ITEM 1.	BUSINESS
	General Development of Business
	GeoResources, Inc. (the "Registrant" or the "Company") is a natural resources company engaged principally in the following two business segments: 1) oil and gas exploration, development and production; and 2) mining of leonardite (oxidized lignite coal) and manufacturing of leonardite based products which are sold primarily as oil and gas drilling mud additives. The Registrant was incorporated under Colorado law in 1958 and was originally engaged in uranium mining. The Registrant built its first leonardite processing plant in 1964 in Williston, North Dakota, and began participating in oil and gas exploration and production in 1969. In 1982, the Registrant completed construction of a larger leonardite processing plant in Williston that is in use today. Financial information about the Registrant's two industry segments is presented in Note B to the Financial Statements in Item 8 of this report.
	Information contained in this Form 10-K contains forward- looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 which can be identified by the use of words such as "may," "will," "expect," "anticipate," "estimate" or "continue," or variations thereon or comparable terminology. In addition, all statements other than statements of historical facts that address activities, events or developments that the Company expects, believes or anticipates, will or may occur in the future, and other such matters, are forward-looking statements.
	The future results of the Company may vary materially from those anticipated by management and may be affected by various trends and factors which are beyond the control of the Company. These risks include the competitive environment in which the Company operates, changing oil and gas prices, the demand for oil, gas and leonardite, availability of drilling rigs, dependence upon key management personnel and other risks described herein.
	Oil and Gas Exploration, Development and Production
	The Registrant's oil and gas exploration and production efforts are concentrated on oil properties in the North Dakota and Montana portions of the Williston Basin. The Registrant typically generates prospects for its own exploitation, but when a prospect is deemed to have substantial risk or cost, the Registrant may attempt to raise all or a portion of the funds necessary for exploration or development through farmouts, joint ventures, or other similar types of cost-sharing arrangements. The amount of interest retained by the Registrant in a cost-sharing arrangement varies widely and depends upon many factors, including the exploratory costs and the risks involved.
	In addition to originating its own prospects, the Registrant occasionally participates in exploratory and development prospects originated by other individuals and companies. The Registrant also evaluates interests in various proved properties to acquire for further operation and/or development.
	The Registrant, where possible, supervises drilling and production activities on new prospects and properties acquired. It does not own or have any plans to acquire any rotary drilling equipment. Hence, the Registrant uses independent drilling contractors for the drilling of wells of which it is the operator. Thus, the Registrant's drilling activities can be subject to delays caused by shortages of drilling equipment or other factors beyond its control, including inclement weather.
	As of December 31, 1997, the Registrant had developed oil and gas leases covering approximately 12,163 net acres in Montana and North Dakota, and during 1997 sold an average 584 net equivalent barrels of oil per day from 94 gross (66.80 net) producing wells located primarily in North Dakota.
	The Registrant sells its crude oil to purchasers with facilities located near the Registrant's wells. The Registrant's gas reserves are also contracted to purchasers in the area near the Registrant's wells.
	Mining and Manufacturing Leonardite Products
	The Registrant operates a leonardite mine and processing plant in Williston, North Dakota. Leonardite is mined from leased reserves and processed to make a basic product that can be sold as is, or blended with other substances to make several different dry, free flowing powders primarily for the oil well drilling mud industry. Leonardite products act as a dispersant or thinner, and provide filtration control when used as an additive in drilling muds. Leonardite is also sold by the Registrant for use in metal working foundries and in agricultural applications.
	In 1997, the Company's leonardite products were sold primarily to drilling mud companies located in coastal areas of the Gulf of Mexico. Demand for the plant's output is governed mainly by the level of oil and gas drilling activities, particularly in the gulf coast area, both onshore and offshore. Drilling activity declined substantially in the mid 1980's and has remained at relatively low levels for the past several years. The Registrant has no significant supply contracts with individual customers.
Status of Products, Services or Industry Segments in Development
	The Company owns 82% of the stock of Belmont Natural Resource Company, Inc. (BNRC), a Washington corporation formed for the purpose of exploiting natural gas opportunities in the Pacific Northwest. BNRC owns oil and gas leases covering 6,713 gross acres (6,479 net) on a gas prospect located in the State of Washington. Activities in 1997 consisted of a small amount of geological field work in an effort to further define the prospect. The Company does not expect to devote any substantial resources to this project in 1998.
