ITEM 1. BUSINESS.
GENERAL DEVELOPMENT OF BUSINESS
Golden Oil Company (the "Company") is a diversified business whose current scope of operations includes oil and gas operation and development, but with increasing emphasis on diversification into other sectors. Over the last several years the Company has continued to develop its properties and has expanded through corporate transactions, primarily asset purchases and mergers including the purchase, outside of the oil and gas sector, of an interest in a commercial real estate venture. Management places strong emphasis upon further diversification. Subject to a number of factors including the success of its ongoing secondary recovery projects, future prices of oil and gas production and properties; the availability of financing; and opportunities for diversification, management anticipates that the Company will accelerate its plans to diversify beyond the independent oil and gas sector.
Following approval by its stockholders in 1986, the Company implemented proposals to reincorporate in Delaware, to approve issuance of a new class of common stock ("Class B Common") and to declare a warrant dividend on its shares of common stock ("Common Stock"). The Class B Common has certain enhanced voting rights compared to the Common Stock. As of December 31, 1997, the Company had outstanding 1,524,291 shares of Common Stock and 22,254 shares of Class B Common.
During September 1989, the Company acquired two public oil and gas exploration and production companies by merging them into Company subsidiaries. At the Company's Annual Meeting held during December 1989, stockholders approved a change of the parent corporation's name to Golden Oil Company. During 1992 the Company purchased the oil and gas related assets of Cobb Resources Corporation ("Cobb"). Due to increased eligibility requirements for initial and ongoing listing, effective December 19, 1997 the Company's stock is no longer traded on the National Association of Securities Dealers Automated Quotation System ("NASDAQ"). The trading market for the Company's Common Stock continues through the facilities of the Over the Counter ("OTC") Bulletin Board market service. The OTC Bulletin Board is electronic and screen-based with trading continuing under the symbol "GOCO".
With regard to the oil and gas sector, the Company's objectives are to increase its net reserves, cash flow and scope of operations primarily through development of Company-operated properties and possible acquisitions. The Company believes that factors including price volatility and other unfavorable economic conditions have negatively affected the independent oil and gas industry over recent years, and have driven operators to seek economies of scale through consolidation and administrative cost cutting, and to diversify or reposition operations away from oil and gas exploration and production. Management believes that such factors may continue in the future.
Currently the Company's oil and gas production is concentrated in the San Juan Basin, New Mexico and Osage County, Oklahoma. The Company is focusing on controlling and enhancing the operating performance of its properties. The Company is continuing to develop the secondary reserve potential of its waterflood project in the South Dog Creek field in Osage County, Oklahoma. Since initial discovery and development by the Company in the late 1970s, the South Dog Creek field has produced over 5,000,000 barrels of primary production.
Primary production of the Company's producing properties is in the latter stages of economic operation in both Oklahoma and New Mexico. Development of the Company's South Dog Creek
secondary reserve potential, now classified as "proved undeveloped", continues to be accorded a high operational priority. The Company has obtained permits from the Environmental Protection Agency ("EPA") necessary for water injection throughout the field, and is proceeding with a staged waterflood injection program. Under the program certain marginally producing wells have been converted to water injectors and water supply wells while other producing wells and well equipment have been reworked to increase the wells' fluid volume capacity. The Company is encouraged that its joint working interest owners, which include companies sophisticated in oil and gas operations, have elected to join such development. Initial work has been completed on the Company's principal lease within the field, and water is being injected at gradually increasing volumes to monitor the effect of injection pressure on the subsurface formation. Water injection rates currently are approximately 550 barrels per well per day. On a cumulative basis, approximately 300,000 barrels of water have been injected into the formation under the current program. To date, the field has not exhibited a sustained production response from water injection; however, this is believed to be due primarily to the low fluid levels injected to date relative to the cumulative fluid depletion of the field. Results from development to date indicate at least moderate improvements in production capacity at economic levels.
The Company does not anticipate significant increases in production volumes until further development occurs. The Company plans to continue the development of the South Dog Creek field. The timing and extent of development of the waterflood injection project is subject to, among other factors, the relative magnitude of production response from the development, the availability of additional financing for future development and prices obtainable for oil and gas production. As of December 31, 1997 a substantial majority of the Company's total proved reserves, approximately $8,800,000 of the Company's pretax estimated discounted future net revenues, are classified as proved undeveloped reserves. Since most or all proved undeveloped reserves are related to the Oklahoma waterflood project, the success or failure of the waterflood project is of vital importance to the Company's future.
In recent years, volatility in product prices has caused substantial fluctuation in the year end projected value of the Company's estimated future net revenues from oil and gas production. In the opinion of management, one result of price fluctuations has been to diminish the general attractiveness of onshore North American exploration drilling by small independent companies. Other factors, such as governmental tax, general regulatory and environmental policies, also are believed to have had a negative impact. Accordingly, management has eliminated "wildcat" exploration drilling by the Company on unproven acreage, while emphasizing development and extension of proved reserves and field operations. Another effect of the many adverse economic factors impacting the small oil and gas sector has been to increase the relative attractiveness of diversification to reposition the Company out of the oil and gas sector.
DESCRIPTION OF BUSINESS
OIL AND GAS OPERATIONS. As part of its business activities the Company owns, acquires and sells oil and gas leases and other mineral interests and produces oil and gas. In addition, the Company has conducted exploration and development activities for its own account as well as for joint venture or partnership accounts. If exploration is undertaken, the Company generally attempts to include third party participants. The Company has no current plans to conduct developmental or exploratory drilling projects during 1998 other than with respect to further development of its waterflood injection program.
GOVERNMENT REGULATION. The domestic production and sale of oil and gas are subject to regulation by the Department of Energy. Rates of production have for many years been subject to federal and state conservation laws, and the petroleum industry has been subject to federal tax laws dealing specifically with the industry. The Company is subject to various federal, state and local
regulations regarding, among other things, environmental and ecological matters.In connection therewith, the Company has been significantly impacted by the implementation of environmental regulations related to the remediation and impoundment of surface pits for all of its San Juan Basin properties. The new regulations have required and will require expenditures during 1997 and 1998 projected to be in the range of $350,000 - $500,000 for which the Company estimates its share to be approximately $106,000. See Note 4 to Consolidated Financial Statements.
EMPLOYEES. As of December 31, 1997, the Company had 11 full time employees, including field personnel. The Company also regularly employs part time personnel and retains outside professionals who provide accounting, legal, engineering and other services.
COMPETITION. The Company faces intense competition in the search for and the acquisition of oil and gas reserves; in the marketing of oil and gas production; and in the raising of funds to purchase or develop oil and gas properties. The Company's competitors in the oil and gas sector include companies and individuals, many of which have financial resources, staffs and facilities substantially greater than those of the Company.
Despite negative factors such as product price fluctuations, competition remains intense for acquisition of oil and gas prospects and properties in the size range which is realistic for the Company to consider. The Company's ability to sustain or increase its oil and gas operations depends primarily on the relative success experienced with future development of its existing properties.
Competitive conditions in marketing the Company's products are influenced by factors including the volume of production of other domestic crude oil and of crude oil imports; the proximity of pipelines to producing properties; the regulation by states of allowable rates of production; and the regulation by federal authorities of the marketing of oil and natural gas. All of the foregoing variable factors are influenced by economic and political forces beyond the Company's control and which cannot be predicted with assurance.
FORWARD-LOOKING STATEMENTS. This document includes "forward-looking statements" within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. All statements other than statements of historical facts included in this document, including statements regarding planned capital expenditures, the availability of capital resources to fund capital expenditures, estimates of proved reserves, the Company's financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, such statements are based upon assumptions and anticipated results that are subject to numerous uncertainties. Actual results may vary significantly from those anticipated due to many factors, including oil and gas prices, industry conditions, the prices of goods and services, the availability of support services and the availability of capital resources. In addition, the production of hydrocarbons are subject to governmental regulations and operating risks. All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by such factors.
ADDITIONAL INFORMATION. The Company's business does not presently require expenditure of substantial funds for research and development. Sales of natural gas tend to be influenced by factors including local demand and the availability of gas transportation. Both oil and gas prices tend to respond to seasonal weather conditions, with increased sales prices generally during the colder winter months. The Company does not believe that any other material aspects of its business are significantly seasonal in nature. During 1997, sales to three purchasers accounted for approximately 48%, 30%, and 18%, respectively, of the Company's total revenues. Sales to three purchasers accounted for approximately 46%, 34%, and 17% for the year ended December 31, 1996 and 55%, 28%, and 14% for the year ended December 31, 1995 of the Company's total revenues. No other customer accounted for more than ten percent of the Company's total revenues during those periods. In the opinion of management, if the Company should lose any of its present customers, other customers for the
Company's oil and gas production would be available on terms substantially similar to those available from its major customers at this time. Due to volatility in oil prices and the Company's vulnerability to another severe price downturn such as the industry experienced during 1994, the Company remains alert to opportunities to enter into fixed price oil contracts. Beginning in December 1997, the Company had approximately 40% of its estimated monthly oil production under a fixed price arrangement with one purchaser at an average price of $19.75 per barrel through March 1, 1998.
ITEM 2.
ITEM 2. PROPERTIES.
OFFICE FACILITIES. The Company's headquarters office is located in a commercial office building at 550 Post Oak Boulevard, Suite 550, Houston, Texas 77027. The Company holds an interest of approximately 23% of a limited partnership which owns such building. The Company leases 3,950 square feet of the total of approximately 54,000 square feet of office space in the building under a six year lease through December 15, 2002.
