company, which have been audited by Hein + Associates LLP, independent certified public accountants. The financial data as of December 31, 1992, and 1991, and for both of the years then ended, have been derived from the Consolidated Financial Statements of the Company for such periods, which were audited by another auditor. (See "ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION Overview
Since its organization in June 1985, the Company has been engaged principally in oil exploration in the Great Basin and Range of Nevada, an area that management believes is one of the most promising unexplored onshore domestic areas with potential for the discovery of major oil reserves. In continuing to advance this exploration, the Company's strategy is to generate exploration prospects with the most recent generally available scientific techniques, expand and improve the Company's strategic land position, and establish arrangements with other oil exploration firms active in Nevada to obtain additional scientific data, leases, and funding.
Until 1994, the Company had only limited revenue, consisting of modest amounts of interest income earned on net proceeds from the sale of securities and revenue from producing properties, including properties held in Texas from which the Company received no material operating income after April 1993. In September 1994 the Texas properties were sold to an unrelated third party operator. In 1993 and 1994, the Company acquired twelve previously producing wells in Eagle Springs, including three acquired with Barrett, and has since reworked and returned to production eleven of such wells, drilled a new water injection well in the Eagle Springs Field, and has undertaken a multi-well drilling program with Barrett, as discussed below, in order to supplement the Company's other limited production from its Tomera Ranch and North Willow Creek oil discoveries. In August 1994, the Company entered into an agreement with Barrett under which Barrett provided $1,920,000 of $2,400,000 in well costs to earn a 40% interest in the Company's Eagle Springs producing properties and obtained the right to participate in one specified Company exploration project on agreed terms. Pursuant to such agreement, the Company and Barrett acquired an additional Eagle Springs lease on approximately 240 acres with three previously producing wells, which have since been reworked, and a shut-in water injection well and have drilled a total of eight new wells in Eagle Springs, all of which are now in regular continuous production. The Company plans to continue additional drilling in this field to place into production undeveloped reserves and to drill in additional locations to test horizons that are productive in existing wells.
To date, the Company has funded its exploration program principally from the sale of its equity securities. The Company also benefits from capital provided by oil industry participants for drilling and other exploration of certain oil prospects through joint arrangements typical in the oil industry.
Plan of Operation
Eagle Springs Drilling
The Company's strategy in acquiring the Eagle Springs property was to increase revenue by returning existing wells to production and to identify additional drilling locations to evaluate the horizons that are productive in existing wells. Management believes that drilling in the Eagle Springs Field involves lower risk as compared to the Company's other exploration drilling in prospect areas with less drilling history and less available exploration data.
The Company has completed substantial work at Eagle Springs since its acquisition in July 1993, reworking eleven wells, including the three wells acquired and reworked with Barrett, to return them to production (subject to interruptions from time to time until further well treatment and other surface facilities could be completed), drilling a water injection well, and drilling and placing into production eight additional Eagle Springs wells with Barrett. Such activities include substantially renovating and upgrading surface facilities such as tank batteries, piping, separators, and other equipment so that field production facilities currently have excess capacity available to service new wells. Production from the Eagle Springs Field is sold under the Company's existing sales agreement and trucking arrangement to a refinery in Salt Lake City, Utah.
Of the new wells drilled on the Eagle Springs Field, the Company and Barrett drilled three new producing wells in the Eagle Springs Field in late 1994 and early 1995. In January 1995, after the first three new Eagle Springs wells were placed into production, Barrett elected to continue to participate in Eagle Springs, thereby earning a 40% working interest in the Company's Eagle Springs project, subject to the right to make individual elections respecting participating in future wells proposed by the Company. In mid-1995, the Company and Barrett commenced a multi-well drilling program on the proved nonproducing and proved undeveloped acreage in the field, to test at additional locations horizons that are productive in existing wells, and to increase proved reserves. The Company and Barrett are proceeding to prioritize the proved undeveloped locations as identified in the reserve report and anticipate those eight locations as additional wells to be drilled during 1996 and 1997. Barrett or Foreland may elect, on a well-by-well basis, to participate in the wells planned for 1996 and 1997 but has no obligation to participate in any well.
Based on its current drilling experience, the Company estimates that the Eagle Springs drilling will cost approximately $325,000 per gross well for a dry hole or $560,000 for a completed gross well, including related geophysical and geological evaluations, for estimated costs attributable to the Company's 60% share of the Eagle Springs drilling of from approximately $195,000 to $336,000 per well for a dry hole and a producing well, respectively. Therefore, the Company's share of the cost of the eight wells planned for 1996 and 1997 is estimated at approximately from $1,560,000, if all wells were dry holes, to $2,688,000 if all wells were completed for production.
General, Administrative, and Property Maintenance
The Company requires cash for general and administrative expenses, for maintaining its properties, and for other items that are required in order for the Company to continue, as distinguished from costs to advance its ongoing exploration program in Nevada. Based on estimates of the production rates and operating conditions during the first quarter of 1996, management believes that the Company currently requires cash from external sources of approximately $70,000 to $90,000 per quarter for ongoing fixed and recurring operating costs (which include general and administrative expenses, exploration consisting of an allocation of employee salaries and other overhead to the exploration function, and interest on outstanding debt), and approximately $32,000 to meet annual lease rental and other cost on its properties, which exceeds the Company's net revenue from oil production. Based on current production, after giving effect to reworking several existing Eagles Springs wells, to be accomplished during the second quarter of 1996, the Company estimates its second quarter oil revenue to be approximately $430,000, based on current oil prices, with average daily production net to the Company's interest of approximately 375 barrels of oil, giving effect to the fact that at any time some wells many not be in production. Related production costs are estimated at approximately $120,000, yielding estimated net production revenue of approximately $310,000 for the second quarter of 1996. (See "ITEM 2. PROPERTIES: Production and Sale of Oil.) Therefore, the Company estimates that it will be able to meet fixed and recurring operating costs for the second quarter of 1996 and thereafter. However, there can be no assurance that the reworking of the Eagle Springs wells will result in increased production, that production levels will not decline, or that current prices for oil will not decline. Any improved operating margins resulting from increased production and reduced operating expenses as weather improves or price increases would benefit the Company. There can be no assurance that Eagle Springs development will result in material additional production or that the Company will be able to obtain funds from other sources, in which case the Company would be required to implement cost-cutting measures and curtail drilling and most other exploration activity in order to continue.
Exploration Program
The Company requires substantial amounts of capital to advance its oil exploration program, relying on funding provided through joint exploration arrangements with other firms and utilizing its own capital provided principally through the sale of securities and existing and anticipated revenues from the development of Eagle Springs. During 1995, the Company drilled the fourth and fifth exploratory tests under its agreement with Enserch/Berry, both plugged and abandoned, incurring approximately $225,800 in drilling costs for the Hot Creek Wash test in Antelope Valley and approximately $153,200 in drilling costs for the Eldorado Federal # 15-1 exploratory well drilled in Little Smoky Valley.
The Company anticipates that it will continue its exploration program with up to six additional exploration tests during 1996, depending on the availability of required funds. The test in the Pinon Prospect in Pine Valley, with estimated total dry hole costs of $300,000, is planned for 1996, subject to available funding. The Company would be required to bear 50% of such costs. This would be the sixth well of the six well exploration program with Enserch/Berry. The Company and Barrett may also drill one test at North Humboldt at an estimated dry hole cost of approximately $400,000 for a net cost to the Company of $133,000 under their joint exploration agreement. The Company has reentered an existing hole drilled by another operator in the Deadman Creek area of Toano Draw on lands covered by an exploration agreement with P&P. The hole was originally drilled in the mid 1980s and encountered favorable oil shows but was not completed for production. The Company is evaluating the hole to determine if it could be economically completed using modern completion techniques. If joint exploration arrangements can be reached with other industry participants and the Company's share of required funds is available, the Company may also attempt to drill a Dixie Flats test in Huntington Valley at an estimated dry hole cost of $400,000. In addition, the Company will be drilling the Pine Creek prospect in Pine Valley at a net estimated cost to the Company of $332,000 and the Ghost Ranch prospect in Railroad Valley at a net estimated cost to the Company of $261,000.
The Company also plans to continue its geophysical and geological data gathering and evaluation, property acquisition, and prospect evaluation, depending on the availability of funds, This includes continuing to process seismic data available to the Company, completing 3-D seismic studies of specific drilling prospects, and integrating seismic, gravity, and drilling data. In addition the Company may undertake joint geophysical data acquisition with others under arrangements in which each participant bears a share of the cost for specific surveys. The Company will continue its lease acquisition efforts in specific prospect areas and, as it generates drilling proposals, seek funding for drilling. Typically, new prospects that are generated are not drilled for several months or until the next drilling season or later.
The Company initiated its 1995 exploration program with the net proceeds of $1,376,718 received from the private placement of units consisting of preferred stock and common stock purchase warrants completed in September 1995 (and $329,250 received from the exercise of C Warrants in October 1995). In order to pay other liabilities incurred in connection with drilling, during February and March 1996, the Company sold 500 shares of preferred stock for net proceeds of $472,500. The Company is currently seeking and is dependent on the receipt of funds from the sale of debt or equity financing to fund its portion of the cost of the Eagle Springs drilling program and further exploration drilling, but there can be no assurance that the Company will be successful in obtaining such additional financing.
In seeking financing for proposed data gathering, land acquisition, or drilling or other exploration of specific prospect areas, the Company typically investigates both oil industry funding sources and the availability of capital through the sale of securities. In considering participation from industry sources, the Company assesses whether the potential industry participant can provide scientific data and lease or other exploration rights in the prospect area as well as required funding as compared to the dilution that may result to the interest of the Company by sharing in any reserves that may be discovered. In analyzing the availability of capital from the sale of securities, the Company considers conditions in the capital markets generally, the anticipated marketability of Company securities, and the dilution that may result to existing shareholders. In selecting between available financing alternatives, management seeks the source that management believes will result in lesser dilution and greater economic return to its shareholders.
Liquidity and Capital Resources
Previous Periods
Historically the Company has obtained cash required for its other requirements from the sale of its equity securities. The Company's operations provided cash of $190,600 in 1995 when the Company reported a net loss of $2,275,600, which included $725,600 in expenses due to abandonments and impairments, and $852,600 for depreciation, depletion, and amortization. As of December 31, 1995, the Company's accumulated deficit was $19,212,300. Operations used $2,501,600 of cash in 1994, which included $1,847,200 in expenses due to abandonments and impairments, $434,500 for the loss on the sale of the Company's Texas oil and gas properties, and $329,500 for depreciation, depletion, and amortization. During 1995 investing activities used net cash of $1,814,300, principally due to $1,883,500 in additions to oil and gas properties. In 1994 investing activities used net cash of $1,182,500, principally due to additions to oil and gas properties resulting from the acquisition of additional lease rights from Kanowa in the Eagle Springs Field and additional Eagle Springs drilling, including the completion of a water injection well.