	In addition to its two principal business segments, the Registrant owns a nonproducing silver property in Arizona. (See Item 2.
ITEM 2.	PROPERTIES
	The Registrant's properties consist of four main categories: Office, leonardite plant and mine, oil and gas, and a nonproducing silver property. Certain of these properties are mortgaged to the Company's bank. See Note F to the Financial Statements for further information.
	Office
	The Registrant owns a 17,500 square foot office building which is located on a one-acre lot in Williston, North Dakota. The Company utilizes approximately 5,000 square feet of the building and rents the remainder to unaffiliated businesses.
	Leonardite Plant and Mine
	The site of the Registrant's leonardite plant covers approximately nine acres located one mile east of Williston in Williams County, North Dakota. This site and an additional 20 acres of undeveloped property are owned by the Company. The plant has approximately 11,500 square feet of floor area consisting of warehousing and processing space. Therein is equipment able to process and ship approximately 3,000 tons of leonardite products per month. Finished product leonardite sales for the past three years are shown below.
Finished Average Products Sales Price Year (Tons) Per Ton
1997 8,094 $ 94.44 1996 8,909 $ 94.49 1995 7,528 $ 93.51
	The Registrant's leonardite mining properties consist of a developed lease from private parties and one undeveloped lease from the United States Department of the Interior, Bureau of Land Management. The leased land is located about one mile from the plant site in Williams County, North Dakota. The private-party (fee) lease totals approximately 160 acres. The federal lease from the Bureau of Land Management (BLM) covers 160 undeveloped acres. In 1994, the Company formed a 240-acre logical mining unit (LMU), in accordance with BLM regulations, consisting of 80 acres of the fee lease and 160 acres of the BLM lease. This LMU allows current operations on the fee lease to satisfy diligent development and other requirements for 160 acres of the BLM lease. Management believes the leonardite contained in the 240-acre LMU is sufficient to supply its plant's raw material requirements for many years and that before these reserves were exhausted, the Company would be able to acquire other fee or federal coal leases in the same area.
	Oil and Gas Properties
	The Registrant owns developed oil and gas leases totaling 16,680 gross (12,163 net) acres as of March 15, 1998, plus associated production equipment and also owns a number of undeveloped oil and gas leases. The acreage and other additional information concerning the Registrant's oil and gas operations are presented in the following tables.
	Estimated Net Quantities of Oil and Gas and Standardized Measure of Future Net Cash Flows All the Registrant's oil and gas reserves are located in the United States. Information concerning the estimated net quantities of all the Registrant's proved reserves and the standardized measure of future net cash flows from such reserves is presented as unaudited supplementary information following the Financial Statements in Item 8. The estimates are based upon the report of Broschat Engineering and Management Services, an independent petroleum- engineering firm in Williston, North Dakota. The Registrant has no long- term supply or similar agreements with foreign governments or authorities, and the Registrant does not own an interest in any reserves accounted for by the equity method.
	Net Oil and Gas Production, Average Price and Average Production Cost The net quantities of oil and gas produced and sold for each of the last three fiscal years, the average sales price per unit sold and the average production cost per unit are presented below.
Oil & Gas
Average Average Net Net Net Oil Gas Average Oil Gas Oil & Gas Sales Sales Prod. Prod. Prod. Prod. Price Price Cost Per Year (Bbls) (MCF) (BOE)* Per Bbl Per MCF BOE**
1997 211,266 10,408 213,001 $16.15 $ 1.30 $ 6.27 1996 166,810 13,167 169,005 $17.67 $ 1.29 $ 6.40 1995 151,467 13,061 153,644 $14.24 $ 0.98 $ 6.18 - ------------------------	 *Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (6 MCF) of natural gas equal to one barrel of oil equivalent (1 BOE). **Average production cost includes lifting costs, remedial workover expenses and production taxes.
	Gross and Net Productive Wells As of March 15, 1998, the Registrant's total gross and net productive wells were as follows:
Productive Wells*
Oil Gas Gross Wells Net Wells Gross Wells Net Wells 96 67.78 24 24.00 - ------------------------	 *There are no wells with multiple completions. A gross well is a well in which a working interest is owned. The number of net wells represents the sum of fractional working interests the Company owns in gross wells. Productive wells are producing wells plus shut-in wells the Company deems capable of production.
	Gross and Net Developed and Undeveloped Acres As of March 15, 1998, the Registrant had total gross and net developed and undeveloped oil and gas leasehold acres as set forth below. The developed acreage is stated on the basis of spacing units designated by state regulatory authorities.