ESTIMATED OIL AND GAS RESERVE INFORMATION. Steven A. Hiraoka & Associates, an independent petroleum engineering firm based in Golden, Colorado, prepared the estimated reserve information for the Company and its wholly owned subsidiaries for the year ended December 31, 1997. The presentation conforms with Securities and Exchange Commission ("SEC") reporting regulations, which require projection of estimated future net revenues based on the prices in effect at the close of the most recent fiscal year. In conformity with SEC reporting regulations, the reserve projections at December 31, 1997 were prepared using an oil price ranging from $16.50 to $19.25 per barrel and gas prices ranging from $1.15 to $2.00 per Mcf. Estimates of proved reserves based on prices in effect at December 31, 1997 have not been filed previously by the Company with, or included in reports to, any federal authority or agency.
Reserve estimates and estimated rates of production are inherently uncertain and imprecise. Accordingly, all reserve data presented is subject to continued evaluation and revision as additional information becomes available. In this regard, it should be noted that since 1985 the petroleum industry has experienced significant volatility in prices obtainable for oil and gas production and that such price volatility directly affects the estimated quantities of oil and gas reserves that are economically recoverable.
Based on the projected economics using prices prevailing on the closing day of each respective year, the tables below set forth the Company's estimated proved and proved developed oil and gas reserves owned by the Company as of the close of the fiscal years indicated. The estimated proved and proved developed oil and gas reserves shown below are based on economic assumptions and future projections. The Company does not believe that such amounts necessarily represent the reserve volumes or amounts which would be actually recoverable at the respective dates shown. As of December 31, 1997 a substantial majority of the Company's total proved reserves, approximately 1,500,000 barrels of the Company's estimated proved reserves, are classified as proved undeveloped reserves.
PROVED PROVED RESERVES DEVELOPED RESERVES ---------------------- --------------------- AS OF OIL(BBLS) GAS(MCF) OIL(BBLS) GAS(MCF) ----------------- --------- --------- ------- --------- December 31, 1997 (1) 2,148,061 911,823 608,849 911,823 December 31, 1996 (2) 1,613,995 1,462,734 593,756 1,462,734 December 31, 1995 (3) 1,298,253 880,158 432,133 880,158
(1) Amounts determined using oil prices ranging from $16.50 to $19.25 per barrel of oil and gas prices ranging from $1.15 to $2.00 per Mcf. Includes reserves of approximately 15,000 barrels of oil and 81,000 Mcf of gas purchased in 1997 from interest holders in Company-operated properties.
(2) Amounts determined using oil prices ranging from $23.30 to $24.60 per barrel of oil and gas prices ranging from $1.89 to $2.75 per Mcf. Includes reserves of approximately 51,000 barrels of oil and 232,000 Mcf of gas purchased in 1996 from interest holders in Company-operated properties.
(3) Amounts determined using oil prices ranging from $17.00 to $17.25 per barrel of oil and gas prices ranging from $1.00 to $1.30 per Mcf.
PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES
The present value of estimated future net revenues before income taxes of proved reserves (which include reserves attributable to secondary waterflood production) of the Company at the dates indicated below was computed according to SEC reporting requirements by discounting the aggregate estimated future net revenues using a discount factor of 10% per year. For additional information see the supplemental unaudited oil and gas information.
The estimated proved and proved developed oil and gas reserves shown below are based on economic assumptions and future projections. The Company does not believe that such amounts necessarily represent the reserve volumes or amounts which would be actually recoverable at the respective dates shown.
PRETAX ESTIMATED DISCOUNTED FUTURE NET REVENUES --------------------------------------------- TOTAL PROVED PROVED DEVELOPED PROVED AS OF RESERVES PRODUCING UNDEVELOPED ----------------- ----------- ---------- ----------- December 31, 1997 (1) $11,529,350 $2,705,451 $ 8,824,082 December 31, 1996 (2) $16,758,460 $4,461,328 $12,297,132 December 31, 1995 (3) $ 9,089,704 $1,924,304 $ 7,165,400
(1) Amounts determined using oil prices ranging from $16.50 to $19.25 per barrel of oil and gas prices ranging from $1.15 to $2.00 per Mcf. Includes proved developed producing reserves with pretax estimated discounted future net revenues of approximately $260,000 purchased in 1997 from interest holders in Company-operated properties.
(2) Amounts determined using oil prices ranging from $23.30 to $24.60 per barrel of oil and gas prices ranging from $1.89 to $2.75 per Mcf.
(3) Amounts determined using oil prices ranging from $17.00 to $17.25 per barrel of oil and gas prices ranging from $1.00 to $1.30 per Mcf.
SECONDARY RECOVERY
In accordance with professional engineering standards, secondary recovery of oil and gas reserves projected to be obtainable through fluid injection or other enhanced recovery techniques for supplementing primary recovery are included as proved undeveloped reserves only after testing by a pilot project or the operation of an installed program in the reservoir provides support for the engineering analysis on which the project or program was based. A preponderance of the Company's total proved reserves as projected above consist of undeveloped reserve volumes and undeveloped reserve values attributable to projected secondary recovery through waterflood development.
Currently, the Company's oil and gas production is concentrated in the San Juan Basin, New Mexico and Osage County, Oklahoma. The Company is focusing on controlling and enhancing the operating performance of its properties. The Company is continuing to develop the secondary reserve potential of its waterflood projects in the South Dog Creek field in Osage County, Oklahoma. Since initial discovery and development by the Company in the late 1970s, the South Dog Creek field has produced over 5,000,000 barrels of primary production.
Primary production of the Company's producing properties is in the latter stages of economic operation in both Oklahoma and New Mexico. Development of the Company's South Dog Creek secondary reserve potential, now classified as "proved undeveloped", continues to be accorded a high operational priority. The Company has obtained permits from the Environmental Protection Agency
("EPA") necessary for water injection throughout the field, and is proceeding with a staged waterflood injection program. Under the program certain marginally producing wells have been converted to water injectors and water supply wells while other producing wells and well equipment have been reworked to increase the wells' fluid volume capacity. The Company is encouraged that its joint working interest owners, which include companies sophisticated in oil and gas operations, have elected to join such development. Initial work has been completed on the Company's principal lease within the field, and water is being injected at gradually increasing volumes to monitor the effect of injection pressure on the subsurface formation. Water injection rates currently are approximately 550 barrels per well per day. On a cumulative basis, approximately 300,000 barrels of water have been injected into the formation under the current program. To date, the field has not exhibited a sustained production response from water injection; however, this is believed to be due primarily to the low fluid levels injected to date relative to the cumulative fluid depletion of the field. Results from development to date indicate at least moderate improvements in production capacity at economic levels.
The Company does not anticipate significant increases in production volumes until further development occurs. The Company plans to continue the development of the South Dog Creek field. The timing and extent of development of the waterflood injection project is subject to, among other factors, the relative magnitude of production response from the development, the availability of additional financing for future development and prices obtainable for oil and gas production. As of December 31, 1997 a substantial majority of the Company's total proved reserves, approximately $8,800,000 of the Company's pretax estimated discounted future net revenues, are classified as proved undeveloped reserves. Since most or all proved undeveloped reserves are related to the Oklahoma waterflood project, the success or failure of the waterflood project is of vital importance to the Company's future.
PRODUCTIVE WELLS AND ACREAGE. As of December 31, 1997, the Company owned working interests in 219 gross (112.8 net) wells of which there were 204 gross (102.8 net) oil wells and 15 gross (10.1 net) gas wells. Additionally the Company held approximately 11,090 gross (5,231 net) producing acres.
UNDEVELOPED ACREAGE. As of December 31, 1997, the Company held certain undeveloped oil and gas leaseholds in New Mexico which covered approximately 4,520 gross and 4,140 net acres. The undeveloped acreage is held pursuant to leases from landowners or governmental entities.
PRODUCTION, UNIT PRICES AND COSTS. Information with respect to production volumes, average unit prices and costs for the dates indicated are set forth below:
The average production costs per unit of production (with oil and gas converted to a common unit of measure based on six Mcf of gas to one barrel of oil) were $12.38, $9.49 and $8.37 for the years ended December 31, 1997, 1996 and 1995, respectively. The increase in average production costs per unit of production in 1997 as compared to 1996 is due to a significant increase in workovers to bring previously shut-in wells into production and due to substantial costs incurred with respect to the Company's pit impoundment project (See Note 4 to Consolidated Financial Statements). Average production costs per unit of production are expected to remain at present levels until completion of the pit impoundment project which is required to be completed by December 31, 1998.
DRILLING ACTIVITY. The Company did not participate in the drilling of any exploratory or development wells for the years ended December 31, 1997, 1996 and 1995.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
The Company has been named as a defendant in certain lawsuits arising in the ordinary course of business. While the outcome of such lawsuits cannot be predicted with certainty, management does not expect these matters to have a material adverse effect on the financial position, cash flows and results of operations of the Company.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matters were submitted to vote by security holders during the fourth quarter of 1997.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The Company's Common Stock was traded through the facilities of the National Association of Securities Dealers, Inc. ("NASDAQ") through December 18, 1997. The ranges of reported high and low bid quotations for the Company's Common Stock for each quarterly period within the two years ended December 31, 1997 are set forth below. Quotations through December 18, 1997 are as reported by NASDAQ-small cap, the market on which the Company's Common Stock was previously traded. Subsequent to December 18, 1997 quotations are as reported by the Over The Counter ("OTC") Bulletin Board market service.
Due to increased NASDAQ eligibility requirements, the Company no longer meets certain minimum asset and capital and surplus requirements for ongoing listing and as a result the Company's Common Stock was no longer eligible for NASDAQ listing as of December 19, 1997. The trading market for the Company's Common Stock continues through the facilities of the OTC Bulletin Board market service. The OTC Bulletin Board is electronic and screen-based with trading continuing under the symbol "GOCO".
The quotations listed below do not necessarily represent actual transactions, but represent quoted prices between dealers without retail markup, markdown or commissions.