As noted above, cash required for both operating and investing activities was provided from financing activities during each of the past two fiscal years. In 1995, financing activities provided $1,560,400, provided by $1,561,400 from the issuance of equity securities. In 1994, financing activities provided $2,819,400, consisting primarily of a net of $2,537,600 from the issuance of equity securities and $400,000 in proceeds from new borrowing.
In addition to the above, the Company's oil and gas exploration and production activities were also advanced by approximately $2,233,000 and $2,345,000 provided during 1994 and 1995, respectively, by others under industry sharing arrangements related to specific drilling or other exploration.
Current Position/Future Requirements
The Company is dependent on the receipt of additional funds to repay certain drilling expenditures incurred during the fourth quarter of 1995 and to date during 1996 as well as to meet ongoing general and administrative expenses and other operating costs.
The Company requires cash for certain fixed and recurring operating costs in order for the Company to continue, as distinguished from drilling and related costs to advance its ongoing exploration program in Nevada that are either expensed as dry hole and abandonment costs in the case of an unsuccessful test or added to oil and gas properties if a producing well results. For example, during the fourth fiscal quarter ended December 31, 1995, the Company required cash for production operations ($105,800), exploration, consisting of an allocation of employee salaries and other overhead to the exploration function ($133,500), general and administrative ($139,100), and interest on outstanding debt requiring cash payment ($12,000), for an aggregate of approximately $390,400. (Most interest revenue and most interest expense relate to indebtedness to and from former and present officers and directors that do not require current cash expenditures.) During the fourth quarter, the Company received revenue of $298,400 from oil sales at an average of approximately 285 barrels per day, resulting in a cash shortfall for the quarter of $92,000.
Average daily net fourth quarter production increased to approximately 285 barrels per day, which is lower than anticipated. Due to delays in the Eagle Springs drilling and completion program, only three new Eagle Springs wells were placed in production during the fourth quarter. Such wells were not placed into production until the latter part of the fourth quarter. One additional well was placed in production in January 1996. Management believes that the Company's cash requirements, excluding drilling and related costs to advance the Company's ongoing development and exploration program in Nevada, will be met when certain Eagle Springs wells are recompleted in the second quarter of 1996, but there can be no assurance that production will increase in sufficient quantities or that oil prices will not fluctuate significantly.
To the extent that net production to the Company does not increase to a level sufficient to cover shortages of cash required for operations, the Company will be dependent on the sale of additional debt or equity securities, the exercise of outstanding options or warrants, or financing from other sources. There can be no assurance that Eagle Springs development will sustain sufficient additional production for the Company to be able to meet its requirements for recurring operating expenses or that the Company will be able to obtain funds from other sources, in which case the Company would be required to implement cost-cutting measures and curtail drilling and most other exploration activity in order to continue.
Between March and September 1995, the Company sold 507,667 units consisting of preferred stock and common stock purchase warrants at $3.00 for net proceeds of $1,376,719. During September 1995, the Company amended the exercise price of the C Warrants from $3.00 per share to $1.50 per share, and extended the expiration date from September 30, 1995 to October 10, 1995. The Company received, in October 1995, $329,250 in cash and notes receivable for the exercise of 219,500 C Warrants. In order to pay other liabilities incurred in connection with drilling, during February and March 1996, the Company sold 500 shares of preferred stock for net proceeds of $472,500 and is investigating the possibility of selling additional equity securities. The Company is current seeking and is dependent on the receipt of funds from the sale of debt or equity financing to fund its portion of the cost of the Eagle Springs drilling program and further exploration drilling, but there can be no assurance that the Company will be successful in obtaining such additional financing. There can be no assurance that the Company will be successful with any of its current financing activities
On April 30, 1994, the Company borrowed $400,000 from an unrelated third party, collateralized by oil and gas production and other personal property of the Company, to provide interim financing to advance the Company's drilling program in its Eagle Springs Field and to pay ongoing general and administrative expenses. The loan bears interest at 8.4% per annum, payable quarterly, and was originally due on April 30, 1995. In connection with this loan, the Company granted the lender options to purchase 200,000 shares of Common Stock at $2.00 per share at any time prior to the earlier of April 30, 1996, or 60 days subsequent to the repayment of the loan. In May 1995, the Company negotiated the extension of the due date of this loan to April 30, 1996. In connection with extending the loan payment date to April 30, 1996, the Company reduced the exercise price of the options previously granted to $1.50 and granted a new option to purchase 200,000 shares at $2.00 through the earlier of April 30, 1997, or 60 days subsequent to the repayment of the loan. The Company is currently investigating financing alternatives to repay the loan
The auditors' report on the financial statements of the Company as of December 31, 1995, contains a modification regarding the ability of the Company to continue as a going concern because of its limited working capital and revenue and continuing losses from operations. As of December 31, 1995, the Company had negative working capital of approximately $2,004,400 and had ongoing cash requirements for fixed and recurring operating expenses requiring cash expenditures, but excluding drilling and related expenditures, of approximately $92,000 greater than production revenue for the fourth quarter of 1995.
The Company will continue to seek cash proceeds from the exercise of outstanding options and warrants and from the sale of additional common stock, preferred stock, warrants, debt or other securities. In addition, the Company is exploring other sources of financing for ongoing costs as well as expanded activities and the possible purchase of additional production to increase the Company's production to increase the Company's financial security and stability as it continues its exploration. The purchase of producing properties would require substantial amounts of additional debt and equity financing. There can be no assurance that the Company can negotiate the acquisition of any properties or obtain any financing that may be required for such purchase. As in the past, the Company will rely largely on the sale of additional securities to meet its capital requirements.
Results of Operations
1994 and 1995
For the year ended December 31, 1995, oil sales increased $540,400 to $1,071,400 when compared to the fiscal year ended December 31, 1994, with sales from the Eagle Springs Field increasing $519,700 to $937,900 during such period. The revenues from the Company's other interests increased $20,700. Operating overhead revenue and well service revenue aggregately increased a net of $16,800 when compared to 1994, consisting of an increase of $33,000 in operating overhead revenue in 1995 due to the increased number of Eagle Springs wells drilled and placed into production during 1995 and a decrease of $16,100 in well service income during 1995 as compared to 1994 as a result of reduced fees earned for water disposal services. The increase of other income of $18,400 in 1995 as compared to 1994 was primarily a result of increases in value of new and used well equipment inventories used in the Company's drilling program. Interest income increased $63,000 in 1995 to $140,700, $76,600 of such increase attributable to interest earned on stock subscriptions receivable, while interest earned from excess cash investments decreased $14,900 in 1995 when compared to 1994.
The Company's oil and gas production expenses for 1995 decreased $33,300 to $424,400 when compared to 1994, attributable principally to reduction in operating expenses of the Eagle Springs Field of $34,700 in 1995 when compared to such expenses in 1994. These reductions were a result of increased efficiency and excess field operations capacity. During 1995, oil and gas exploration costs decreased $287,500. Components of oil and gas exploration costs in 1994 were Eagle Springs 3-D seismic program expenses of $207,500 and gravity and other surveys costing $16,000 for Dixie Flats, $16,300 for the North Humboldt prospect, and $57,600 for Toano Draw. The Company did not incur any similar expenses during 1995. Dry hole, abandonment, and impairment costs aggregately decreased $1,132,200 when compared to such expenses during 1994. Individually, dry hole expense decreased $70,500 when compared to 1994. Dry hole costs for 1995 were primarily from the Eldorado Federal #15-1 of $153,200, the Hot Creek Wash #15-1 of $225,800, and costs for the Trout Creek #26-1 well of $17,300. Impairment and abandonment of leases decreased $1,211,700 when compared to 1994. Major cost components during 1995 were abandonment of expired undeveloped leasehold costs of $23,000, impairment of undeveloped leases of $250,000 and impairment of well equipment inventory of $47,500, while the North Willow Creek nos. 1-27 and 5-27 and the Tomera Ranch wells were impaired in 1994 at $1,382,200. General and administrative expenses decreased $227,300 in 1995 to $775,300. Much of the reduction in general and administrative expenses were principally due to one time charges in 1994 that were not repeated in 1995 of $114,500 for relocation cost; and $129,200 as a reduction in securities offering costs that were required to be expensed because of delays in consummating the Company's financing, although in 1995 the Company did incur an increase of $70,000 in expenses related to financial public relations, information dissemination within the investment community (which management expects to decline) and a decrease in certain salaries and benefits of $27,900 when compared to 1994. Depreciation, depletion and amortization expenses increased $533,100 when compared to 1994. Such expenses attributable to the Eagle Springs Field increased $426,900, primarily due to new wells being brought into production with high initial production rates, while such expenses attributable to the Company's remaining properties increased $106,200 in 1995 when compared to 1994. Interest expense increased $39,600 in 1995 to $125,300, primarily due to a full year of interest and amortization of loan fees associated with the Company's $400,000 note payable, as opposed to nine months of interest and amortization of the same loan fees during 1994.
1993 and 1994
For the year ended December 31, 1994, oil sales increased $401,200 to $477,000 as compared to 1993, with the Eagle Springs Field contributing approximately $418,200 of 1994 revenues as production from the Company's other fields declined. Well service revenue decreased $4,000 due primarily to reduced water disposal fees. Other income was approximately $35,600 higher in 1994 as compared to 1993 as a result of increased drilling and lease overhead fees charged to participants in Company drilling programs and lease operations.