Leasehold Acreage*
Developed Undeveloped Total Gross Net Gross Net Gross Net
Montana 9,000 7,627 17,377 17,312 26,377 24,939 North Dakota 7,680 4,536 30,842 11,029 38,522 15,565 Washington 0 0 6,713 6,479 6,713 6,479 ALL STATES 16,680 12,163 54,932 34,820 71,612 46,983 - ------------------------	 *Gross acres are those acres in which a working interest is owned. The number of net acres represents the sum of fractional working interests the Company owns in gross acres.
	Exploratory Wells and Development Wells For each of the last three fiscal years ended December 31, the number of net exploratory and development productive and dry wells drilled by the Company was as set forth below.
Net Exploratory Net Development Total Net Year Wells Drilled Wells Drilled Wells Drilled Productive Dry Productive Dry
1997 0.00 0.02 1.67 0.00 1.69 1996 0.00 0.08 0.67 0.00 0.75 1995 0.00 0.00 1.34 0.00 1.34
	Present Activities From January 1, 1998 to March 15, 1998, the Registrant had one gross (.67 net) horizontal well in the process of drilling. This well was completed and put on production prior to March 15, 1998, and it is therefore included in the previous table titled "Gross and Net Productive Wells".
	Supply Contracts or Agreements The Registrant is not obligated to provide a fixed or determinable quantity of oil and gas in the future under any existing contract or agreement, beyond the short term contracts customary in division orders and off lease marketing arrangements within the industry.
	Reserve Estimates Filed with Agencies No estimates of total proved net oil and gas reserves for the year ended December 31, 1997 have been filed with any federal authority or agency. Other than the estimates of reserves at December 31, 1996, filed with the Securities and Exchange Commission, the Registrant did not file reserve reports with any other federal agencies within the past 12 months.
	Silver Property
	The Registrant owns seven patented mining claims and 15 unpatented mining claims in Pinal County, Arizona. These claims, known as the Reymert Silver Property, have produced silver sporadically since the 1880's. The property's last ore production was in 1989 under a lease arrangement. In 1993, the Registrant entered into a License Agreement with another company to allow commercial rock production from the patented claims. The Registrant receives a royalty of $2 per ton for rock severed from the property. No commercial rock production occurred in 1997. No mining activities are presently being conducted on this property. Management has no plans to devote significant financial resources to this property in 1998; however, it continues to investigate ways to further exploit the property.
ITEM 3.
ITEM 3.	LEGAL PROCEEDINGS
	On May 12, 1989, the Company filed an action in Burleigh County District Court, North Dakota, against MDU Resources Group, Inc., a Delaware corporation, and Williston Basin Interstate Pipeline Company, a Delaware corporation. The Complaint related to, among other things, breaches of a take or pay natural gas contract and attempts by the defendants to coerce the Company into modifying the contract. The defendants answered the Complaint on June 1, 1989. Afterwards, no further materials were filed with the court, but the Company believed that the case remained pending. The Company contacted the attorney who filed the action to assess the status and request further prosecution of the case. After several months of inaction regarding the case, the Company contacted the court in September 1996 and was informed by the court that the case had been dismissed in 1991. On January 15, 1997, the Company refiled its action against MDU Resources Group, Inc. Management cannot predict the outcome of this action, although the Company intends to pursue its available remedies.
	Other than the foregoing legal proceeding, the Company is not a party, nor is any of its property subject to, any pending material legal proceedings. The Company knows of no legal proceedings contemplated or threatened against it.
ITEM 4.
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
	During the fourth quarter of 1997, no matter was submitted to a vote of security holders of the Company through the solicitation of proxies or otherwise.
PART II
ITEM 5.
ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
	The Registrant's Common Stock trades on the Nasdaq SmallCap Stock Market under the Symbol "GEOI." The following table sets forth for the period indicated the lowest and highest trade prices for the Registrant's Common Stock as reported by the Nasdaq SmallCap Stock Market. These trade prices may represent prices between dealers and do not include retail markups, markdowns or commissions.