HIGH LOW QUARTER ENDED BID BID ---------------- -------- -------- December 31... $ 1.88 $ 0.13 September 30.. 0.59 0.13 June 30....... 0.50 0.25 March 31...... 0.63 0.19
December 31... $ 1.19 $ 0.25 September 30.. 0.75 0.25 June 30....... 2.50 0.50 March 31...... 0.75 0.25
As of February 13, 1998 there were approximately 3,700 stockholders of record of the Company's Common Stock. On March 13, 1998 the Common Stock was listed at a range of approximately $0.19 low bid and $0.44 high bid.
The Company has not paid any cash dividends on its Common Stock and does not expect to do so in the foreseeable future.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
The following selected financial information has been derived from, and is qualified by reference to and should be read in conjunction with, the Company's Consolidated Financial Statements and Notes thereto included elsewhere herein, except that data relating to income statement information for the years ended December 31, 1994 and 1993, and balance sheet information at December 31, 1995, 1994 and 1993 which have been derived from previously published financial statements.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Golden Oil Company (the "Company") is a diversified business whose current scope of operations includes oil and gas operation and development, but with increasing emphasis on diversification into other sectors. Over the last several years the Company has continued to develop its properties and has expanded through corporate transactions, primarily asset purchases and mergers including the purchase, outside of the oil and gas sector, of an interest in a commercial real estate venture. Management places strong emphasis upon further diversification. Subject to a number of factors including the success of its ongoing secondary recovery projects, future prices of oil and gas production and properties; the availability of financing; and opportunities for diversification, management anticipates that the Company will accelerate its plans to diversify beyond the independent oil and gas sector. The Company's current objectives in the oil and gas sector look primarily to waterflood development of its proved reserves and to possible corporate transactions.
The Company expects, absent a continued decline in oil prices, to generate cash flows from operations and financings during 1998 sufficient to meet its operating and budgeted capital requirements. However, in order to continue its project to develop reserves classified as proved undeveloped and to further its plan for diversification and repositioning, the Company will be required to make additional financing arrangements. In 1996, the Company was advised by its commercial lenders that additional credit for the Company, or the renewal and extension of existing bank credit, could not be granted to the Company unless it could provide an independent third party guarantor. Such guarantor was required to unconditionally and personally guarantee all principal and interest loaned to the Company under the credit agreement. Such guarantee was provided by a principal officer of the Company. The Company believes that in order to obtain additional financing in the future, similar guarantees may be required by lenders. The Company plans to restructure its existing loan and increase its borrowings in 1998.
The Company expects to use proceeds from future borrowings to continue development of the South Dog Creek waterflood program, to complete the pit impoundment program, to meet working capital requirements, for purchases of interests in the Company's principal areas of field operation and in connection with transactions aimed at repositioning the Company. Based on the Company's working capital position and oil and gas prices in March 1998, no assurances can be made as to the availability or terms of new financing arrangements. Accordingly, ongoing development of the Company's secondary reserve recovery project could be delayed.
Prevailing prices obtainable for oil and gas production are dependent on numerous factors beyond the Company's control including political, economic and regulatory developments as well as competition from other sources of energy. The energy markets are historically volatile and there can be no assurance that oil and gas prices will not be subject to significant fluctuations in the future as they have been in the past. Regardless of whether oil or gas prices increase or decline, the Company may elect to enter corporate transactions to divest oil and gas properties or interests; purchase or dispose of real estate interests; recapitalize; reposition itself with new sectors of operation; or enter new financing agreements.
Beginning in December 1997, the Company held a fixed price oil contract for approximately 40% of its monthly oil production. Such contract extended through March 1, 1998 at an average price at the wellhead of approximately $19.75 per barrel. The Company plans to obtain new fixed price oil contracts in the near future. The Company believes it enters into fixed price arrangements with a financially capable purchasers and does not anticipate nonperformance by counterparties to such transactions.
LIQUIDITY AND CAPITAL RESOURCES. The Company's operations during 1997 and 1996 were funded primarily through existing working capital, borrowings under its credit facilities and internally generated funds from operating activities. Management anticipates that to meet its major strategic and operational objectives, the Company will need to arrange new financing through joint ventures, additional borrowings, asset sales, or other means. There can be no assurance as to the availability,
timing or amount of additional financing arrangements, or any assurance that the Company's objectives will be achieved.
Cash flow from operating activities was $132,072 for 1997 versus $289,091 during 1996. The decrease is primarily due to expenditures associated with pit closures in its San Juan Basin properties offset by increases in oil and gas revenues. Such increase in revenues have been utilized primarily to fund the ongoing waterflood development project in Oklahoma, purchase interests in Company-operated properties and pit closure costs.
At December 31, 1997 the Company had a working capital deficit of $987,000 and a current ratio of .39 to 1.00 compared to a working capital deficit of $989,000 and a current ratio of .40 to 1.00 as of December 31, 1996. The working capital deficit is relatively unchanged due primarily to the use of cash generated from operating activities to fund capital expenditures for the Company's secondary recovery project, the pit impoundment program, and to a lesser extent, the purchases of additional interests in properties as discussed above.
In April 1996, the Company entered into a credit agreement with a commercial bank in Albuquerque, New Mexico ("Bank") under which the Company obtained an extension of existing borrowings and increased the credit available to it from $150,000 to $400,000. The maturity schedule of the Company's debt was extended to four years, subject to certain conditions. As a condition of extending the current maturity and obtaining additional credit, the Bank required the entire credit facility to be independently, personally guaranteed by a person acceptable to the Bank and to be collateralized by the Company's New Mexico oil and gas properties. An officer of the Company provided the independent, personal guarantee. The credit agreement bears interest at 2% over the Bank's prime lending rate, adjusted periodically. Such interest rate was 11.5% at December 31, 1997.
Proceeds from the credit facility were utilized to refinance short-term debt then outstanding; to acquire additional interests in Company-operated oil and gas properties; and for working capital. At the time the new credit agreement was obtained, the Company had a working capital deficit of approximately $1,000,000. In order to obtain the new financing the Company was required by the lending Bank to provide a personal guarantee from a principal officer of the Company for repayment in full to the Bank of all principal, interest and related costs. Due to its financial position, the Company was not able to pay a cash fee for the personal guarantee required by the Bank as a condition of extending credit to the Company. In lieu of cash payment, the Company proposed to pay the guarantee fee by delivering to the guarantor warrants to purchase unregistered shares of its common stock. On March 29, 1996 after obtaining the written opinion of fairness from independent investment banking advisors, the Board of Directors approved the credit agreement and the payment and delivery to the guarantor of warrants to purchase 250,000 unregistered shares of common stock of the Company through March 2006 for an exercise price of $.20 per share. For the calendar year 1997 the guarantor exercised rights to purchase 100,000 shares of common stock granted under the warrants.
Under the Company's present credit agreement, the Company is required to make monthly payments of principal and interest of approximately $10,400 through April 2000. As of March 31, 1998, the Company had $59,000 remaining available for purchases of oil and gas properties or other bank-approved uses under the terms of the agreement.
The Company also maintained a credit facility in the original amount of $100,000 with a commercial bank in Tulsa, Oklahoma and had borrowed $70,000 under such line of credit facility. In March 1996, the Company began reducing the principal amount borrowed under this credit facility by $5,000 each month. Such line of credit was retired in April 1997.
In March 1993, an agreement was reached between the Company and Calumet Oil Company, the principal operators in the South Dog Creek, Oklahoma field, aimed at enhancing and extending the producing life of the field by injection of water into the Mississippian formation in ten wells covering four separate quarter section leases. The operators filed for a water injection permit with the Environmental Protection Agency ("EPA"), and during October 1993, a field-wide water injection permit was granted by the EPA to the Company and another interest holder and operator. During the fourth quarter of 1995 the Company initiated a limited waterflood injection program on one of its operated leases believed to have demonstrated engineering potential for success. Under the program certain marginally producing wells were converted to water injectors and producing wells and well equipment were reworked to increase the wells' fluid volume capacity. The cost of the initial phase of the waterflood project on this lease approximated $305,000 through December 1997, exclusive of operating fees charged by the Company, of which the Company's share was approximately $226,000. The Company funded its share of costs through internally generated cash flows with the balance paid by outside working interest owners who elected to join the project. Management anticipates that future development costs will be funded through a combination of internally generated funds and additional financing.
The Company continues to gradually increase the rate of water injection into the producing formation. To date, the field has not exhibited any substantial, sustained increase in production from water injection and the Company does not anticipate significant increases in overall production volumes from the field unless further development is implemented across a more extensive area and such further development is successful. Management will continue to evaluate the results of current development before determining whether or to what extent to undertake additional development. Currently, rates of total water injection, including reinjected water, are approximately 1,600 barrels per day into three injection wells. The Company is currently reviewing alternatives for the acquisition or development of additional water sources for the Company's injection plan; however, source water supply is not expected to be a material limiting factor in the overall project. To date approximately 300,000 barrels of new water have been injected into the producing formation. Based on the current engineering projection, at least 650,000 new barrels will be required to reach the level at which localized repressurization may be expected to occur. Based on indications available from the localized response to water injection to date, the Company plans to continue its injection program. If in the future sufficient production response is achieved and sustained, the Company will pursue a field-wide implementation of its waterflood plan. The feasibility and overall scheduling of full scale, field-wide development for water injection remains subject to, among other things, engineering advice based on the localized injection summarized above; actual and projected oil prices; and the availability of additional financing. At this time, due to the variables discussed above, the Company is not able to provide a definitive estimate of overall projected waterflood costs. As results are received and analyzed, the Company will continue to review the actual and projected overall costs of the waterflood project. Subject to the foregoing the Company is using a working projection for its share of overall project costs on the order of $750,000, inclusive of $305,000 of costs already incurred. Subject to the availability of funds, the Company is projecting capital expenditures in 1998 for this project of $107,000.