The Company's oil and gas production expenses for 1994 increased $387,800 to $457,800 when compared to 1993, attributable principally to $346,500 in operating costs at Eagle Springs, which was placed into production in early 1994 and included one-time repair, maintenance and clean-up costs of $110,600. During 1994, oil and gas exploration costs increased $46,200, reflecting the Company's continuing active exploration program. Major components of 1994 exploration costs were an Eagle Spring 3-D seismic program expense of $207,500 and gravity and other seismic surveys of $16,000 for Dixie Flats, $16,300 for North Humboldt, and $57,600 for Toano Draw areas in Nevada contributed to the increase in exploration costs for 1994. Dry hole and abandonment cost increased by $468,200 due to the Company's exploration activities as well as specific abandonment expenses relating to wells initially drilled in previous years. Dry hole, abandonment, and impairment costs included charges to expense of $75,600 for the Indian Springs no. 22-A test that was plugged and abandoned, $31,800 for the Cedar Creek no. 2-1 dry hole, $87,900 for the Willow Springs no. 34-31 dry hole, and $268,800 for the Trout Creek no. 26-1 dry hole. Impairment expense increased due to the charge to expense of $703,900 for the North Willow Creek no. 1-27 test drilled in August 1993 that management concluded could not be placed into production. Additionally, during the fourth quarter of 1994 when it was determined that no reserves could be attributed to the North Willow Creek no. 1-27 or the Tomera Ranch wells, their undepleted capitalized costs of $564,400 and $103,900, respectively, were charged to impairment expense. General and administrative expenses for 1994 increased approximately $337,900 as compared to 1993. The major contributors to this increase were $222,600 associated with expenses written off for a canceled securities offering and the $84,200 cost on the guarantee of the selling price of N. Thomas Steele's residence. The Company recognized a $434,500 loss during 1994 related to the disposal of its remaining interest in certain Texas producing properties. In 1993, the Company reported a noncash compensation expense of $320,000 related to the grant of below market options. The Eagle Springs Field added approximately $154,000 of depletion expense in 1994, while depletion attributable to the North Willow Creek and the Tomera Ranch wells decreased $41,500 and $188,600, respectively, as compared to 1993. Interest expense declined $27,900, primarily due to the conversion of promissory notes to stock in September 1993 as compared to interest expense on the long term debt incurred in 1994.
Accounting Treatment of Certain Capitalized Costs
Included in oil and gas properties on the Company's balance sheets are costs of wells in progress. Such costs are capitalized until a decision is made to plug and abandon or, if the well is still being evaluated, until one year after reaching total depth, at which time such costs are charged to expense, even though the well may subsequently be placed into production. The Company also charges to expense the amount by which the total capitalized cost of proved oil and gas properties exceeds the total undiscounted net present value of related reserves. As a result of the foregoing policies, the Company expects that from time to time capitalized costs will be charged to expense based on management's evaluation of specific wells or properties or the disposition, through sales or conveyances of fractional interests in connection with industry sharing arrangements, of property interests for consideration in amounts that have the effect of reducing the Company's total undiscounted net present value of oil and gas reserves below the total capitalized cost of proved oil and gas properties. As part of the Company's evaluation of its oil and gas reserves in connection with the preparation of the Company's annual financial statements, the Company completes an engineering evaluation of its properties based on current engineering information, oil and gas prices, and production costs, which may result in material changes in the total undiscounted net present value of the Company's oil and gas reserves. The Company would be required to charge to expense the amount by which the total capitalized cost of proved oil and gas properties exceeds the amount of such undiscounted net present value of the Company's oil and gas reserves. (See "ITEM 1. BUSINESS: Oil Properties.")
Operating Costs
Operating costs relating to Nevada production from time to time include costs associated with various production testing measures on the Tomera Ranch and North Willow Creek wells and fixed costs allocable to a number of wells, including the Eagle Springs wells that were returned to production during 1994 and the new producing wells jointly drilled with Barrett. Production costs relating to the Eagle Springs Field have historically been higher than the normal industry standard per barrel of oil presently being produced due to start-up costs associated with the upgrading and expanding the production facility to facilitate additional production, and repairs to equipment that had been shut down without maintenance for over a year. During the first three months of 1995, the Company incurred additional costs of operating in winter due to energy costs for heating the oil, and operating the wells using propane as its main fuel to operate the pumping units. In early 1995, the Company completed field upgrades including a boiler system to heat the oil, a trace water disposal system to return produced water to the field water injection well as opposed to trucking the water to the disposal well.
Overall operating costs are a combination of costs associated with each well and costs associated with operation of the entire field. As additional wells are added to the production system, the field operating costs will be spread among additional wells, lowering the impact of such costs on each well and per barrel produced. Because of the foregoing, the Company expects that production costs per barrel will continue to be high unless and until the amount of production increases sufficiently to obtain economies of scale and dilute the impact of high fixed operating costs. In addition, operating costs may continue to vary materially due to the costs of ongoing treatment or reworking of existing wells and other factors. Inflation
The Company's activities have not been, and in the near-term are not expected to be, materially affected by inflation or changing prices in general. The Company's oil exploration and production activities are generally affected by prevailing sales prices for oil, however, and material price declines may make wells with low rates of production uneconomical to operate. Because of the size of potential discoveries in Nevada, the Company does not expect that short term declines in oil prices would materially affect its exploration activities.
Accounting Policy Changes
The Company's accounting policy is to compute depreciation and depletion expense for its proved oil and gas properties on a well-by-well basis, and to assess impairment on a Company-wide basis by comparing aggregate net capitalized costs related to proved properties to the aggregate undiscounted future cash flows related to such properties. At December 31, 1995, the Company recorded impairment to leases of undeveloped drilling properties of $250,000 and to well equipment inventory of $47,450. No impairment was necessary for net aggregate capitalized costs of proved properties.
In March 1995, the Financial Accounting Standards Board issued a new Statement titled "Accounting for Impairment of Long-Lived Assets." This new standard is effective for years beginning after December 15, 1995, and would change the Company's method of determining impairment of proved oil and gas properties. Although the Company has not performed a detailed analysis of the impact of the new standard on the Company's financial statements, management estimates the application of the new standard would have increased the provision for impairment of oil and gas properties by approximately $450,000, as of December 31, 1995. The Company will adopt the new standard in the first quarter of fiscal 1996.
In October 1995, the Financial Accounting Standards Board issued a new statement titled "Accounting for Stock-Based Compensation" (SFAS 123). The new statement is effective for fiscal years beginning after December 15, 1995. SFAS 123 encourages, but does not require, companies to recognize compensation expense for grants of stock, stock options, and other equity instruments to employees based on fair value. Companies that do not adopt the fair value accounting rules must disclose the impact of adopting the new method in the notes to the financial statements. Transactions in equity instruments with non- employees for goods or services must be accounted for on the fair value method. For transactions with employees, the Company currently does not intend to adopt the fair value accounting under SFAS 123, and will be subject only to the related disclosure requirements.
The Company does not anticipate that any other currently adopted changes in accounting policies will have a material positive or negative effect on the Company.
ITEM 8.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The table of contents of the financial statements and supplementary data included in this report is contained in "ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K."
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE The Company and its auditors have not disagreed on any items of accounting treatment or financial disclosure.
PART III
ITEM 10.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT Executive Officers and Directors
The following table sets forth the name, age, and position of each director and executive officer of the Company. Name Age Position - ----------------------- ------ --------------------------------
Dr. Grant Steele 71 Chairman and Director N. Thomas Steele 51 President and Director Kenneth L. Ransom 38 Vice-President, Exploration and Director Bruce C. Decker 44 Vice-President and Director Dennis J. Gustafson 48 Vice-President, Land and Director
All directors and executive officers of the Company serve for one year and until their respective successors are elected and qualified. Dr. Grant Steele is the uncle of N. Thomas Steele. There is no family relationship among any of the other officers and directors of the Company. Each of the officers is a full-time employee of the Company. The Company has entered into employment agreements with N. Thomas Steele, Kenneth L. Ransom, Bruce C. Decker, and Dennis J. Gustafson. See "Employment Agreements" below.
Dr. Grant Steele. Dr. Steele, the Company's co-founder and chairman, has been an executive officer and chairman of the Company since its organization in 1985. Prior to forming the Company, he was employed by Gulf Oil Corporation from 1953 to 1983. From 1973 to 1980, Dr. Steele was Chief Geologist/U.S. for Gulf Oil. His knowledge of Nevada dates back to his Ph.D. work on the Pennsylvanian and Permian Systems of the eastern Great Basin. While with Gulf, he completed several studies, each spanning a number of years, in eastern Nevada. Dr. Steele graduated from the University of Utah, Salt Lake City, Utah, in 1949 with a bachelor of science degree and earned his doctorate in geology from the University of Washington in 1959. He is a certified professional geologist and an active member of the American Association of Petroleum Geologists, which awarded him a distinguished service award in 1984, the Houston Geological Society, and the Society of Economic Paleontologists and Mineralogists.
N. Thomas Steele. Mr. Steele, co-founder and president, has been an officer and director of the Company since its organization in 1985. He was elected president in May 1993. Prior to joining the Company in 1985, he was the president of Magnum Resources, Inc., Ogden, Utah, which was engaged in mineral exploration in Nevada and Utah.
Kenneth L. Ransom. Mr. Ransom, has been vice-president of exploration and a director since the Company's founding in 1985. Mr. Ransom was senior geologist under Dr. Steele at Gulf Oil from 1981 to 1985, involved principally in its Nevada area study. He earned a bachelor of science degree in geological engineering from the Colorado School of Mines in 1979 and a master's degree in geological sciences from Brown University in 1981. Mr. Ransom is a member of the American Association of Petroleum Geologists and the Geological Society of America and has published numerous papers on Nevada exploration and geology.
. Bruce Decker. Mr. Decker, has been an officer and director of the Company since 1991. Mr. Decker was an officer of Krutex Energy Corporation from 1983 through its acquisition by the Company in 1989. Mr. Decker received his bachelor's degree in finance and management from the University of Utah in 1973.
Dennis J. Gustafson. Mr. Gustafson received his bachelor's degree from Iowa State University in 1973, and has been active since then in the oil and gas industry. In 1973 he joined Mobil's Central Region Marketing and Refining Division and held various positions in their Marketing Department prior to joining Mobil's Exploration and Production Division in Denver as a landman in 1981, where he managed fee mineral interests, various acquisitions, and farmouts and farmins. As Mobil's land advisor for the Denver division, he directed Mobil's land activities in Nevada and negotiated Mobil's major Nevada development contract with the BLM, renegotiated the Mobil/Chevron Nevada joint venture agreement, and managed the leasing of over 500,000 acres in Nevada. Mr. Gustafson left Mobil and joined the Company in 1993 as a director and executive officer.
Significant Employees
Jerry Hansen. Mr. Hansen, who joined the Company in 1986, is senior structural geologist for the Company with primary responsibility for generating and developing exploration proposals and drilling prospects for the Company. He has 12 years of oil and gas experience directed toward prospect generation and evaluation in the Powder River Basin, Gulf Coast, and primarily, in Nevada. He graduated with degrees in geology from the University of Colorado in 1973 and the University of Arizona in 1982. As senior structural geologist for the Company, Mr. Hansen's primary responsibility is in the generation and development of drillable prospects from inception to actual wellsite operations.