Trade Price Calendar Lowest Highest 1996 1st Quarter $1.25 $1.63 2nd Quarter $1.44 $2.06 3rd Quarter $1.38 $1.88 4th Quarter $1.50 $4.38 1997 1st Quarter $3.04 $3.21 2nd Quarter $2.83 $2.98 3rd Quarter $3.39 $3.61 4th Quarter $2.52 $2.65
	As of March 15, 1998, there were approximately 1,300 holders of record of the Registrant's Common Stock. Management believes that there are also approximately 750 additional beneficial owners of common stock held in "street name".
	The Registrant has never declared or paid a cash dividend on its Common Stock nor does it anticipate that dividends will be paid in the near future. Further, certain of the Company's financing agreements restrict the payment of cash dividends. See Note F to the Financial Statements for further information.
ITEM 6.
ITEM 6.	SELECTED FINANCIAL DATA
1997 1996 1995 1994 1993 Operating Revenue $ 4,189,793 $ 3,806,790 $ 2,874,001 $ 2,442,850 $ 2,375,150
Income (Loss) Before Cumula- tive Effect of Accounting Change $ 766,265 $ 733,726 $ 303,889 $ 40,141 $(1,654,090)
Net Income (Loss) $ 766,265 $ 733,726 $ 303,889 $ 40,141 $(1,077,090)
Income (Loss) Per Share From Continuing Operations $ .19 $ .18 $ . 08 $ .01 $ (.41)
Net Income (Loss) Per Share $ .19 $ . 18 $ . 08 $ .01 $ (.27)
AT YEAR END: Total Assets $ 8,032,328 $ 7,909,965 $ 6,690,285 $ 5,796,354 $ 5,856,396
Long-term Debt $ 666,000 $ 998,097 $ 958,330 $ 787,035 $ 1,019,792
Current Maturities $ 457,097 $ 283,200 $ 511,594 $ 385,219 $ 371,677
Working Capital $ 18,240 $ 205,463 $ (171,949) $ (86,786) $ 149,646 (Deficit)
Stockholders' Equity $ 5,691,597 $ 4,873,927 $ 4,114,001 $ 3,798,549 $ 3,758,408
ITEM 7.
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
	The Company operates through two primary segments: 1) oil and gas exploration and production; and 2) leonardite mining and processing wherein the Company's major products are oil and gas drilling mud additives. Each of the Company's segments is discussed herein.
BUSINESS ENVIRONMENT AND RISK FACTORS
	The following discussion should be read in conjunction with the Company's consolidated financial statements and related notes included elsewhere herein. The Company's future operating results may be affected by various trends and factors which are beyond the Company's control. These include, among other factors, the competitive environment in which the Company operates, oil and gas prices, demand for oil, gas and leonardite, availability of drilling rigs, dependence upon key management personnel, and other uncertain business conditions that may affect the Company's business.
	With the exception of historical information, the matters discussed below under the headings "Results of Operations" and "Liquidity and Capital Resources" may include forward-looking statements that involve risks and uncertainties. The Company cautions the reader that a number of important factors discussed herein, and in other reports filed with the Securities and Exchange Commission, could affect the Company's actual results and cause actual results to differ materially from those discussed in forward-looking statements.
RESULTS OF OPERATIONS
Comparison of 1997 to 1996 Revenue and Gross Margin
	Oil and gas sales were $3,425,000 in 1997 compared to $2,965,000 in 1996, an increase of $460,000 or 16%. This increase in revenue was due to a 9% decrease in average oil prices and a 26% increase in the volume of oil and gas sold. The 1997 average oil price per barrel was $16.15 compared to an average of $17.67 in 1996. The Company periodically uses various New York Mercantile Exchange (NYMEX) crude oil and energy products contracts and options to hedge against the risks of oil price declines. See Note K to the Financial Statements for further information. The volume of oil and gas sold in 1997 increased to 213,000 barrels of oil equivalent (BOE) from 169,000 BOE in 1996. The lower 1997 average oil price resulted from moderately lower world oil prices that existed during 1997. The higher 1997 production volumes resulted from production contributed by horizontal wells the Company has drilled in recent years. The horizontal well that had the largest impact on production in 1997 compared to 1996 was the Oscar Fossum H3 that began production in December 1996.