In recent years the Bureau of Land Management ("BLM") of the U.S. Department of the Interior has implemented extensive national regulations for the handling and maintenance of produced water from well sites on all federal lands. The stated objective of the regulations is to provide guidance for closure of unlined surface impoundments in a manner that assures protection of fresh waters, public health and the environment. The regulations require oil and gas companies to eliminate the use of unlined surface impoundments in the operation of wells and to remediate and replace them with lined and enclosed surface pits. Such federal government regulations provide for implementation on a region-by-region basis.
In January 1997, the regions designated by the federal government were expanded to include 81 wells in the Company's field of operations in New Mexico. Pursuant to the Company's operating permit from the Jicarilla Apache Indian Nation, the Company's operating subsidiary was required to develop a plan for remediation and improvement for every well site. In May 1997 the BLM and the Jicarilla Environmental Protection Office ("EPO") approved the initial phase of the remediation and improvement plan ("Plan"). The initial phase of the Plan provided for the remediation and enclosure of 14 surface pits located at the well sites by June 30, 1997 in accordance with applicable Ordinance 95-0-308-03. Surface pits on such well sites and on an additional 14 well sites have been enclosed and soil remediation is complete in accordance with BLM and EPO regulations. Work is ongoing for an additional 25 well sites. Total costs to date of the project, including the Company's and all third parties interests, vary by well site but have ranged between $2,000 to $10,000 per well site, or approximately $110,000 of a total projected cost of $350,000 to $500,000.
Remediation on all well sites operated by the Company in New Mexico is currently required to be completed by December 1998. Numerous oil and gas producers in the region, including the Company, are seeking extensions of such date but have not yet received them. The total cost of such work is subject to a number of variable expense factors including, among others, the cost and manner of disposal of removed soil and the amounts of soil that may be required to be removed. The Plan allows relatively broad soil disposal options; however, other more costly soil disposal alternatives may be deemed necessary or may be mandated by the regulatory agencies governing the remediation and impoundment programs.
Based upon the preliminary information available at this time, the Company has estimated the total cost to complete the entire remediation and pit impoundment program in this region to be in the range of approximately $350,000 to $500,000. Total costs could vary significantly from such estimate due to the numerous variable factors discussed above. In recognition of the above variables the Company has charged a provision reflecting its preliminary estimate of its share of such costs, net of operating charges, of approximately $106,000 to earnings as of December 31, 1997. The adequacy of such provision is periodically reviewed and adjusted by the Company as actual costs are incurred. Costs to complete the pit impoundment program are expected to be funded through internally generated cash flows.
Due to factors including certain changes in tax law, adverse changes in the economics of exploration drilling and the availability to the Company of alternative uses of capital, during the late 1980s the Company eliminated exploration activities. If the Company undertakes further exploration programs in the future, it intends to continue its policy of sharing exploration risks with third party drilling participants. Certain of the Company's oil and gas leases require ongoing drilling arrangements for periodic development of proved reserves. The Company's principal development obligations under such agreements have been suspended pending clarification of title assignments on certain federal leases. The Company expects to obtain drilling participation from industry partners so as to reduce the amount of the Company's future required drilling commitments. Capital expenditures for development of properties other than the South Dog Creek field have been suspended pending additional financing.
The production and sale of oil and gas are subject to a variety of federal, state and local government regulations, including regulations concerning the prevention of waste, the discharge of materials into the environment, the conservation of natural gas and oil, pollution, permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, the unitization of pooling of properties and various other matters. Many jurisdictions have at various times imposed limitations on the production of gas and oil by restricting the rate of flow for gas and oil wells below the actual capacity to produce. The Company believes it is in substantial compliance with currently applicable
environmental and other governmental laws and regulations. However, governmental laws and regulations have continued to impose increasingly strict requirements on companies for water and air pollution control and solid waste management. As a result, it is likely that the Company will incur additional costs for compliance with such regulations in the future.
RESULTS OF OPERATIONS
1997 COMPARED TO 1996. For the year ended December 31, 1997, oil and gas revenues from production totaled $1,608,583 compared to $1,507,407 for the previous year, a net increase of $101,176 or approximately 6.7%. The increase in oil and gas revenue is primarily attributable to an increase in average oil price of $1.34 per barrel from $19.56 per barrel during 1996 to $20.90 per barrel during 1997. Additionally, average gas prices increased $0.47 per Mcf from $1.37 per Mcf during 1996 to $1.84 per Mcf during 1997. Production volumes for oil remained relatively unchanged at 60,594 barrels in 1997 compared to 60,998 in 1996 due to purchases of interests in Company-operated properties offset by natural production declines. Gas volumes decreased 53,653 Mcf from 239,512 Mcf in 1996 to 185,859 Mcf in 1997 due to production downtime on certain gas-producing wells and a significant production decline on certain high-rate gas producing wells.
Production costs totaled $1,133,547 during 1997 compared to $957,443 in 1996, an increase of $176,104 or approximately 18.4%. Such increase is primarily due to the production costs associated with the purchases of additional interests in Company-operated properties, increased operating costs related to the waterflood project in Oklahoma and an above average number of well workovers in its San Juan Basin field in New Mexico. Pit impoundment costs, net to Golden, to date were $105,837.
During 1997, the Company's depreciation, depletion and amortization expense decreased to $299,709 compared to $325,502 for the prior year. Depletion expense per equivalent unit of production increased to $2.99 per barrel in 1997 from $2.89 per barrel in 1996.
During 1997, general and administrative expenses were $332,695 compared to $387,464 for the prior year, a decrease of $54,769 or 14.1%. The decrease is primarily due to increased operating fees allocable to outside interest owners in the Company's Oklahoma and New Mexico field operations.
The Company reported a net gain on the disposition of oil and gas properties, equipment, inventory and other assets of $19,715 during 1997 compared to a net loss on the disposition of oil and gas properties, equipment, inventory and other assets of $12,023 during 1996. The 1997 gain arose from the sale of certain non-strategic wells and well equipment. The 1996 loss arose from the writedown to market value of certain field equipment.
Interest expense decreased to $19,937 in 1997 compared to $24,777 in 1996 due to reductions in average principal amounts of debt outstanding during 1997.
Primarily reflecting the factors discussed above, the Company reported a net loss for the year ended December 31, 1997 of $236,796 compared to a net loss of $226,160 for the prior year.
1996 COMPARED TO 1995. For the year ended December 31, 1996, oil and gas revenues from production totaled $1,507,407 compared to $1,245,986 for the previous year, a net increase of $261,421 or approximately 21.0%. The increase in oil and gas revenue is primarily attributable to an increase in average oil price of $2.44 per barrel from $17.12 per barrel during 1995 to $19.56 per barrel during 1996. Additionally, average gas prices increased $0.40 per Mcf from $0.97 during 1995 to $1.37 during 1996. Gas production volumes increased approximately 6,900 Mcf and oil production volumes increased approximately 2,400 barrels during 1996 compared to 1995 reflecting the effects of
field management, weather and production from additional purchases of interests in leases operated by the Company.
Production costs totaled $957,443 during 1996 compared to $814,841 in 1995, an increase of $142,602 or approximately 17.5%. Oil production volumes increased to 60,998 barrels during 1996 compared to production volumes of 58,626 barrels in 1995. Gas production volumes increased to 239,512 Mcf during 1996 compared to production volumes of 232,655 in 1995. The increases in both production costs and volumes produced are attributable to purchases of additional interests in Company operated properties in New Mexico partially offset by natural production decline. Production costs per barrel of oil equivalent increased as a result of increased well maintenance costs incurred in 1996.
During 1996, the Company's depreciation, depletion and amortization expense decreased to $325,502 compared to $508,745 for the prior year. The decrease is primarily attributable to upward revisions of reserve estimates due to increases in oil and gas prices and the Company changing its depletion method on producing oil and gas properties from the property-by-property basis to the field basis of applying the unit-of-production method. The cumulative effect of the Company changing its method of accounting for depletion reduced income for the year ended December 31, 1996 by $39,770. See Note 1 to the Consolidated Financial Statements for a discussion of the change in accounting method for depletion. Depletion expense per equivalent unit of production decreased to $2.89 per barrel in 1996 from $4.83 per barrel in 1995.
During 1996, general and administrative expenses were $387,464 compared to $431,701 for the prior year, a decrease of $44,237 or 10.0%. The decrease is attributable to continuing reductions in corporate fixed costs and increases in operating fees charged to outside working interests in Company operated properties.
The Company reported a net loss on the disposition of oil and gas properties, equipment, inventory and other assets of $12,023 during 1996 compared to a net gain on the disposition of oil and gas properties, equipment, inventory and other assets of $12,576 during 1995. The 1996 loss arose from the writedown to market value of certain field equipment. The 1995 gain arose from the sale of non-strategic properties which the Company elected to sell due to marginal production and limited development potential. Additionally, the Company charged to operations in the prior year $66,142 for previously deferred property acquisition costs.
Interest expense decreased to $24,777 in 1996 compared to $31,416 in 1995 due to reductions in average principal amounts of debt outstanding during 1996. Other income (expense) in 1996 primarily reflects the accrual of $25,000 for a guarantee fee in connection with the Company's new credit facility. See Note 6 to the Consolidated Financial Statements.
Primarily reflecting the factors discussed above, the Company reported a net loss for the year ended December 31, 1996 of $226,160 compared to a net loss of $573,177 for the prior year.