Carl Schaftenaar. Mr. Schaftenaar, who joined the Company in 1993, has been a geophysicist and geologist in the oil industry for 12 years. He holds a bachelor's degree in geology from Hope College, Holland, Michigan, and a master of science degree in geophysics from Texas A&M University. Mr. Schaftenaar worked for Chevron USA on exploration and development projects in Nevada and the Rocky Mountain area from 1982 to 1992. As senior geophysicist, Mr. Schaftenaar is responsible for the acquisition and analysis of proprietary two- and three-dimension seismic programs of the Company.
Compliance with Section 16(a) of the Exchange Act
Based solely upon a review of forms 3, 4, and 5 and amendments thereto, furnished to the Company during or respecting its last fiscal year, no director, officer, beneficial owner of more than 10% of any class of equity securities of the Company or any other person known to be subject to Section 16 of the Exchange Act failed to file on a timely basis reports required by Section 16(a) of the Exchange Act for the last fiscal year, except that N. Thomas Steele and Grant Steele each failed to timely report a gift of shares of Common Stock during December 1995, and all directors failed to timely report the delivery of shares of stock held by them to the Company as payment for the September 1995 installment of their notes as discussed in "Item 13. Certain Relationships and Related Transactions."
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation
The following table sets forth the annual and long term compensation earned by, awarded to, or paid to the chief executive officer of the Company during the last fiscal year. None of the Company's other executive officers as of the end of the last fiscal year received total annual salary and bonuses in excess of $100,000 for all services rendered in all capacities to the Company and its subsidiaries. The Company provides to all of its full time employees, including executive officers and directors, health insurance and miscellaneous other benefits.
(1)During 1994, the Company incurred a loss of $84,200 on its guarantee of a minimum sales price of $375,000 on Mr. Steele's former residence in connection with his move to Denver, Colorado, to become president and chief executive officer of the Company. (See "ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS: Relocation Agreement.") (2)Consists of options to purchase 72,000 shares at $1.50 through May 1998 and stock appreciation rights with respect to appreciation on 45,000 shares of the Company's Common Stock above $4.56, the trading price of the Company's Common Stock on the date of grant on May 19, 1993. Such stock appreciation rights vest as to 15,000 shares on May 19, 1993, as to an additional 15,000 shares on May 19, 1994, and as to the remaining 15,000 shares on May 19, 1995. The terms of these stock appreciation rights were not determined in arm's length negotiations.
Option/SAR Grants in Last Fiscal Year
The chief executive officer was not granted any options or stock appreciation rights during the fiscal year ended December 31, 1995.
Aggregate Option/SAR Exercises in Last Fiscal Year and Year End Option/SAR Values
The following table sets forth information respecting the exercise of options and SARs during the fiscal year ended December 31, 1995, by the named executive officer of the Company and the fiscal year end values of unexercised options and SARs.
(1)Includes stock appreciation rights with respect to appreciation on 45,000 shares of the Company's Common Stock above $4.56, the trading price of the Company's Common Stock on the date of grant on May 19, 1993. Such stock appreciation rights vested as to 15,000 shares on May 19, 1993, as to an additional 15,000 shares on May 19, 1994, and as to the remaining 15,000 shares on May 19, 1995. The terms of these stock appreciation rights were not determined in arm's length negotiations. (2)Based on the closing bid price for the Company's common stock of $1.5625 on December 31, 1995.
Director Compensation
As all of the Company's directors are also employees, the Company has not compensated and does not intend to compensate such individuals for their service as directors of the Company.
Employment Agreements
The Company entered into employment agreements dated May 19, 1993, with N. Thomas Steele, Kenneth L. Ransom, Bruce C. Decker, and Dennis J. Gustafson at annual salaries of $125,000, $119,000, $119,000, and $72,000 respectively, subject to reduction to $85,000, $77,760, $75,600, and $60,000 respectively, until the Company obtains net oil production levels of 500 barrels per day. Each such employment agreement is for a three-year term and is automatically extended on each anniversary date of the agreement for an additional three-year term. The employment agreements contain covenants not to compete for two years after termination of employment, restrictions on the disclosure of confidential information, provisions for reimbursement of expenses and payment of major medical insurance coverage, and an agreement of the Company to register securities of the Company held by such persons at the request of the employees. In addition, under the employment agreements, the Company agreed to award to each such officer stock appreciation rights to 45,000 shares of Common Stock, vesting 15,000 shares at the date of grant and 15,000 on each of the next two succeeding anniversary dates.
Limitation of Liability and Indemnification
The articles of incorporation of the Company limit or eliminate the personal liability of directors for damages for breaches of their fiduciary duty, unless the director has engaged in intentional misconduct, fraud, or a knowing violation of law, or paid a dividend in violation of the Nevada Revised Statutes.
The Company's articles of incorporation and bylaws further provide for the indemnification of officers and directors for certain civil liabilities, including liabilities arising under the Securities Act. In the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth, as of April 15, 1996, the outstanding Common Stock of the Company owned of record or beneficially by each person who owned of record, or was known by the Company to own beneficially, more than 5% of the Company's 14,489,401 shares of Common Stock issued and outstanding, and the name and share holdings of each director and all of the executive officers and directors as a group:
(1)Except as otherwise noted, shares are owned beneficially and of record, and such record shareholder has sole voting, investment, and dispositive power. The address of all such persons for purposes of this table is deemed to be the address of the Company. (2)Calculations of total percentages of shares outstanding for each individual assumes the exercise of options held by that individual to which the percentage relates. Percentages calculated for totals of all executive officers and directors as a group assume the exercise of all options held by the indicated group. (3)Represents 100,000 shares owned by Dr. Steele's wife's estate and 80,000 shares held by his Individual Retirement Account, over which Dr. Steele exercises sole investment, voting, and dispositive power. (4)Consists of options to acquire 100,000 shares of Common Stock at an exercise price of $1.50 per share at any time prior to December 1, 1996, and options to acquire 200,000 shares at an exercise price of $2.125 per share at any time prior to September 16, 1999. The options to acquire 100,000 shares at $1.50 per share contain a provision that, on exercise, the holder is granted a new option covering the number of shares for which the prior option was exercised, with the exercise price of the new option fixed at the then fair market value of the Common Stock. (5)Includes 7,000 shares of Common Stock and 6,250 shares of Common Stock issuable on conversion of outstanding preferred stock, such shares of common and preferred stock held by Mr. Steele's wife. (6)Consists of options to acquire 116,667 shares of Common Stock at an exercise price of $1.50 per share and 33,333 shares at an exercise price of $1.31 per share at any time prior to December 1, 1996, options to acquire 72,000 shares at $1.50 per share at any time prior to May 19, 1998, and options to acquire 200,000 shares at an exercise price of $2.125 per share at any time prior to September 16, 1999. The options to acquire 116,667 shares contain a provision that, on exercise, the holder is granted a new option covering the number of shares for which the prior option was exercised, with the exercise price of the new option fixed at the then fair market value of the Common Stock. (7)Consists of options to acquire 65,333 shares of Common Stock at an exercise price of $1.50 per share at any time prior to December 1, 1996, options to acquire 34,667 shares at $1.31 per share at any time prior to December 1, 1996, and options to acquire 200,000 shares at $2.125 per share at any time prior to September 16, 1999. The options to acquire 65,333 shares contain a provision that, on exercise, the holder is granted a new option covering the number of shares for which the prior option was exercised, with the exercise price of the new option fixed at the then fair market value of the Common Stock. (8)Consists of options to acquire 25,000 shares of Common Stock at $1.81 per share and options to acquire 25,000 shares at $3.38 per share, both expiring July 15, 1996, and options to acquire 25,000 shares at $2.125 per share expiring September 16, 1999. The options to acquire 25,000 shares at $3.38 per share contain a provision that, on exercise, the holder is granted a new option covering the number of shares for which the prior option was exercised, with the exercise price of the new option fixed at the then fair market value of the Common Stock. (9)Consists of shares owned by the individual retirement account of Mr. Gustafson, over which he exercises sole investment, voting and dispositive power. (10)Consists of options to acquire 25,000 shares of Common Stock at an exercise price of $2.125 per share at any time prior to September 16, 1999.
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Salary Deferrals and Waivers
Because of shortages of cash and working capital suffered by the Company during recent periods, certain officers and directors of the Company agreed to defer or waive all or portions of their previous salaries. As of December 31, 1995, the Company owed $392,462 in deferred salaries (including $10,527 due N. Thomas Steele), which the officers and directors have agreed not to seek to collect until at least after January 1, 1996 unless such payment would not jeopardize the ability of the Company to continue, or the net amount received by such officers and directors is used to retire existing debt owed to the Company or to purchase stock from the Company on exercise of options so that the Company will have such amounts available for its ongoing cash requirements. The officers and directors to whom the deferred salaries are owed have advised the Company that they will not seek payment of such amounts if such payment would jeopardize the ability of the Company to continue or unless the net amount received, after paying applicable withholding taxes, was used to pay notes for stock purchased on the previous exercise of stock options or for the exercise of additional options now outstanding.
Officer, Director, and Employee Options
On September 16, 1994, outstanding options were exercised to purchase an aggregate of 650,000 shares of Common Stock as follows: Grant Steele, 200,000 shares at $1.50; N. Thomas Steele, 200,000 shares at $1.50; Kenneth L. Ransom, 200,000 shares at $1.50; Bruce C. Decker, 25,000 shares at $2.25; and Dennis J. Gustafson, 25,000 shares at $2.25. Pursuant to the terms of the options exercised, each optionee paid the purchase price of the options by the delivery of a promissory note payable in three equal, consecutive installments of principal plus interest on the unpaid balance at 7% per annum, payable annually commencing on the first anniversary of the exercise. The note installments are payable in cash or the delivery of Common Stock or other options valued at the trading price at the time of payment. In connection with the issuance of shares on the exercise of such options, Grant Steele, N. Thomas Steele, and Kenneth L. Ransom each returned 24,118 shares, for an aggregate of 72,354 shares, of Common Stock to satisfy withholding obligations of the Company, as provided for in the terms of the options exercised. On September 16, 1995, these individuals delivered to the Company shares of Common Stock , valued at $2.25 per share, the approximate price of the Company's common stock as quoted on Nasdaq as of such date, as payment of accrued interest and principal due on notes delivered by them to the Company as payment for the September 1995 installment of their notes as follows: N. Thomas Steele, 50,807 shares for $114,316; Grant Steele, 50,807 shares for $114,316; Kenneth L. Ransom, 50,807 shares for $114,316; Dennis Gustafson, 9,527 shares for $21,436; and Bruce C. Decker, 9,527 shares for $21,436. These transaction were not the result of arm's length negotiations.