	Oil and gas production costs were $1,336,000 in 1997 compared to $1,082,000 in 1996, an increase of $254,000 or 23%. About two-thirds of the increase resulted from two factors, the first being the Company's increased workover activity in 1997, and the second, increased repairs and maintenance on the Company's oil and gas production facilities. For many years before the Company drilled its first horizontal well in 1995, cash flow was substantially lower, and therefore, non-essential repairs and maintenance of production equipment were often deferred in order to minimize production expense and conserve cash flow. During 1997, with substantially more cash flow available, the Company performed many repairs and maintenance on production equipment in an effort to improve their operating condition and efficiency. The remaining one-third of the increase in oil and gas production costs was due to smaller increases in many expense categories due to either increased costs of goods or the Company's increased production levels. For example, production taxes increased $13,000 due to the higher oil sales, electrical power increased $35,000 due to more wells using power, and contract pumping services increased $26,000 due to a rate increase and more wells. Even with these higher production costs, however, production costs expressed on a per- equivalent-barrel basis remained relatively stable, averaging $6.27 for 1997 compared to $6.40 for 1996. The stability in per barrel costs was due to increased production which spread the costs over more barrels. Gross margin for 1997 oil and gas operations before deductions for depletion and selling, general and administrative expenses increased to $2,090,000, or 61% of revenue, compared to $1,883,000, or 63% of revenue, for 1996. The stability in 1997 gross margin as a percentage of revenue was due to oil revenues increasing the same percentage as production costs.
	Leonardite product sales were $764,000 in 1997 compared to $842,000 in 1996, a decrease of $77,000, or 9%. This decrease was due to a 9% decrease in tonnage sold in 1997 resulting from weaker demand for the Company's products in the fourth quarter of 1997. Production sold in 1997 was 8,094 tons at an average price of $94.44, compared to 8,909 tons at an average price of $94.49 for 1996.
	Cost of leonardite sold was $598,000 in 1997 compared to $667,000 in 1996, a decrease of $70,000 or 10%. This decrease resulted from the 9% decrease in 1997 tonnage sold. Production costs per ton were $73.86 and $74.92 for 1997 and 1996, respectively. Costs per ton were essentially stable for 1997 compared to 1996 and varied only slightly due to the ratio of basic products and specialty products processed in 1997 and 1996.
	Gross margin for 1997 leonardite operations before deductions for depreciation and selling, general and administrative expenses was $167,000, or 22% of revenue, compared to $174,000, or 21% of revenue, for 1996. The relative stability in 1997 gross margin resulted from relatively equal declines in leonardite production costs compared to leonardite sales.
Comparison of 1997 to 1996 Consolidated Analysis
	Total revenue for 1997 increased $383,000, or 10%, to $4,190,000 from $3,807,000 in 1996. This increase was due to the higher oil and gas production previously discussed.
	Total operating costs for 1997 increased $310,000 or 11%, to $3,233,000 compared to $2,923,000 in 1996. These increased costs resulted from the higher oil and gas production costs previously discussed coupled with higher depreciation, depletion and amortization (DD&A) expenses. DD&A expenses were higher due to higher oil production levels that increased the oil depletion expense portion of DD&A.
	Higher 1997 total revenue, and to a lesser extent higher total operating costs, resulted in operating income of $957,000 for 1997 compared to $883,000 in 1996. Nonoperating expenses increased $16,000 from $64,000 in 1996 to $80,000 in 1997, yielding an income before taxes of $876,000 in 1997 compared to $819,000 in 1996.
	Income tax expense in 1997 was $110,000 compared to $86,000 in 1996. The expense amount for each year is reflective of the net changes in the Company's deferred-tax assets and deferred-tax liabilities under the provisions of SFAS No. 109 and include only a small amount of income taxes currently paid. See Notes A and G to the Financial Statements for further information.
	Net income for 1997 was $766,000 or 19 cents per share compared to a net income of $734,000 or 18 cents per share in 1996.
Comparison of 1996 to 1995 Revenue and Gross Margin
	Oil and gas sales were $2,965,000 in 1996 compared to $2,170,000 in 1995, an increase of $795,000 or 37%. This increase in revenue was due to a 24% increase in average oil prices and a 10% increase in the volume of oil and gas sold. The 1996 average oil price was $17.67 compared to an average of $14.24 in 1995. The Company periodically uses various New York Mercantile Exchange (NYMEX) crude oil and energy products contracts and options to hedge the risks of oil price declines. See Note K to the Financial Statements for further information. The volume of oil and gas sold in 1996 increased to 169,000 BOE (Barrels of Oil Equivalent) from 154,000 BOE in 1995. The higher 1996 average oil price resulted from substantially higher world oil markets that existed during 1996. The higher 1996 production volumes resulted entirely from production contributed by the Company's Oscar Fossum H2 horizontal well (.67 net) that began production in December 1995.