RECENTLY ISSUED ACCOUNTING PRONOUCEMENTS
In June 1997, the FASB issued Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income" ("Statement No. 130"). The statement establishes standards for reporting and display of comprehensive income and its components. In June 1997, the FASB also issued Statement of Financial Accounting Standards No. 131, "Disclosures About Segments of an Enterprise and Related Information" ("Statement No.131"). The statement specifies revised guidelines for determining an entity's operating and geographic segments and the type and level of financial
information about those segments to be disclosed. The Company will adopt the provisions of Statements No. 130 and 131 in its 1998 financial statements.
YEAR 2000 ISSUES
Year 2000 issues result from the inability of computer programs or computerized equipment to accurately calculate, store or use a date subsequent to December 31, 1999. The erroneous date can be interpreted in a number of different ways; the year 2000 may be represented as the year 1900. This could result in a system failure or miscalculations causing disruptions of operations, including among other things, a temporary inability to process transactions, send invoices or engage in similar normal business.
The Company has recently completed an assessment of its financial and operational software systems to ensure compliance. The estimated cost of compliance is expected to be immaterial to results of operations and cash flows. The Company believes that the potential impact, if any, of these systems not being Year 2000 compliant will at most require employees to manually complete otherwise automated tasks or calculations and it should not impact the Company's ability to continue exploration, drilling, production or sales activities.
The Company plans to initiate communication with its significant suppliers, business partners and customers to determine the extent to which the Company is vulnerable to those third parties' failure to correct their own Year 2000 issues. There can be no guarantee, however, that the systems of other companies on which the Company's systems rely will be timely converted, or that a failure to convert by another company, or a conversion that is incompatible with the Company's systems would not have a material adverse effect on the Company. The Company has not determined its contingencies related to the Year 2000 issue with respect to products sold to third parties.
The Company has and will utilize both internal and external resources to complete tasks and perform testing necessary to address the Year 2000 issue. The Company does not anticipate that it will incur any significant costs relating to the assessment and remediation of Year 2000 issues.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
PAGE ---- Report of Independent Accountants ......................................... 20
Consolidated Balance Sheets ............................................... 21
Consolidated Statements of Operations ..................................... 23
Consolidated Statements of Stockholders' Equity ........................... 24
Consolidated Statements of Cash Flows ..................................... 25
Notes to Consolidated Financial Statements ................................ 28
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of Golden Oil Company:
We have audited the consolidated financial statements and financial statement schedule of Golden Oil Company as listed in Item 14(a) of this Form 10-K. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Golden Oil Company as of December 31, 1997 and 1996, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1997 in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein.
As described in Note 1 to Consolidated Financial Statements, the Company changed its method of accounting for depletion of its oil and gas producing properties effective January 1, 1996.
COOPERS & LYBRAND L.L.P.
Houston, Texas March 31, 1998
GOLDEN OIL COMPANY
Consolidated Balance Sheets
DECEMBER 31, ---------------------------- 1997 1996 ----------- ----------- ASSETS Current assets: Cash and cash equivalents ................. 178,481 165,209 Short-term investments .................... -- 25,000 Accounts receivable: Oil and gas sales ....................... 181,746 290,210 Joint interest operations ............... 190,677 94,111 (including allowance for doubtful accounts of $113,718 in 1997 and $91,718 in 1996) Affiliates and other .................... 30,089 55,903
Prepaid expenses and other ................ 39,409 35,997 ----------- ----------- Total current assets .................... 620,402 666,430 ----------- ----------- Property and equipment, at cost: Oil and gas properties (using the successful efforts method of accounting) Producing properties ...................... 5,867,128 5,781,349
Undeveloped leasehold costs ............... 105,000 105,000 ----------- ----------- Total oil and gas properties ............ 5,972,128 5,886,349
Pipeline, field and other well equipment ............................... 225,274 242,902
Other property and equipment .............. 413,981 468,911 ----------- ----------- 6,611,383 6,598,162 Less accumulated depreciation, depletion and amortization ................ (3,757,030) (3,566,746) ----------- ----------- Net property and equipment .............. 2,854,353 3,031,416 ----------- -----------
Investment, real estate ...................... 192,229 196,234
Other assets ................................. 1,481 1,481 ----------- ----------- $ 3,668,465 $ 3,895,561 =========== ===========
See Notes to Consolidated Financial Statements.
GOLDEN OIL COMPANY
Consolidated Balance Sheets (Continued)
See Notes to Consolidated Financial Statements.
GOLDEN OIL COMPANY Consolidated Statements of Operations
See Notes to Consolidated Financial Statements.
GOLDEN OIL COMPANY
Consolidated Statements of Stockholders' Equity
See Notes to Consolidated Financial Statements.
GOLDEN OIL COMPANY
Consolidated Statements of Cash Flows
See Notes to Consolidated Financial Statements.
GOLDEN OIL COMPANY
Consolidated Statements of Cash Flows (Continued)
See Notes to Consolidated Financial Statements.
GOLDEN OIL COMPANY
Consolidated Statements of Cash Flows (Continued)
Supplemental Disclosure of Cash Flow Information:
During 1995 the Company paid Director fees of $20,000 by issuing shares of the Company's Common Stock in lieu of cash payment.
Interest charges of $20,296, $26,187 and $37,762 were paid in cash during 1997, 1996 and 1995, respectively. The Company has a net operating loss carryforward and was not required to make cash payments for federal income taxes during 1997, 1996 or 1995.
GOLDEN OIL COMPANY
Notes to Consolidated Financial Statements
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements of Golden Oil Company (the "Company") include its wholly owned subsidiaries Regal Petroleum, Ltd. ("Regal"); Spur Petroleum, Inc. ("Spur"); Golden Oil Holding Corporation ("Holding"); and Golden Resources, Inc. ("GRI"). The Company accounts for its commercial real estate investment under the equity method of accounting. All significant intercompany accounts and transactions have been eliminated in consolidation.
OIL AND GAS PROPERTIES. The Company follows the successful efforts method of accounting for its oil and gas properties. Under the successful efforts method, costs associated with the acquisition, drilling and equipping of successful exploratory wells and all developmental costs, including developmental dry holes, are capitalized and amortized using the unit-of-production method. Geological and geophysical costs, delay rentals and drilling costs of unsuccessful exploratory wells are charged to expense as incurred. In the event of a substantial downturn in prices obtainable for either oil or gas, whether temporary or permanent, the Company would be required to provide an impairment on the carrying value of its oil and gas properties.
Proceeds from the sale of an interest in an oil and gas property are credited to the asset account until all capitalized costs are recovered relative to that property.
PROPERTY AND EQUIPMENT. Property and equipment are depreciated over their estimated useful lives which range from three to ten years using the straight line method. Expenditures for maintenance and repairs which do not improve or extend the useful lives are charged to operations as incurred, while expenditures for major renewals and betterments are capitalized. Dispositions of assets are reflected at their historical cost less accumulated depreciation, with the resulting net gain or loss reflected in operations currently.
INCOME TAXES. The Company and its wholly owned subsidiaries join in filing consolidated federal income tax returns. Investment tax credits are accounted for by the flow-through method.
The Company recognizes deferred income tax assets and liabilities based on the expected future tax consequences of temporary differences between the income tax and financial reporting carrying amounts of assets and liabilities.
CASH EQUIVALENTS. For purposes of financial statement presentation, highly liquid instruments purchased with an original maturity of three months or less are shown as cash equivalents.
FAIR VALUE OF FINANCIAL INSTRUMENTS. The Company's Notes to Consolidated Financial Statements include information on fair value of its financial instruments when such value is different from the book value. The carrying value of cash and cash equivalents, receivables and accounts payable approximate fair value due to the short-term maturities of these instruments. The carrying value of the Company's credit agreements approximate fair value as the interest rates on such instruments are variable, based on current market.
Notes to Consolidated Financial Statements (Continued)
SHORT-TERM INVESTMENTS. At December 31, 1997, the Company had no short-term investments. The Company's short-term investments at December 31, 1996 consisted of 6 month certificates of deposit in federally insured banks for which cost approximated fair market value.
PER SHARE DATA. Effective December 31, 1997, the Company retroactively adopted the provisions of SFAS No. 128 for all periods presented. Basic earnings per common share ("EPS") is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if securities were exercised or converted to common stock. Potential common shares have not been added to compute diluted EPS as this inclusion would be antidilutive.
ACCOUNTING FOR STOCK-BASED COMPENSATION In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based Compensation" which encourages, but does not require, employers to adopt a fair value method of accounting for employee stock-based compensation, and requires increased disclosures if expense recognition is not adopted. The Company adopted SFAS 123 in 1996 and did not elect expense recognition for stock options and therefore implementation of SFAS No. 123 did not have an effect on the Company's operating results or financial condition.
USE OF ESTIMATES. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. See Supplemental Oil and Gas Information (Unaudited) and Note 4.
RECLASSIFICATIONS. Certain amounts from prior periods have been reclassified to conform to the presentation format for the Company's 1997 Consolidated Financial Statements with no effect on reported results of operations or cash flows.
ACCOUNTING CHANGE. Effective January 1, 1996 the Company changed its depletion method on producing oil and gas properties from the property-by-property basis to the field basis of applying the unit-of-production method. The field basis provides for the aggregation of wells that have a common geological reservoir or field. The Company believes that the field basis provides a better matching of expenses with revenues over the productive life of the properties and, therefore, that the new method is preferable to the property-by-property basis. The cumulative effect of this change in accounting method of $39,770 ($.03 per share) is reported in the accompanying consolidated statements of operations. This method of computing depletion expense would have had an immaterial impact on results of operations for the year ended December 31, 1995 had it been applied during that year.
Notes to Consolidated Financial Statements (Continued)
(2) OIL AND GAS PRODUCING ACTIVITIES
Shown below are the historical net capitalized costs and related accumulated depreciation, depletion and amortization for the Company's oil and gas properties at the dates indicated. The Company's oil and gas operations are conducted entirely in the United States.