Certain Loans
In previous years, the Company loaned to Bruce C. Decker, an officer and director of the Company, and Robert Richins, a former officer and director, an aggregate of $160,005, secured by a pledge of the obligation of the Company to such persons for accrued but unpaid back salaries. Proceeds from these loans were used principally to purchase equity securities of the Company. As of December 31, 1995, the aggregate amount of principal and interest due the Company from such individuals was $247,470, and the aggregate amount of accrued but unpaid salaries, including interest, due by the Company to such persons was $258,638. The Company has not sought, nor will it seek, payment of the notes until back salaries owed these individuals are paid.
Relocation Agreement
In May 1993, in connection with the relocation of N. Thomas Steele from Utah to Colorado in order to become president of the Company, the Company agreed, among other items, to guarantee the sales price of Mr. Steele's Utah home. In the third quarter of 1994, the Company sold the home and recognized a loss of approximately $84,200.
PART IV
ITEM 14.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a)(1) Financial Statements. The following statements are included in --------------------
this report:
(a)(2) Financial Statement Schedules. Schedules are omitted because of -----------------------------
the absence of conditions under which they are required or because the information is shown in the financial statements.
(a)(3) Exhibits. The following exhibits are included as part of this --------
report
(1)Incorporated by reference from the Company's registration statement on form S-2, SEC file number 33-42828. (2)Incorporated by reference from the Company's annual report on form 10-K for the fiscal year ended December 31, 1992. (3)Incorporated by reference from the Company's quarterly report on form 10-Q for the period ending March 31, 1993. (4)Incorporated by reference from the Company's registration statement on form S-1, SEC file number 33-19014. (5)Incorporated by reference from the Company's registration statement on form S-2, SEC file number 33-34970. (6)Incorporated by reference from the Company's annual report on form 10-K for the fiscal year ended December 31, 1991. (7)Incorporated by reference from the Company's annual report on form 10-K for the fiscal year ended December 31, 1993. (8)Incorporated by reference from the Company's registration statement on form S-1, SEC file number 33-81538. (9)Incorporated by reference from the Company's registration statement on form S-2, SEC file number 33-64756. (10) Incorporated by reference from the Company's registration statement on form S-2, , SEC file number 33-86076. (11) Incorporated by reference from the Company's quarterly report on form 10-Q for the period ending March 31, 1993. (12) Incorporated by reference from the Company's annual report on form 10-K for the fiscal year ended December 31, 1985. (13) Incorporated by reference from the Company's annual report on form 10-K for the fiscal year ended December 31, 1994.
* Filed as an exhibit to this annual report on form 10-K. ** Identifies each management contract or compensatory plan or arrangement required to be filed as an exhibit. (b) Reports on Form 8-K.
During the last quarter of the fiscal year ended December 31, 1995, the Company did not file any reports on form 8-K.
SIGNATURES Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
FORELAND CORPORATION
Dated: April 15, 1996 By /s/ N. Thomas Steele ---------------------------
N. Thomas Steele, President
Pursuant to the requirements of the Securities Exchange of 1934, as amended, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Dated: April 15, 1996 By /s/ N. Thomas Steele ---------------------------
N. Thomas Steele, President and Director (Principal Executive Officer and Principal Financial Officer)
Dated: April 15, 1996 By /s/Grant Steele ---------------------------
Grant Steele, Chairman and Director
Dated: April , 1996 By ----- ---------------------------- Kenneth L. Ransom, Vice President- Exploration and Director
Dated: April , 1996 By ----- ---------------------------- Bruce C. Decker, Vice-President and Director
Dated: April 15, 1996 By /s/ Dennis J. Gustafson ----------------------------
Dennis J. Gustafson, Vice President- Land and Director
Dated: April 15, 1996 By /s/Don W. Treece ----------------------------
Don W. Treece, Controller (Principal Accounting Officer)
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE ----
Independent Auditor's Report.....................................F-2
Consolidated Balance Sheets - As of December 31, 1994 and 1995...F-3
Consolidated Statements of Operations - For the Years Ended December 31, 1993, 1994, and 1995.....................F-5
Consolidated Statements of Stockholders' Equity - For the Years Ended December 31, 1993, 1994, and 1995.....................F-6
Consolidated Statements of Cash Flows - For the Years Ended December 31, 1993, 1994, and 1995...........................F-8
Notes to Consolidated Financial Statements......................F-10
INDEPENDENT AUDITOR'S REPORT
Board of Directors Foreland Corporation Lakewood, Colorado
We have audited the accompanying consolidated balance sheets of Foreland Corporation and subsidiaries as of December 31, 1994 and 1995, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 1995. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Foreland Corporation and subsidiaries as of December 31, 1994 and 1995, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 1995, in conformity with generally accepted accounting principles.
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates the real- ization of assets and liquidation of liabilities in the normal course of business. As discussed in Note 2 to the financial statements, the Company has suffered losses from inception, and anticipates the need for additional cash to fund its operations. These conditions raise substantial doubt about the Company's ability to continue as a going concern. Management's plans in regard to these matters are also discussed in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
HEIN + ASSOCIATES LLP
Denver, Colorado April 12, 1996
FORELAND CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, ------------
1994 1995 --------- ---------
ASSETS ------
CURRENT ASSETS: Cash and equivalents $ 93,715 $ 30,490 Accounts receivable, net of allowance of $9,000 in 1994 864,778 438,058 Inventory 168,699 81,382 Advances to officer and director 7,907 7,212 Prepaid expenses and other 1,472 2,586 ---------- ---------- Total current assets 1,136,571 559,728
PROPERTY AND EQUIPMENT, at cost: Oil and gas properties, under the successful efforts method 5,133,538 6,874,635 Furniture, equipment, and vehicles 263,603 299,161 ---------- ---------- 5,397,141 7,173,796
Less accumulated depreciation, depletion and amortization (1,500,648) (2,363,211) ---------- ----------
3,896,493 4,810,585
OTHER ASSETS 164,350 230,785 ---------- ----------
TOTAL ASSETS $5,197,414 $5,601,098 ========== ==========
See accompanying notes to these consolidated financial statements.
LIABILITIES AND STOCKHOLDERS' EQUITY ------------------------------------
CURRENT LIABILITIES: Current maturities of long-term debt $ - $ 404,237 Accounts payable and accrued expenses 649,242 1,642,537 Officers' salaries payable 354,962 392,462 Oil and gas sales payable 84,738 125,899 ---------- ----------
Total current liabilities 1,088,942 2,565,135
LONG-TERM DEBT, less current maturities 400,000 23,091
COMMITMENTS (Notes 2, 4 and 8)
STOCKHOLDERS' EQUITY: Preferred stock, $.001 par value, 5,000,000 shares authorized: 1991 Convertible Preferred Stock, 40,000 shares issued and outstanding, liquidation preference of $50,000 40 40 1994 Convertible Redeemable Preferred Stock, 1,242,210 and 433,686 shares issued and outstanding, respectively, liquidation preference of $2,484,420 and $867,372, respectively 1,242 434
1995 Convertible Redeemable Preferred Stock, 1,015,334 shares issued and outstanding, liquidation preference of $1,523,001 - 1,015
Common stock, $.001 par value, 50,000,000 shares authorized; 13,587,852 and 14,489,401 shares issued and outstanding, respectively 13,588 14,489 Additional paid-in capital 21,887,629 23,301,858 Less note and stock subscriptions receivable (1,257,250) (1,092,622) Accumulated deficit (16,936,777)(19,212,342) ----------- ----------
Total stockholders' equity 3,708,472 3,012,872 ---------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $5,197,414 $5,601,098 ========== ==========
See accompanying notes to these consolidated financial statements.
FORELAND CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, --------------------------------
1993 1994 1995 ----------- ----------- ----------
REVENUE: Oil sales $ 75,748 $ 476,964 $1,017,401 Operator and well service revenue 21,589 54,880 71,722 Other income, net 907 11,147 26,753 ---------- ---------- ----------
Total revenue 98,244 542,991 1,115,876
EXPENSES: Oil and gas production 69,970 457,782 424,445 Oil and gas exploration 860,214 906,371 618,895 Dry hole, abandonment, and 1,389,728 1,857,878 725,648 impairment costs General and administrative 655,985 1,002,662 775,300 Compensation - below market options 320,000 - - Depreciation, depletion, and amortization 356,676 329,502 862,563 ---------- ---------- ----------
Total expenses 3,652,573 4,554,195 3,406,851 ---------- ---------- ----------
OPERATING LOSS (3,554,329) (4,011,204) (2,290,975)
OTHER INCOME (EXPENSE): Interest income 89,636 77,693 140,688 Interest expense (113,561) (85,686) (125,278) Loss on sale of oil and gas properties - (434,521) - ---------- ---------- ----------
NET LOSS ($3,578,254) ($4,453,718) ($2,275,565) ========== ========== ===========
NET LOSS PER COMMON SHARE $ (.34) $ (.34) $ (.16) ============ ========= ===========
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING 10,405,000 12,989,000 14,271,000 ========== ========== ==========
See accompanying notes to these consolidated financial statements.
See accompanying notes to these consolidated financial statements.
FORELAND CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: ------------------------------------------
Nature of Operations - Foreland Corporation (Foreland) was incorporated in Nevada in 1985 to engage in oil exploration, development, and production. Activities to date have focused primarily in north-central Nevada.
Principles of Consolidation - The consolidated financial statements include the accounts of Foreland and its wholly-owned subsidiaries, Krutex Energy Corporation (Krutex), and Eagle Springs LLC (Eagle Springs), collectively referred to as the Company. All significant intercompany transactions and balances have been eliminated in consolidation.
Cash Equivalents - For purposes of the statements of cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.
Oil and Gas Properties - The Company follows the "successful efforts" method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed. Management estimates that the salvage value of lease and well equipment will approximately offset the future liability for plugging and abandonment of the related wells.
The Company determines impairment of proved oil and gas properties by comparing the net carrying value of all of the Company's proved properties to the undiscounted future net revenues for such properties. Impairment is recognized to the extent that the carrying value exceeds the undiscounted future net revenues. Also see Note 11.
Unproved oil and gas properties are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Capitalized costs of producing oil and gas properties are depreciated and depleted by the unit-of-production method. Costs of exploratory wells in progress are capitalized and excluded from depletion until such time as proved reserves are established or impairment is determined, generally not longer than one year from completion of drilling.
Upon the sale of an entire interest in an unproved property for cash, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
Other Property and Equipment - Furniture, equipment, and vehicles are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives (ranging from 3 to 10 years) of the respective assets. The cost of normal maintenance and repairs is charged to operating expenses as incurred. Material expenditures which increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of properties sold, or otherwise disposed of, and the related accumulated depreciation or amortization are removed from the accounts, and any gains or losses are reflected in current operations.