	Oil and gas production costs were $1,082,000 in 1996 compared to $950,000 in 1995, an increase of 14%. This $132,000 increase was caused by a $46,000 increase in production taxes resulting from higher oil prices, a $44,000 increase related to increased workover activity and a $42,000 increase in winter-related costs including snow removal and increased prices of propane fuel for oil treating facilities. Production costs on a per equivalent barrel basis however, remained relatively stable averaging $6.40 for 1996 compared to $6.18 for 1995. The stability in per barrel costs was due to increased production which spread the costs over more barrels. Gross margin for 1996 oil and gas operations before deductions for depletion and selling, general and administrative expenses was $1,883,000, or 63% of revenue, compared to $1,220,000, or 56% of revenue, for 1995. The increase in 1996 gross margin was primarily due to higher 1996 oil prices previously discussed.
	Leonardite product sales were $842,000 in 1996 compared to $704,000 in 1995, an increase of $138,000, or 20%. This increase was primarily due to an 18% increase in products sold resulting from increased demand for drilling mud additives associated with increased oil and gas drilling in the United States. Production sold in 1996 was 8,909 tons at an average price of $94.49, compared to 7,528 tons at an average price of $93.51 for 1995. Variations in the average per ton prices were normal fluctuations associated with the ratio of basic products and specialty products sold during 1996 and 1995.
	Cost of leonardite sold was $667,000 in 1996 compared to $560,000 in 1995, an increase of $108,000 or 19%. This increase resulted from the 18% increase in 1996 production. Production costs per ton were $74.92 and $74.34 for 1996 and 1995, respectively. Costs per ton were essentially stable for 1996 compared to 1995 and varied only slightly due to the ratio of basic products and specialty products processed in 1995 and 1996.
	Gross margin for 1996 leonardite operations before deductions for depreciation and selling, general and administrative expenses was $174,000, or 21% of revenue, compared to $144,000, or 20% of revenue, for 1995. The increase in 1996 gross margin was primarily due to the higher product sales previously discussed.
Comparison of 1996 to 1995 Consolidated Analysis
	Total revenue for 1996 increased $933,000, or 32%, to $3,807,000 from $2,874,000 in 1995. This increase was due to the higher oil and gas production and prices and increased leonardite product sales previously discussed.
	Total operating costs for 1996 increased $471,000 or 19%, to $2,923,000 compared to $2,453,000 in 1995. These increased costs resulted from the higher oil and gas and leonardite production cost previously discussed coupled with higher depreciation, depletion and amortization (DD&A) and selling, general and administrative (SG&A) expenses. SG&A expenses were higher due to increased costs for corporate publicity, shareholder communications and general increases in office activity. SG&A expenses also increased due to the Company's contribution to its employees' profit sharing plan that was $25,000 higher than the prior year and a non-cash expense incurred in 1996 related to a one time stock grant upon the retirement of an employee. DD&A expenses were higher due to higher oil production levels that increased oil depletion expense.
	Higher 1996 total revenue, and to a lesser extent higher total operating costs, resulted in operating income of $883,000 for 1996. Nonoperating expenses decreased $25,000 from $90,000 in 1995 to $64,000 in 1996, yielding an income before taxes of $819,000 in 1996 compared to $332,000 in 1995.
	Income tax expense in 1996 was $86,000 compared to $28,000 in 1995. The expense amount for each year is reflective of the net changes in the Company's deferred tax assets and deferred tax liabilities under the provisions of SFAS No. 109 and include only a small amount of income taxes currently paid. See Notes A and G to the Financial Statements for further information.
	Net income for 1996 was $734,000 or 18 cents per share compared to a net income of $304,000 or 8 cents per share in 1995.
LIQUIDITY AND CAPITAL RESOURCES.
	At December 31, 1997, the Company had current assets of $1,358,000 compared to current liabilities of $1,340,000 for a current ratio of 1.01 to 1 and working capital of $18,000. This compares to a current ratio of 1.11 to 1 at December 31, 1996 and working capital of $205,000. The lower working capital for 1997 was primarily due to lower oil and gas receivables from lower year-end 1997 oil prices and the Company continuing to use cash and cash flow to drill additional horizontal wells.