AT DECEMBER 31, ----------------------------------------- 1997 1996 1995 ----------- ----------- ----------- Oil and gas properties: Producing ...................... $ 5,867,128 $ 5,781,349 $ 5,847,201
Non-producing .................. 105,000 105,000 105,000 ----------- ----------- ----------- 5,972,128 5,886,349 5,952,201 Less accumulated depreciation, depletion and amortization ..... (3,258,377) (3,035,795) (2,957,112) ----------- ----------- -----------
Net oil and gas properties ..... $ 2,713,751 $ 2,850,554 $ 2,995,089 =========== =========== ===========
Costs incurred in the Company's oil and gas operations and related accumulated depletion, depreciation and amortization per equivalent unit of production are shown below. For purposes of determining the equivalent unit of production, six Mcf of gas production is assumed to be equivalent to production of one barrel of oil. AT DECEMBER 31, ---------------------------------- 1997 1996 1995 -------- -------- -------- Property acquisition costs: Producing ............................ $ 57,009 $ 88,355 $ --
Non-producing ........................ -- -- -- -------- -------- -------- 57,009 88,355 -- ======== ======== ======== Exploration costs ....................... -- -- -- ======== ======== ======== Development costs ....................... 79,789 98,732 59,344 ======== ======== ======== Depletion ............................... 273,601 291,852 470,369 ======== ======== ======== Depletion per equivalent unit of production ........ $ 2.99 $ 2.89 $ 4.83 ======== ======== ========
Notes to Consolidated Financial Statements (Continued)
The Company's current oil and gas activities consist primarily of the operation and development of oil and gas properties in Oklahoma and New Mexico. At December 31, 1997 and 1996 the Company's accounts receivable, which generally are not collateralized, were primarily from entities and individuals involved in the oil and gas industry. The Company sells its oil and gas production on currently available markets pursuant to contracts with various purchasers. Generally, the purchasers of the Company's production volumes are established oil and gas and industrial companies. The Company does not anticipate nonperformance by the counterparties under such contracts. Beginning in December 1997, the Company had approximately 40% of its estimated monthly oil production under fixed price arrangements with one purchaser at an average price of $19.75 per barrel through March 1, 1998. As of March 31, 1998, the Company held a fixed price gas contract for approximately 80% of its monthly gas production at a price of $1.99 per Mcf through August 31, 1998. During 1997 sales to three purchasers accounted for approximately 48%, 30% and 18%, respectively, of the Company's total revenues. For each of the two previous years, sales to three purchasers accounted for approximately 46%, 34%, and 17% for the year ended December 31, 1996 and 55%, 28%, and 14% for the year ended December 31, 1995 of the Company's total revenues. No other customer accounted for more than ten percent of the Company's total revenues during those periods.
(3) AGREEMENTS TO PURCHASE OIL AND GAS PROPERTIES
In 1993 the Company entered into an agreement to purchase proved producing reserves in oil and gas properties in New Mexico's San Juan Basin under which it paid a nonrefundable deposit of $42,000. Due to subsequent declines in oil and gas prices, environmental and operational factors related to these prospective acquisitions, the Company elected not to close on the transaction. Accordingly, in 1995, the Company charged approximately $24,000 of acquisition-related costs and the $42,000 deposit to operations.
(4) ENVIRONMENTAL MATTERS
In recent years the Bureau of Land Management ("BLM") of the U.S. Department of the Interior has implemented extensive national regulations for the handling and maintenance of produced water from well sites on all federal lands. The stated objective of the regulations is to provide guidance for closure of unlined surface impoundments in a manner that assures protection of fresh waters, public health and the environment. The regulations require oil and gas companies to eliminate the use of unlined surface impoundments in the operation of wells and to remediate and replace them with lined and enclosed surface pits. Such federal government regulations provide for implementation on a region-by-region basis.
In January 1997, the regions so designated by the federal government were expanded to include 81 wells in the Company's field of operations in New Mexico. Pursuant to the Company's operating permit from the Jicarilla Apache Indian Nation, the Company's operating subsidiary was required to develop a plan for remediation and improvement for every well site. In May 1997 the BLM and the Jicarilla Environmental Protection Office ("EPO") approved the initial phase of the remediation and improvement plan ("Plan"). The initial phase of the Plan provided for the remediation and enclosure of 14 surface pits located at the well sites by June 30, 1997 in accordance with applicable Ordinance 95-0-308-03. Surface pits on such well sites and on an additional 14 well sites have been
Notes to Consolidated Financial Statements (Continued)
enclosed and soil remediation is complete in accordance with BLM and EPO regulations. Work is ongoing for an additional 25 well sites. Total costs to date of the project including the Company's and all third parties interest vary by well site but have ranged between $2,000 to $10,000 per well site, or approximately $110,000 of a total projected cost of $350,000.
Remediation on all well sites operated by the Company in New Mexico is currently required to be completed by December 1998. Numerous oil and gas producers in the region, including the Company, are seeking extensions of such date but have not yet received them. The total cost of such work is subject to a number of variable expense factors including, among others, the cost and manner of disposal of removed soil and the amounts of soil that may be required to be removed. The Plan allows relatively broad soil disposal options; however, other more costly soil disposal alternatives may be deemed necessary or may be mandated by the regulatory agencies governing the remediation and impoundment programs.
Based upon the preliminary information available at this time, the Company has estimated the total cost to complete the entire remediation and pit enclosure program in the this region to be in the range of approximately $350,000 to $500,000. Total costs could vary significantly from such estimate due to the numerous variable factors discussed above. In recognition of the above variables the Company has charged a provision reflecting its preliminary estimate of its share of such costs, net of operating charges, of appproximately $106,000 to earnings as of December 31, 1997. The adequacy of such provision is periodically reviewed and adjusted by the Company as actual costs are incurred.
(5) INDEBTEDNESS
In April 1996, the Company entered into a credit agreement with a commercial bank in Albuquerque, New Mexico ("Bank") under which the Company obtained an extension of existing borrowings and increased the credit available to it from $150,000 to $400,000. The maturity schedule of the Company's debt was extended to four years, subject to certain conditions. As a condition of extending the current maturity and obtaining additional credit, the Bank required the entire credit facility to be independently, personally guaranteed by a person acceptable to the Bank and to be collateralized by the Company's New Mexico oil and gas properties. An officer of the Company provided the independent, personal guarantee. The credit agreement bears interest at 2% over the bank's prime lending rate, and adjusted periodically. Such interest rate was 11.5% at December 31, 1997.
Proceeds from the credit facility were utilized to refinance short-term debt then outstanding; to acquire additional interests in Company-operated oil and gas properties; and for working capital. At the time the new credit agreement was obtained, the Company had a working capital deficit of approximately $1,000,000. In order to obtain the new financing the Company was required by the lending Bank to provide a personal guarantee from a principal officer of the Company for repayment in full to the Bank of all principal, interest and related costs. Due to its financial position, the Company was not able to pay a cash fee for the personal guarantee required by the Bank as a condition of extending credit to the Company. In lieu of cash payment, the Company proposed to
Notes to Consolidated Financial Statements (Continued)
pay the guarantor fee by delivering to the guarantor warrants to purchase unregistered shares of its common stock. On March 29, 1996 after obtaining the written opinion of fairness from independent investment banking advisors, the Board of Directors approved the credit agreement and the payment and delivery to the guarantor of warrants to purchase 250,000 unregistered shares of common stock of the Company through March 2006 for an exercise price of $.20 per share. For the calendar year 1997 the guarantor exercised rights to purchase 100,000 shares of common stock granted under the warrants.
Under the Company's present credit agreement, the Company is required to make monthly payments of principal and interest of approximately $10,400 through April 2000. As of March 31, 1998, the Company had $59,000 remaining available for purchases of oil and gas properties or bank-approved uses under the terms of the agreement.
The Company also maintained a credit facility in the original amount of $100,000 with a commercial bank in Tulsa, Oklahoma and had borrowed $70,000 under such line of credit facility. The line of credit bears interest at 2% over the bank's prime lending rate, adjusted periodically. In March 1996, the Company began reducing the principal amount borrowed under this credit facility by $5,000 each month. Such line of credit was retired in April 1997.
(6) CAPITAL STOCK
STOCK OPTIONS. The Company has a stock option plan for key employees (the "Employee Plan"). The Employee Plan is administered by the Stock Option Committee which is appointed by the Board of Directors. During 1989 the Stock Option Committee granted options covering 147,000 shares to the Company's Chairman at an initial exercise price of $1.79 per share and exercisable in whole or in part through December 21, 1999. During 1990 the Stock Option Committee granted 49,000 options to other eligible employees at the same initial exercise price and exercisable in whole or in part through April 16, 2000. No options were granted or exercised during the years 1997, 1996 or 1995.
The Company also has a stock option plan covering 14,000 shares for the Company's non-employee directors (the "Directors' Plan"). Under the Directors' Plan, each non-employee director will be granted 1,400 shares per year, subject to prior approval by the Board of Directors, at the market price on the date of grant. Options covering such shares may be exercised any time from the date of grant and all optioned shares must be exercised within five years from the date of grant. No such options were granted or exercised during the years ended December 31, 1997, 1996 or 1995.
STOCK WARRANTS. In connection with the credit arrangement executed in April 1996 the commercial bank required the Company to provide a third party guarantor satisfactory to the Bank as a condition of extending credit (See Note 5). As compensation, the Company issued stock warrants to the guarantor, an officer of the Company, to purchase 250,000 unregistered shares of common stock at $0.20 per share in lieu of cash payment to provide a personal guarantee for the entire debt, including associated interest and other costs. The grant date of such warrants was March 29, 1996 and they were fully vested at the date of grant. The fair value of the warrants, estimated to be $25,000, was reflected as additional paid-in capital and other income (expense) during 1996. As of December 31, 1997, the guarantor had
Notes to Consolidated Financial Statements (Continued)
exercised rights to purchase 100,000 shares of common stock available under the warrants for which the Company received $20,000.