Accounting Estimates - The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and the accompanying notes. The actual results could differ from those estimates.
The Company's financial statements are based on a number of significant estimates including the allowance for doubtful accounts, realizability of notes and common stock subscriptions receivable, impairment of unproved oil and gas properties, and oil reserve quantities which are the basis for the calculation of depreciation, depletion, and impairment of proved oil and gas properties. The Company's reserve estimates were determined by an independent petroleum engineering firm. However, management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent discoveries are more imprecise than those for properties with long production histories. At December 31, 1995, approximately 44% of the Company's oil reserves are attributable to non-producing properties. Accordingly, the Company's estimates are expected to change as future information becomes available.
At least annually, the Company is required to evaluate the possible impairment of the carrying value of its proved oil and gas properties. This involves a comparison to the estimated future undiscounted cash flows, which is the primary basis for determining the related fair values for such properties. In addition to the uncertainties inherent in the reserve estimation process, this amount is affected by historical and projected prices for oil which has typically been volatile. It is reasonably possible that the Company's oil reserve estimates will materially change in the forthcoming year.
Additionally, at December 31, 1995, the Company has net capitalized costs of approximately $114,000 related to a well in progress. If this well is ultimately unsuccessful, these costs will be charged to operations.
Inventory - Inventory consists primarily of oil and gas production equipment and crude oil. Inventory is carried at the lower of cost or market, cost being determined generally under the average cost method of accounting, or where possible, by specific identification. The Company has classified $50,000 of used oil field equipment inventory as long-term (included with other assets), because based on current inventory usage and the type of equipment, it is not expected to be sold or placed in service within the next year.
Income Taxes - The Company accounts for income taxes on the liability method, whereby deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates.
Revenue Recognition - The Company recognizes oil sales upon delivery to the purchaser. Revenues from operator and well service fees are recognized as the services are performed.
Net Loss Per Share - The net loss per share calculation is based on the weighted average number of shares outstanding during each year. Convertible preferred stock, options, and warrants outstanding have been excluded from the calculation since the effect would be antidilutive.
Financial Instruments - Statement of Financial Accounting Standards No. 107 requires all entities to disclose the fair value of certain financial instruments in their financial statements. Accordingly, at December 31, 1995, management's best estimate is that the carrying amount of all financial instruments approximates fair value due to the short maturity of these instruments.
Reclassifications - Certain reclassifications have been made to the 1993 and 1994 financial statements to conform to the presentation in 1995. The reclassifications had no effect on the 1993 or 1994 net loss.
2. BASIS OF PRESENTATION: ---------------------
The accompanying consolidated financial statements have been prepared on the going concern basis, which contemplates the realization of assets and liquidation of liabilities in the normal course of business. The Company has incurred cumulative losses of $19,212,342 since inception, and the ability of the Company to continue as a going concern is dependent on its ability to successfully develop its oil and gas properties and ultimately achieve profitable operations. Management's plans in this regard are set forth below.
The Company will continue to seek cash proceeds from the exercise of options and warrants currently outstanding and from the sale of additional common stock, preferred stock, warrants, or other securities for cash. If inadequate funds are received from security offerings, the Company will seek required operating capital through interim debt financing, the farmout of drilling prospects, the sale of leases, drilling prospects or exploration rights on specific prospects, the sale of geological and geophysical data gathered in Nevada by the Company since 1985, or through other means. The Company intends to fund its exploration drilling program by spreading the risk inherent in this type of drilling by entering into drilling partnerships with others. The Company is continuing negotiations with various other exploration firms to fund additional drilling in Nevada, but there is no assurance that arrangements can be reached on terms acceptable or favorable to the Company.
The Company believes these efforts along with increased revenues from oil and gas production will enable it to continue its operations in the forthcoming year.
3. RELATED PARTY TRANSACTIONS: --------------------------
The Company owed $354,962 and $392,462 in salaries and interest to its officers and directors at December 31, 1994 and 1995, respectively.
In June 1991, the Company loaned an officer and director, and a former officer and director, an aggregate of $123,421, repayable with interest at the prime rate and collateralized by a pledge of the obligation of the Company to such persons for accrued but unpaid back salaries of approximately $156,720. A portion of the proceeds from these loans was used to purchase $100,000 in preferred stock and warrants. The notes were originally due in June 1992, but the Company has agreed not to seek payment of $247,470 (including additional advances and accrued interest) of the notes until back salaries owed these individuals (totaling $258,638 at December 31, 1995) are paid. At December 31,
1995, $247,470, including accrued interest, was due under the notes (which are included as a reduction of stockholders' equity in the accompanying financial statements).
In May 1993, in connection with the Company's move to Denver, Colorado, the Company agreed to: (1) pay for all relocation expenses incurred by the president; (2) pay the president's mortgage payments and maintenance costs on his former residence; (3) grant the president options to purchase 72,000 shares of the Company's common stock at $1.50 per share; (4) guarantee a minimum sales price of $375,000 on his former residence; and (5) advance the president up to $175,000. In September 1994, the Company sold the residence and received approximately $290,000 net of selling costs and recognized a loss on the transaction of approximately $85,000. Additional relocation costs of approximately $29,000 were paid in 1994.
See Note 4 for other related party transactions.
4. STOCKHOLDERS' EQUITY: --------------------
1991 Offering - During November 1991, the Company received net proceeds of $1,971,100 from a public offering of 4,600 units. Each unit consisted of 270 shares of common stock, 270 A warrants to purchase common stock at $2.25 per share, and 270 B warrants to purchase common stock at $3.90 per share. The warrants were exercisable through October 30, 1994. Upon expiration of the B warrants, the Company issued 1,242,000 L warrants to replace the B warrants. The L warrants are exercisable to purchase common stock at $8.00 per share through December 31, 1996.
The L Warrants are subject to redemption by the Company at a price of $0.10 per L Warrant on 30 days' prior written notice if the closing bid price of the Common Stock of the Company, as quoted on NASDAQ, exceeds the L Warrant exercise price by at least 20% for 20 of 30 trading days during a period ending within 10 days of the notice of redemption. All L Warrants in any class must be redeemed if any L Warrant in that class is redeemed. L Warrants may be exercised during the 30 day period after notice of redemption has been given.
In conjunction with the 1991 Offering, the Company issued to the underwriter for $100, 400 underwriter unit warrants consisting of an aggregate of 108,000 Class A warrants, 108,000 Class B warrants, and 108,000 shares of common stock.
The underwriter's unit warrants were exercisable at $550 per each unit. In 1995, pursuant to their terms, the underwriter's unit warrants were adjusted so that they are now exercisable at $552 per unit and the 400 units purchasable on exercise now consist of an aggregate of 138,000 shares of common stock, 138,000 Class A Warrants and 138,000 Class B Warrants. The underwriter's unit warrants are exercisable through October 30, 1996. The A and B Warrants issuable on the exercise of the underwriter's unit warrants are not redeemable and are exercisable through October 30, 1995, at an exercise price of $2.25 and $3.90, respectively, to acquire one share of Common Stock for each A and B Warrant exercised.
On July 23, 1993, Foreland notified holders of its Class A warrants that Foreland would redeem the warrants at $.10 each if not exercised by October 1, 1993. During 1993, the holders of Class A warrants purchased 1,241,990 shares of common stock at $2.25 per share for total proceeds of $2,794,478.
1991 Private Placement - During 1991, the Company sold 914,600 shares of convertible preferred stock in a private placement at $1.25 per share for net proceeds of $972,954. The purchasers of preferred stock also received two-year warrants (the 1991 warrants) to purchase an aggregate of 455,000 shares of common stock at $1.50 per share during the first year and $1.75 per share during the second year. The sales agent for the private placement received warrants to purchase an aggregate of 73,000 shares of common stock at $1.25 per share. At the election of the holder, each share of 1991 preferred stock may be converted into one share of common stock.
The holders of the 1991 warrants purchased 186,000 shares of common stock at $1.50 per share, and 10,000 shares of common stock at $1.75 per share for total proceeds of $296,500 during 1992 and 217,000 shares of common stock at $1.75 per share for a total of $379,750 during 1993.
During 1992, 72,000 of the 73,000 underwriter warrants issued in connection with the 1991 preferred private placement were exercised at $1.25 per share for total proceeds of $90,000.
The holders of the 1991 convertible preferred stock elected to convert 450,000 and 34,600 shares into common stock in 1993 and 1994, respectively. No holders of the 1991 convertible preferred stock elected to convert their shares to common in 1995.
1993 Private Placement - During May 1993, the Company completed a private placement totaling $3,500,000 for the sale of 700,000 units, each unit consisting of one share of 1993 Convertible Preferred Stock, par value $.001, and one X warrant, yielding net proceeds of approximately $3,126,542, after placement commissions and other costs of the offering. Subsequent to such offering, each share of 1993 preferred stock was convertd into two shares of the Company's common stock. Each X warrant entitled the holder to purchase, at any time through December 1, 1994 at an exercise price of $3.25 one share of the Company's common stock, and one Y warrant to purchase, for $4.00 per share, an additional share of common stock through December 15, 1995. Through December 1, 1994, holders of an aggregate of 3,000 X Warrants exercised such warrants and the Company isued 3,000 shares of common stock and 3,000 Y Warrants. The 697,000 X Warrants not exercised by December 1, 1994, were exercisable at $4.00 per share thereafter. The outstanding X and Y Warrants originally expired on December 15, 1995, but the Company extended the exercise period to March 14, 1996. During such period, no holders elected to exercise the outstanding X or Y Warrants.
The Company issued to the placement agent in this offering warrants to purchase 70,000 units, each unit consisting of one share of 1993 convertible preferred stock and one X warrant, such securities containing the same terms and conditions as those issued to investors.
1994 Private Placement - In July of 1994, the Company issued 1,316,210 shares of 1994 Convertible Redeemable Preferred Stock and 658,105 C Warrants for net proceeds of $2,341,370. The preferred stock and warrants were sold as units at $4.00 per unit, such units consisting of two shares of preferred stock and one C Warrant. The Company issued to the placement agent in this offering warrants to purchase 65,811 units which are exercisable before July 8, 1999, at an exercise price of $4.40 per unit.
At the election of the holder, each share of preferred stock may be converted at any time after October 31, 1994, into one share of common stock. Holders of the 1994 Preferred Stock elected to convert 74,000 and 808,524 shares into common shares in 1994 and 1995, respectively. The 1994 preferred stock is redeemable at any time after March 31, 1996, at $4.00 per share at the Company's option, and has a liquidation preference of $2.00 per share.
Each C Warrant originally entitled the holder to purchase, at any time between October 31, 1994, and July 1, 1995, for an exercise price of $3.00, one share of common stock During September 1995, the Company amended the exercise price of the Class C warrants from $3.00 per share to $1.50 per share, and extended the expiration date from September 30, 1995 to October 10, 1995. In October 1995, the Company received $191,749 in cash and a $137,500 note receivable for the exercise of 219,500 C warrants. The note receivable was recorded as a reduction in stockholders' equity.
1995 Private Placement - Between March and September 1995, the Company completed the sale of 507,667 non-transferable units (the "Units") for $3.00 per unit. Each Unit consists of two shares of preferred stock designated as the 1995 Series Preferred Stock and one M warrant. At the election of the holder, each share of 1995 Preferred Stock may be converted into one share of common stock. The 1995 preferred stock has a liquidation preference of $1.50 per share. Each M warrant entitles the holder to purchase, at any time through December 31, 1998, for $4.00 one share of Common Stock. M Warrants not exercised by December 31, 1998 will expire. The M Warrants may be redeemed by the Company on at least 30 days' notice at a redemption price of $.10 per M Warrant if the average closing price for the Company's Common Stock is at least $6.00 per share for 20 consecutive trading days prior to the redemption notice, subject to certain other conditions. The Company has agreed to file a registration statement under the Securities Act of 1933 covering the resale of the Conversion Shares issuable on conversion of the 1995 Preferred Stock and the Warrant Shares issuable on the exercise of the M Warrants.
Options - In 1985, the Company granted to its founders, who were also directors and officers, options to purchase 1,100,000 shares of the Company's common stock at a purchase price of $1.50 per share. During 1989, the Board extended to June 15, 1992, the 1985 options held by the Company's current directors to purchase, in the aggregate, up to 1,050,000 shares of common stock. In addition, the 1985 options were revised to provide that upon exercise of any of the options to purchase 1,050,000 shares of common stock, the Company will grant new five-year options for an equal amount of shares at a new exercise price to be equal to the trading price for the Company's common stock as of the date of grant. In April 1991, the options were again extended through 1996 and the officers and directors waived their rights to 100,000 options. In 1991, options for 67,781 shares were exercised at $1.50 per share, and new options were granted for 67,781 shares at $1.31 per share through December 1996.
During 1991, options to purchase 25,000 shares at $1.81 and 25,000 shares at $3.38 through July 15, 1996 were granted to an officer and director. Upon exercise of the 25,000 options at $3.38, new options for an equal number of shares at a new exercise price equal to the trading price of the Company's common stock at the date of grant will be issued.
In April 1994, options to purchase a total of 50,000 shares at $2.25 through April 1999 were granted to two officers and directors. Upon exercise of the options, new options for an equal number of shares at an exercise price equal to the trading price of the Company's common stock at the date of grant will be issued.
During 1994, outstanding options, including the options granted in April 1994, were exercised to purchase Common Stock as follows: Grant Steele, 200,000 shares at $1.50; N. Thomas Steele, 200,000 shares at $1.50; Kenneth L. Ransom, 200,000 shares at $1.50; Bruce C. Decker, 25,000 shares at $2.25; and Dennis J. Gustafson, 25,000 shares at $2.25. Pursuant to the terms of the options exercised, each optionee paid the purchase price of the options by the delivery of a promissory note payable in three equal, consecutive installments of principal plus interest on the unpaid balance at 7% per annum, payable annually commencing on the first anniversary of the exercise. The note installments are payable in cash or the delivery of Common Stock or other options valued at the trading price at the time of payment. In connection with the issuance of shares on the exercise of such options, Grant Steele, N. Thomas Steele, and Kenneth L. Ransom each returned 24,118 shares, for an aggregate of 72,354 shares, of Common Stock to satisfy withholding obligations of the Company, as provided for in the terms of the options exercised. Also pursuant to the terms of the options exercised, the Company automatically granted new five year options to purchase Common Stock at $2.125, the market price for the Common Stock at the time of exercise, as follows: Grant Steele, 200,000 shares; N. Thomas Steele, 200,000 shares; Kenneth L. Ransom, 200,000 shares; Bruce C. Decker, 25,000 shares; and Dennis J. Gustafson 25,000 shares. The first payment for the above referenced notes became due in September 1995. Grant Steele, N. Thomas Steele, and Kenneth Ramson each returned 50,807 shares of Common Stock in satisfaction of the first installment of principal and interest on their $300,000 notes, while Bruce Decker and Dennis Gustafson each returned 9,527 shares in satisfaction of the first installment of principal and interest on their $56,250 notes.
During 1994, the Company granted five-year options which allow several employees to purchase an aggregate of 105,000 shares of common stock at $3.00 per share. Options for 10,000 shares were immediately exercisable upon grant, 31,000 vested and became exercisable one year after grant, 32,000 vest and become exercisable after two years, and 32,000 vest and become exercisable after three years, provided that the employee in each case has been, within the preceding 30 days, an employee of the Company.
In 1994, the Company granted options to a non-affiliated person to purchase 30,000 shares of common stock at an exercise price of $3.00 per share through October 6, 1999.
SARS - In 1993, the Company granted a total of 180,000 Stock Appreciation Rights (SARS) to officers. The SARS vest 1/3 upon grant, 1/3 on the first anniversary date of the grant, and 1/3 on the second anniversary date of the grant. The SARS entitle the officers to receive cash, stock or a combination of
both in an amount equal to the amount by which the fair market value of the Company's common stock on the date the SARS are exercised exceeds $4.56 per share. The SARS expire in May 1998.
In 1994, the Company granted 45,000 SARS to an executive officer and director. The SARS entitle the officer to receive cash, stock, or a combination of both in an amount equal to the amount by which the fair market value of the Company's common stock on the date the SARS are exercised exceeds $2.50 per share. The SARS expire in June 1999.
Summary - The following summarizes the options and warrants currently -------
outstanding:
EXPIRATION DATE COMMON SHARES ------------------ -----------------
Options (price per share): -------------------------
Officers and directors: Exercise price of $3.38 July 1996 25,000 Exercise price of $1.81 July 1996 25,000 Exercise price of $1.50 December 1996- 354,000 May 1998 Exercise price of $1.31 December 1996 68,000 Exercise price of $2.125 September 1999 650,000
Others: Exercise price of $2.50 April 1998 20,000 Exercise price of $1.50 April 1998 30,000 Exercise price of $3.00 October 1999 135,000 ---------
Total options 1,307,000 ---------
Warrants (price per share): --------------------------
Exercise price of $4.00 March 1996 3,000 (Y warrants) Exercise price of $6.00-8.00 December 1996 1,242,000 (L warrants) Exercise price of $4.00 March 1996 697,000 (X warrants) Exercise price of $1.60 October 1996 138,000 (Placement Agent) Exercise price of $1.25 February 1996 1,000 (Underwriter) Exercise price of $1.50 April 1996 200,000 (CapitalPro) Exercise price of $2.00 April 1997 200,000 (CapitalPro) Exercise price of $4.00 December 1998 507,667 (M Warrants) Exercise price of $1.50 June 2000 100,000 (Investment Banker) ---------
Total warrants 3,088,667 ---------
Total options and warrants issued and outstanding 4,395,667 =========
The above table does not include 346,000 warrants to purchase common stock purchase warrants, underlying units currently outstanding, or any options issuable upon the exercise of existing options.
The Company has also issued 271,622 warrants to purchase preferred stock of prices ranging from $2.20 to $2.75.
5. INCOME TAXES: ------------
Deferred tax assets (liabilities) are comprised of the following at December 31, 1994 and 1995:
1994 1995 ---------- ----------
Long-term deferred tax assets (liabilities): Net operating loss carryforward $6,700,000 $7,300,000 Property and equipment basis (1,000,000) (1,300,000) differences Below-market stock options 100,000 100,000 --------- ---------
Net deferred tax assets 5,800,000 6,100,000
Less valuation allowance (5,800,000) (6,100,000) ---------- ----------
Net deferred tax assets $ - $ - ======= =========
The Company has a net operating loss carryforward of approximately $19,700,000 for income tax purposes. A portion of these net operating loss carryforwards may be subject to reduction or limitation of use as a result of change in ownership or certain consolidated return filing regulations.
The loss carryforwards for income tax purposes expire as follows:
YEAR OF EXPIRATION - -----------
1999 $ 300,000 2000 100,000 2001 700,000 2002 1,600,000 2003 1,400,000 2004 1,000,000 2005 1,300,000 2006 1,900,000 2007 1,700,000 2008 4,300,000 2009 3,800,000 2010 1,600,000 ----------
$19,700,000 ===========
6. SIGNIFICANT CONCENTRATIONS: --------------------------
Substantially all of the Company's accounts receivable result from crude oil sales and joint interest billings to companies in the oil and gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk, either positively or negatively, since these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral from a customer or joint interest owner, the Company generally analyzes the entity's net worth, cash flows, earnings, and/or credit ratings. Receivables are generally not collateralized; however, receivables from joint interest owners are subject to collection under operating agreements which generally provide lien rights. Historical credit losses incurred on trade receivables by the Company have been insignificant.
The Company's oil and gas properties are located in north-central Nevada where the net price realized for the Company's oil production is typically discounted due to gravity adjustments and transportation costs. Accordingly, in comparison to the net price received by oil producers in many other areas of the United States, the Company often realizes a lower net sales price. Additionally, the Company is vulnerable to a curtailment in drilling activity in order to realize the value of oil field inventories and related operating assets. Due to the remote location, the Company may be vulnerable to delays and shortages of equipment due to a relatively limited number of suppliers for certain goods and services.
At December 31, 1995, the Company had a receivable from a single oil purchaser for $225,000, which was collected in January 1996. This purchaser accounts for all of the Company's oil sales. Additionally, at December 31, 1994 and 1995, the Company had joint interest billings from a single customer of approximately $475,000 and $175,000, respectively.
7. LONG-TERM DEBT: --------------
Long-term debt at December 31, 1994 and 1995, consists of the following: 1994 1995 ======= ------
Note payable to unrelated party. $400,000 $400,000
Other installment notes. Interest at 13.4%, monthly principal and interest payments of approximately $639 through October 1999 when the remaining balance is due. The notes are collateralized by vehicles. - 27,328 -------- --------
Total long-term debt 400,000 427,328
Less current maturities - (404,237) -------- -------- Total long-term debt, less current $400,000 $ 23,091 maturities -------- --------
On April 30, 1994, the Company borrowed $400,000 from an unrelated party to provide interim financing to proceed with the Company's drilling program in its Eagle Springs Field and to pay ongoing general and administrative expenses. In connection with the loan, the Company granted the lender warrants to purchase 200,000 shares of Common Stock at $2.00 per share at any time prior to the earlier of April 30, 1996 or 60 days subsequent to the repayment of the loan. The loan originally provided for interest at 8.4% per annum, payable quarterly, and was due on April 30, 1995.