CLASS B COMMON STOCK. During 1986, the stockholders of the Company approved the issuance of a new class of common stock designated Class B Common Stock ("Class B Common"). The holders of Class B Common, voting as a separate class, have the right to elect a simple majority of the Board of Directors and vote as a separate class on major corporate transactions. Holders of the Class B Common also vote share-for-share with holders of the Common Stock. Class B Common shares are not publicly traded, and are only transferable to persons within defined categories of "permitted transferees", but may be converted into Common Stock at any time on a share-for-share basis.
PREFERRED STOCK. The Company also has an authorized class of Preferred Stock, par value $.01, of which there are currently 10,000,000 shares authorized, with none currently issued or outstanding.
(7) EMPLOYEE BENEFIT PLAN
Effective October 12, 1997 the Company implemented a Simple Individual Retirement Account ("IRA") Retirement Plan to all employees of the Company. Employees may contribute up to 6% (limited to $6,000) of their gross salary and the Company matches up to 3% (limited to $3,000) of an employee's salary, subject to limitations imposed by the Internal Revenue Service. The Company's contribution to the Simple IRA Retirement Plan was $6,264 for the year ended December 31, 1997.
(8) INCOME TAXES
At December 31, 1997 the Company had aggregate net operating loss carryforwards of approximately $10,000,000 which expire at various dates through the year 2012, and net investment tax credit carryforwards of approximately $170,000 which expire at various dates through the year 2000. In connection with ownership changes resulting from certain transactions, the utilization of the net operating loss and net investment tax credit carryforwards are limited under Sections 382 and 383 of the Internal Revenue Code to a maximum of approximately $7,625,000. Certain other restrictions may also exist as to the utilization of such carryforwards. At December 31, 1997 the Company also has available federal statutory depletion and capital loss carryforwards.
Notes to Consolidated Financial Statements (Continued)
The components of the Company's deferred tax assets and liabilities at December 31, 1997 and 1996 are as follows:
DEFERRED TAX ASSETS (LIABILITIES) ------------------------------ 1997 1996 ----------- ----------- Accounts receivable ...................... $ 38,664 $ 33,332 Oil and gas properties (net) ............. (390,678) (377,493) Investment in real estate ................ 45,510 44,148 Net operating losses ..................... 3,407,707 3,680,175 Capital losses ........................... 335,504 335,504 Investment tax credit .................... 57,670 77,788
Percentage depletion ..................... 1,089,064 1,096,443 ----------- ----------- Deferred tax asset ....................... 4,583,441 4,889,897
Valuation allowance ...................... (4,583,441) (4,889,897) ----------- ----------- Deferred tax assets, net ................. -- -- ----------- -----------
The Company's valuation allowance increased (decreased) by approximately ($306,000), ($39,000), and $96,000 for 1997, 1996 and 1995, respectively. The decrease in the valuation allowance in 1997 is attributable to the expiration of prior year tax loss carryforwards partially offset by current year net operating loss carryforwards.
(9) CERTAIN TRANSACTIONS
The Company holds as a long-term investment approximately a 23% interest in a real estate limited partnership ("Partnership") which owns a 54,000 square foot commercial office building. In connection with this investment, in October 1996, the Company provided its pro rata share of $25,000 as collateral under a $100,000 standby letter of credit. Other investors, including an officer of the Company with an ownership interest in the Partnership, provided the remaining $75,000 collateral guarantee under such standby letter of credit. This letter of credit was required by the Partnership's first mortgage lender as a condition to extension and modification of the mortgage term to provide time to execute a new mortgage agreement with a new institutional lender. A new mortgage agreement was completed in May 1997 and the Company's collateral was released in full.
The Company leases approximately 3,950 square feet of office space in the building of the total of approximately 54,000 square feet under a six year lease through December 15, 2002.
In connection with establishment of an electronic data processing and management reporting system, the Company is jointly and severally liable for a computer hardware and software lease together with a related party that is also jointly and severally liable for the lease obligation. The lease has a term of five years through January, 1999 and provides for monthly payments of $3,050, of which one-half will be paid by the Company. The Company anticipates that it will share use of the hardware and additional software throughout such term.
Notes to Consolidated Financial Statements (Continued)
(10) COMMITMENTS AND CONTINGENCIES
At December 31, 1997 the aggregate future minimum lease payments under the Company's noncancellable operating leases are:
1998 ............................... $ 68,235 1999 ............................... 51,735 2000 ............................... 50,235 2001 ............................... 50,235 2002 ............................... 48,142 Thereafter ......................... -- -------- Total .......................... $268,582 ========
Rent expense for the years ended December 31, 1997, 1996 and 1995 was $54,500, $55,500 and $57,900.
(11) UNAUDITED QUARTERLY INFORMATION
Amounts previously reported in the Company's 10-Q were restated to accurately account for the Company's purchase of properties in New Mexico. Oil and gas production revenues, production costs, and producing properties were previously reported as $456,344, $551,956, and $5,855,159, respectively, as of June 30, 1997 and for the three and six month periods then ended. These amounts have been restated to $415,799, $525,822, and $5,840,748, respectively. The amounts reported in the Company's 10-Q filed as of September 30, 1997 and for the nine months then ended included the restated amounts.
End of Notes to Consolidated Financial Statements
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
The following quantity and discounted estimates of future net cash flows are based on prices as of the respective year ends. No price escalation was assumed. Operating costs, production taxes, royalties and estimated future capital expenditures to complete development of the proved reserves were deducted in determining the quantity and discounted estimates of future net cash flows. Such costs were estimated based on current costs and were not adjusted to anticipate increases due to inflation or other factors. No deductions were made for general overhead, depreciation or other indirect costs. The following table reflects estimated quantities of proved oil and gas reserves. These reserves have been reduced for royalty interests owned by others. These reserves are all located in the United States and have been estimated by the Company's petroleum engineers. The Company considers such estimates to be reasonable; however, due to inherent uncertainties, estimates of underground reserves are imprecise and subject to change over time as additional information becomes available.
The estimated proved and proved developed oil and gas reserves shown below are based on economic assumptions and future projections. The Company does not believe that such amounts necessarily represent the reserve volumes or amounts which would be actually recoverable at the respective dates shown.
ANALYSIS OF CHANGES IN PROVED RESERVES
(1) Amounts computed using oil prices ranging from $16.50 to $19.25 per barrel and gas prices ranging from $1.15 to $2.00 per Mcf. Oil prices at December 31, 1997 were higher than currently prevailing prices and, in management's opinion were not indicative of prices likely to prevail throughout 1998. As of March 15, 1998, the Company is obtaining a price of approximately $13.00 to $14.50 per barrel of oil on sales of oil not subject to fixed price contracts. Use of such March 15, 1998 prices in the above projections would have decreased total reserves recoverable as of December 31, 1997. (2) In accordance with the reporting regulations of the SEC, total estimated reserves at December 31, 1996 reflect oil and gas prices prevailing at year end ranging from $23.30 to $24.60 per barrel of oil and $1.89 to $2.75 per Mcf of gas. Oil prices at December 31, 1996 were higher than currently prevailing prices and, in management's opinion, were not indicative of prices likely to prevail throughout 1997. As of March 15, 1997, the Company is obtaining a price of approximately $21.00 per barrel of oil on sales of oil not subject to fixed price contracts. Use of such March 15, 1997 prices in the above projections would have decreased total reserves recoverable as of December 31, 1996. (3) Amounts computed using oil prices ranging from $17.00 to $17.25 per barrel and gas prices ranging from $1.00 to $1.30 per Mcf. (4) In 1995, the Company made certain revisions to estimated future lease operating expenses.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN
The standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves is as follows:
DECEMBER 31, ------------------------------------------------- 1997 1996 1995 ------------ ------------ -----------
Future cash inflows ...... $ 42,622,350 $ 43,560,590 $ 23,201,780 Future production and development costs ..... (12,964,878) (14,541,524) (8,143,653)
Future income tax expenses (7,167,123) (6,265,135) (3,161,915) ------------ ------------ ----------- Future net cash flows .... 22,490,349 22,753,931 11,896,212
10% annual discount for estimated timing of cash flows .......... (13,236,249) (8,517,599) (4,690,122) ------------ ------------ ----------- Standardized measure of discounted future net cash flows ........... 9,254,100(1) $ 14,236,332(2)(4) $ 7,206,090(3) ============ ============ ===========
Future net cash flows were computed using year-end prices and costs, and year end statutory tax rates that relate to existing proved oil and gas reserves.
(1) Amounts computed using oil prices ranging from $16.50 to $19.25 per barrel and gas prices ranging from $1.15 to $2.00 per Mcf. Oil prices at December 31, 1997 were higher than currently prevailing prices and, in management's opinion were not indicative of prices likely to prevail throughout 1998. As of March 15, 1998, the Company is obtaining a price of approximately $13.00 to $14.50 per barrel of oil on sales of oil not subject to fixed price contracts. Use of such March 15, 1998 prices in the above projections would have decreased total reserves recoverable as of December 31, 1997. (2) In accordance with the reporting regulations of the SEC, total estimated reserves at December 31, 1996 reflect oil and gas prices prevailing at year end ranging from $23.30 to $24.60 per barrel of oil and $1.89 to $2.75 per Mcf of gas. Oil prices at December 31, 1996 were higher than currently prevailing prices and, in management's opinion, were not indicative of prices likely to prevail throughout 1997. As of March 15, 1997, the Company is obtaining a price of approximately $21.00 per barrel of oil on sales of oil not subject to fixed price contracts. Use of such March 15, 1997 price in the above projections would have decreased estimated future net cash flows as of December 31, 1996. (3) Amounts computed using oil prices ranging from $17.00 to $17.25 per barrel and gas prices ranging from $1.00 to $1.30 per Mcf. (4) The realization of the discounted cash flows associated with the Company's proved undeveloped reserves in the South Dog Creek field are dependent on, among other things, the availability of financing to complete development and the success of production response from the waterflood injection program.
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
YEAR ENDED DECEMBER 31, ---------------------------------------------- 1997 1996 1995 ------------ ------------ ----------- Standardized measure of discounted future net cash flows, beginning of year .................. $ 14,236,332 $ 7,206,090 $ 8,099,847 Sale of oil and gas produced, net of production costs ........ (369,199) (549,964) (413,988)
Net changes in prices and production costs .......... (3,816,308) 3,338,005 (443,613)
Purchases of minerals in place ..................... 250,378 1,082,136 --
Sales of minerals in place ... -- -- (2,339)
Revisions of previous quantity estimates ................. (3,007,168)(4) 5,752,713 (1,051,461)
Net change in income taxes ... 536,432 (3,313,257) 207,659
Accretion of discount ........ 1,423,633 720,609 809,985 ------------ ------------ ----------- Standardized measure of discounted future net cash flows, end of year $ 9,254,100(1) $ 14,236,332(2) $ 7,206,090(3) ============ ============ ===========
Future net cash flows were computed using year end prices and costs, and year end statutory tax rates that relate to existing proved oil and gas reserves.
(1) Amounts computed using oil prices ranging from $16.50 to $19.25 per barrel and gas prices ranging from $1.15 to $2.00 per Mcf. Oil prices at December 31, 1997 were higher than currently prevailing prices and, in management's opinion were not indicative of prices likely to prevail throughout 1998. As of March 15, 1998, the Company is obtaining a price of approximately $13.00 to $14.50 per barrel of oil on sales of oil not subject to fixed price contracts. Use of such March 15, 1998 prices in the above projections would have decreased total reserves recoverable as of December 31, 1997.
(2) In accordance with the reporting regulations of the SEC, total estimated reserves at December 31, 1996 reflect oil and gas prices prevailing at year end ranging from $23.30 to $24.60 per barrel of oil and $1.89 to $2.75 per Mcf of gas. Oil prices at December 31, 1996 were higher than currently prevailing prices and, in management's opinion, were not indicative prices likely to prevail in 1997. As of March 15, 1997, the Company is obtaining a price of approximately $21.00 per barrel of oil on sales of oil not subject to fixed price contracts. Use of such March 15, 1997 price in the above projections would have decreased estimated future net cash flows as of December 31, 1996.
(3) Amounts computed using oil prices ranging from $17.00 to $17.25 per barrel and gas prices ranging from $1.00 to $1.30 per Mcf.
(4) Estimated proved reserve volumes increased 534,066 barrels from 1,613,995 barrels in 1996 to 2,148,061 barrels in 1997. However, the discounted future net cash flows pertaining to revisions of previous quantity estimates decreased as a result of revisions in the timing of production. Such revisions in the timing of production are related to proved undeveloped reserves of the waterflood project.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The definitive Proxy Statement in connection with the 1997 Annual Meeting of Stockholders to be filed by the Company pursuant to Regulation 14A of the Securities Exchange Act of 1934 is incorporated herein by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
The definitive Proxy Statement in connection with the 1997 Annual Meeting of Stockholders to be filed by the Company pursuant to Regulation 14A of the Securities Exchange Act of 1934 is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The definitive Proxy Statement in connection with the 1997 Annual Meeting of Stockholders to be filed by the Company pursuant to Regulation 14A of the Securities Exchange Act of 1934 is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The definitive Proxy Statement in connection with the 1997 Annual Meeting of Stockholders to be filed by the Company pursuant to Regulation 14A of the Securities Exchange Act of 1934 is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
PAGE ---- (a) 1. The following consolidated financial statements are included in Part II, Item 8:
Report of Independent Accountants......................... 20
CONSOLIDATED FINANCIAL STATEMENTS: Consolidated Balance Sheets as of December 31, 1997 and 1996.................................. 21 Consolidated Statements of Operations for the years ended December 31, 1997, 1996 and 1995................ 23 Consolidated Statements of Stockholders' Equity for the years ended December 31, 1997, 1996 and 1995........................................................ 24 Consolidated Statements of Cash Flows for the years ended December 31, 1997, 1996 and 1995................ 25
Notes to Consolidated Financial Statements.................. 28
2. FINANCIAL STATEMENT SCHEDULES:
Schedule II Valuation and Qualifying Accounts............... 46
All other schedules are omitted because they are not applicable or the information is included in the financial statements and notes included herewith.
(b) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the Company's last fiscal quarter of 1997.
(c) EXHIBITS
3. The following exhibits are filed as part of this report. Where such filing is made by incorporation by reference to a previously filed statement or report, such statement or report is identified in parenthesis. ARTICLES OF INCORPORATION AND BYLAWS
3.1 Articles of Incorporation (incorporated by reference to Exhibit 3 of Form 10-K for the year ended December 31, 1985).
3.2 Bylaws (incorporated by reference to Exhibit 3 of Form 10-K for the year ended December 31, 1985).
10. MATERIAL CONTRACTS
10.1 Pinnacle Petroleum, Inc. Amended and Restated Employees' Stock Option Plan (incorporated by reference from Exhibit I to Pinnacle Petroleum, Inc. Proxy Statement dated November 29, 1989).
10.2 Directors' Stock Option Plan (incorporated by reference from Exhibit II to Pinnacle Petroleum, Inc. Proxy Statement dated November 29, 1989).
10.3 Agreement and Plan for Merger by and between Golden Oil Company, Golden Oil Holding Corporation and Cobb Resources Corporation dated November 28, 1990 (incorporated by reference from Exhibit 1 to Form 8-K dated November 28, 1990).
10.4 Stock Option Agreement between Golden Oil Company and Cobb Resources Corporation dated November 28, 1990 (incorporated by reference from Exhibit 2 to Form 8-K dated November 28, 1990).
10.5 Directors Agreement among George O. Lotspeich, B. W. Miller, Malcolm G. Colberg, William J. Mayhew, Frank J. Yeager, Ralph T. McElvenny, Jr., Anthony B. Petrelli and Golden Oil Company dated November 28, 1990 (incorporated by reference from Exhibit 4 to Form 8-K dated November 28, 1990).
10.6 Asset Purchase Agreement, dated April 5, 1991, by and between Golden Oil Company, Cobb Resources Corporation and Chace Oil Company, Inc. (incorporated by reference from Exhibit 10.13 to Cobb Resources Corporation Form 10-K for the year ended June 30, 1991).
10.7 Shareholders Agreement, dated as of April 5, 1991, between Golden Oil Company, Cobb Resources Corporation, Horace F. McKay, Jr. George O. Lotspeich and Frank J. Yeager (incorporated by reference from Exhibit 10.15 to Cobb Resources Corporation Form 10-K for the year ended June 30, 1991).
10.8 Amendment No. 1 to Directors Agreement, dated as of April 5, 1991, between Golden Oil Company and Malcolm G. Colberg, George O. Lotspeich, William J. Mayhew, Ralph T. McElvenny, Jr., B. W. Miller, Anthony B. Petrelli and Frank J. Yeager (incorporated by reference from Exhibit 10.17 to Cobb Resources Corporation Form 10-K for the year ended June 30, 1991).
10.9 Amendment No. 1 to Asset Purchase Agreement, dated June 25, 1991, by and between Golden Oil Company, Cobb Resources Corporation and Chace Oil Company, Inc. (incorporated by reference from Exhibit 10.14 to Cobb Resources Corporation Form 10-K for the year ended June 30, 1991).
10.10 Amendment No. 2 to Asset Purchase Agreement, dated as of September 30, 1991, by and between Golden Oil Company, Cobb Resources Corporation and Chace Oil Company, Inc. (incorporated by reference from Exhibit 10.18 to Cobb Resources Corporation 10-K for the year ended June 30, 1991).
10.11 Stock Purchase Agreement, dated October 16, 1992, by and between Golden Oil Company, Cobb Resources Corporation, and Charles Cobb IV (incorporated by reference from Exhibit 10.11 to Form 10-K for the year ended December 31, 1992).
10.12 Warrant to Purchase Shares of Common Stock, dated March 29, 1996 by and between Golden Oil Company and Ralph T. McElvenny, Jr. (filed herewith).
10.13. Note Agreement dated April 12, 1996 by and between Golden Oil Company, Ralph T. McElvenny, Jr. and Western Bank of Albuquerque, New Mexico (filed herewith).
22.1 SUBSIDIARIES OF THE COMPANY (filed herewith).
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(1) Accounts written off, net of recoveries and allowance adjustment.
GOLDEN OIL COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
GOLDEN OIL COMPANY
Date: March 31, 1998 By: /s/ RALPH T. McELVENNY, JR. --------------------------- Ralph T. McElvenny, Jr., Director Chief Executive Officer
Date: March 31, 1998 By: /s/ JEFFREY V. HOUSTON ----------------------- Jeffrey V. Houston Principal Financial and Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated.
Date: March 31, 1998 By: /s/ DARRYL L. EMMERT --------------------- Darryl L. Emmert, Director
Date: March 31, 1998 By: /s/ RALPH T. McELVENNY, JR. --------------------------- Ralph T. McElvenny, Jr., Director Chief Executive Officer
Date: March 31, 1998 By: /s/ FRANK J. YEAGER ------------------- Frank J. Yeager, Director