In May 1995, the Company negotiated the extension of the due date of this loan to April 30, 1996, and in connection with such extension, the interest rate was increased to 10%, the Company reduced the exercise price of the warrants previously granted to $1.50 per share, and the Company granted new warrants to purchase 200,000 shares of Common Stock at $2.00 per share through the earlier of April 30, 1997, or 60 days subsequent to the repayment of the loan.
Borrowings are collateralized by substantially all of the Company's property, equipment, receivables and inventory. The credit agreement contains certain covenants, including those that prohibit the Company from selling substantially all of its assets and incurring additional collateralized indebtedness in excess of $50,000. From time to time, certain vendors of the Company file mechanics liens against the Company's oil and gas properties in order to secure their claims. These liens are typically cleared in a relatively short period of time and management believes they are insignificant to the Company's financing activities.
The aggregate maturities of long-term debt are as follows:
Year Ending December 31, - ------------
1996 $404,237 1997 4,844 1998 5,538 1999 12,709 ------- $427,328 ========
8. COMMITMENTS: -----------
The Company currently rents administrative office space and equipment under noncancelable leases. Total rental expenses incurred under operating leases amounted to $55,205, $64,717, and $67,382 for the years ended December 31, 1993, 1994, and 1995, respectively.
The total minimum rental commitment as of December 31, 1995 is as follows:
1996 $ 57,061 1997 52,200 1998 29,393 -------- $138,654 ========
In 1995, the Company entered into a financial consulting agreement with Vantage Resource Group LLP ("Vantage") whereby the Company agreed to pay Vantage 3% of the gross proceeds from any debt or equity financing from any person directly or indirectly introduced to the Company by Vantage. The Company also agreed to pay Vantage 1% of the proceeds from any financing obtained from any other source. The Company agreed to pay these amounts during the term of the consulting agreement, which expires in June 1996, and for 12 months thereafter. The Company has issued 100,000 warrants exercisable at the lower of $1.50 or the average of the closing price of the common stock for the 20 business days preceding the exercise date. The warrants expire in June 2000. The Company has agreed to issue an additional 100,000 warrants in the event Vantage is successful in obtaining financing in excess of $1,000,000.
9. OIL AND GAS PROPERTY CONVEYANCES: --------------------------------
During 1994, the Company entered into an agreement with Barrett Resources Corporation ("Barrett") whereby Barrett agreed to pay 80% of the first $2,400,000, or as much as $1,920,000, of the costs to drill and, if practical, complete three oil wells in the Company's Eagle Springs field. In January 1995, Barrett elected to retroactively assign ownership of the Eagle Springs properties and leaseholds to the August 1, 1994 effective date of the agreement. The accompanying financial statements give effect to Barrett's election as of August 1, 1994, with no gain or loss recognized since this transaction represented a pooling of capital. After the initial $2,400,000 of expenditures, additional development costs are being shared 60% by the Company and 40% by Barrett.
In 1994, Krutex entered into an agreement with an unrelated third party operator under which the operator agreed to pay Krutex $50,000 to earn 75% of Krutex's working interest in the West Salt Flat Field. In addition, Krutex granted the operator an option to purchase Krutex's remaining 25% interest for $25,000 through February 2, 1995. This option was exercised in 1995 and the Company recognized a loss of $434,521 in 1994.
10. SUBSEQUENT EVENTS: -----------------
In March 1996, the Company issued 500 shares of 6% convertible preferred stock for net proceeds of $472,500. From May 1996 through March 1998, at the election of the holder, each share may be converted into that number of shares
of the common stock determined by dividing $1,000 plus all accrued but unpaid dividends on such a share by the lesser of (i) $1.50 or (ii) 75% of the average closing bid price of the common stock as reported by NASDAQ for the trading date immediately preceding the date of conversion.
Under certain conditions, this stock may be redeemed after April 1, 1997 at a price of 133% of the original issue price. The Company has agreed to register the resale of the common stock issuable on conversion in certain circumstances.
11. IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS (UNAUDITED): ----------------------------------------------------------
In March 1995, the Financial Accounting Standards Board issued a new Statement titled "Accounting for Impairment of Long-Lived Assets." This new standard is effective for years beginning after December 15, 1995 and will change the Company's method of determining impairment of proved oil and gas properties. Management estimates that the application of the new standard would have increased the provision for impairment of oil and gas properties by approximately $450,000 as of December 31, 1995. The Company plans to adopt the new standard in the first quarter of 1996.
In October 1995, the Financial Accounting Standards Board issued a new statement titled "Accounting for Stock-Based Compensation" (SFAS 123). The new statement is effective for fiscal years beginning after December 15, 1995. SFAS 123 encourages, but does not require, companies to recognize compensation expense for grants of stock, stock options, and other equity instruments to employees based on fair value. Companies that do not adopt the fair value accounting rules must disclose the impact of adopting the new method in the notes to the financial statements. Transactions in equity instruments with non- employees for goods or services must be accounted for on the fair value method. For transactions with employees, the Company currently does not intend to adopt the fair value accounting under SFAS 123, and will be subject only to the related disclosure requirements.
12. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES: --------------------------------------------------
All oil and gas operations of the Company and its subsidiaries are conducted in the United States. Capitalized costs relating to oil and gas producing activities are as follows:
DECEMBER 31, --------------------
1994 1995 ---------- ----------- Proved oil and gas producing properties $4,145,656 $6,292,331 Wells in progress 137,285 113,986 Unproved properties, net of allowance for impairment of $250,000 in 1995 850,597 468,318 --------- --------- 5,133,538 6,874,635 Accumulated depreciation, depletion and (1,361,802) (2,183,423) ---------- ---------- amortization $3,771,736 $4,691,212 ========== ==========
Costs incurred in oil and gas producing activities, whether capitalized or expensed, during the three years ended December 31, 1993, 1994, and 1995 are as follows:
1993 1994 1995 ---------- ---------- ----------
Acquisition costs $ 843,871 $ 347,393 $ 46,597 ========= ========== =========
Exploration costs $2,249,942 $1,829,943 $1,024,008 ========== ========== ==========
Development costs $2,166,883 $1,232,606 $2,414,265 ========== ========== ==========
Estimated Quantities of Proved Oil and Gas Reserves (Unaudited) - Proved oil ---------------------------------------------------------------
and gas reserves are the estimated quantities of crude oil, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. However, reserve information should not be construed as the current market value of the Company's oil and gas reserves or the costs that would be incurred to obtain equivalent reserves. Reserve calculations involve the estimation of future net recoverable reserves of oil and gas and the timing and amount of future net revenues to be received therefrom. These estimates are based on numerous factors, many of which are variable and uncertain. Accordingly, it is common for the actual production and revenues to vary from earlier estimates.
At December 31, 1995, over 40% of the Company's reserves are attributable to undeveloped properties which are scheduled to be drilled over the next two years at an estimated cost of approximately $2,750,000. As of December 31, 1995, the Company has minimal working capital and, therefore, may be unable to develop its reserves unless additional capital is raised, financing is obtained and/or the property interests are sold. If the property interests are farmed out to fund development, the Company's revenue interest will decrease.
Reserve estimates for recently drilled wells and undeveloped properties are subject to substantial upward or downward revisions after drilling is completed and a production history obtained. Hence, reserve estimates and estimates of future net revenues from production may be subject to substantial revision from year to year. Reserve information presented herein is based on reports prepared by independent petroleum engineers for 1993 and 1995, and by a petroleum engineer who was employed by the Company for 1994.
Set forth below is the unaudited summary of the changes in the net quantities of the Company's proved oil reserves (in barrels) as of December 31, 1993, 1994, and 1995:
1993 1994 1995 --------- --------- --------
Proved reserves, beginning of 506,000 1,144,000 1,848,000 year Production (29,000) (38,000) (88,000) Purchase of reserves in place 627,000 308,000 - Discoveries, extensions and other additions - 994,000 724,000 Sale of reserves in place - (737,000) - Revisions of previous 40,000 177,000 (478,000) estimates --------- --------- --------
Proved reserves, end of year 1,144,000 1,848,000 2,006,000 ========= ========= =========
Proved developed reserves, end of 754,000 992,000 1,175,000 --------- --------- --------- year
Standardized Measure of Discounted Future Net Cash Flows (Unaudited) --------------------------------------------------------------------
Statement of Financial Accounting Standards No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines which are briefly discussed below.
Future cash inflows and future production and development costs are determined by applying year-end prices and costs to the estimated quantities of oil and gas to be produced. Estimated future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.
The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and, as such, do not necessarily reflect the Company's expectations for actual revenues to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates are the basis for the valuation process.
DECEMBER 31, -------------------------------
1993 1994 1995 ---------- ----------- -----------
Future cash inflows $12,445,000 $21,178,000 $25,926,000 Future production costs (4,749,000) (7,439,000) (11,092,000) ) Future development costs (2,808,000) (2,352,000) (2,754,000) Future income tax expense - - - ---------- ---------- --------- Future net cash flows 4,888,000 11,387,000 12,080,000
10% annual discount for estimated timing of cash flows (2,692,000) (6,276,000) (5,880,000) ---------- ---------- ----------
Standardized measure of discounted future $2,196,000 $5,111,000 $6,200,000 of cash flows ---------- ---------- ----------
The following are the principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 1993, 1994, and 1995:
1993 1994 1995 ---------- ----------- --------
Standardized measure, beginning $1,215,000 $2,196,000 $5,111,000 of year Sales of oil and gas, net of (6,000) (19,000) (593,000) production costs Extensions, discoveries and - 4,165,000 4,122,000 other, net Purchase of reserves in place 3,136,000 1,364,000 - Sale of reserves in place - (1,118,000) - Net change due to revisions in 120,000 142,000 (2,565,000) quantity estimates Net change due to changes in (3,161,000) 346,000 (2,000) prices and production costs Net change in future development 472,000 (2,234,000) (384,000) costs Net change in income taxes 298,000 - - Accretion of discount 122,000 269,000 511,000 --------- --------- -------- Standardized measure, end of $2,196,000 $5,111,000 $6,200,000 year ---------- ---------- ----------