	During the year ended December 31, 1997, the Company generated cash flows from operating activities of $2,228,000 which is $1,077,000 greater than the amount generated during 1996. This increase was due in a large part to increased oil production in 1997 coupled with other changes to current assets and liabilities. During the second quarter of 1997, the Company drilled the Ballantyne-State/Steinhaus H1 (BSS H1) horizontal well (1 gross, 1.0 net) in the Wayne Field, Bottineau County, ND; and the Company spudded a second horizontal well in the same field, the Oscar Fossum H4 (1 gross, .67 net) just before year-end 1997. The Oscar Fossum H4 was drilled and completed successfully, and was put on production in February 1998. The Company anticipates that cash flows from operations and funds available under a new 1997 $3,000,000 revolving line of credit will be sufficient to meet its short-term cash requirements. This new line of credit replaces the Company's prior 1995 line of credit and contains terms substantially the same as the 1995 line. It allows borrowings until January 5, 2001 with repayment of any amounts borrowed to begin by that date. The Company can select a repayment schedule of up to a maximum of 48 months.
During 1997, the Company's investing activities used $2,707,000 of cash which was primarily for additions to property, plant and equipment. The additions to property and equipment consists of the approximate amounts as follows: Exploration and development costs of $2,553,000 that included the paid portion of costs for drilling and completing the Oscar Fossum H3 in late 1996 and the BSS H1 in mid-1997, proved property acquisition costs of $29,000 that included the cost of acquiring some small interests in several producing wells, unproved property costs of $55,000 primarily for oil and gas lease costs, delay rental costs of $27,000 and improvements to the Company's leonardite plant of $43,000.
	During 1997, the Company's financing activities also utilized $583,000 of cash for principal payments on long-term debt agreements. This amount consisted of $283,200 of regularly scheduled debt maturities for 1997 plus $300,000 that was paid down prior to terming out the Company's 1995 revolving line of credit in December 1997 and replacing it with the new 1997 $3,000,000 revolving line of credit discussed above.
	The sources of cash in 1997 for the investing and financing activities discussed above were the cash flows provided by operating activities, $425,000 of borrowings on the Company's 1995 revolving line of credit and a Volumetric Production Payment (VPP) with Koch Producer Services, Inc., that forward sold 27,375 barrels of oil from one of the Company's properties and provided the Company with cash of $364,550. A $300,000 portion of the VPP cash was then applied to partially pay down the 1995 revolving line of credit before terming it out as discussed above. The VPP agreement started December 1, 1997 and ends November 30, 1998. During that time, the Company's production is reduced by the 75 barrels of oil per day that is being delivered to Koch under the terms of the forward sale.
	Management estimates that the Company could incur development costs in 1998 in the range of $1,000,000 related to the Company's proved developed nonproducing and proved undeveloped oil and gas properties. Other planned expenditures for 1998 consist of delay rentals and other exploration costs of approximately $100,000. Capital expected to be used for 1998 principal payments required under existing debt agreements totals $457,000. The estimated amounts for exploration and development are uncertain because of the extremely low oil prices that exist as of March 1998. During March 1998, crude oil prices on the NYMEX have both declined to their lowest levels in nearly 10 years and then also regained nearly 25% of their value. These dramatic fluctuations are caused by the market's perception of what major oil producing countries will do to reduce oil production. The price the Company receives for its oil production is tied directly to world oil markets, and lower prices will reduce cash flow. The Company budgets and estimates its capital expenditures, but these estimates can change, either upward or downward, very quickly with the effects oil prices have on cash flow.
	Management expects to continue to evaluate possible future purchases of additional producing oil and gas properties and the further development of currently owned properties. Management believes the Company's long-term cash requirements for such investing activities and the repayment of long-term debt can be met by the continued future cash flows from operations, and, if necessary, possible forward sales of oil reserves or additional debt or equity financing.
ITEM 8.
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See "Index to Consolidated Financial Statements and Supplementary Data" on page 25.
ITEM 9.
ITEM 9.	DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
	Not applicable.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
	The following sets forth certain information concerning each director and executive officer of the Company:
Position(s) with Period of Service as Name and Age the Company a Director or Officer
Jeffrey P. Vickers President and Since 1982 Age: 45 Director
Thomas F. Neubauer Vice President Since June 1992 Age: 63 of Leonardite Operations
Cathy Kruse Secretary, Since October 1981; Age: 43 Treasurer and October 1981 to May Director 1985 and since June 1990; since June 1996
H. Dennis Hoffelt Director From 1967 through June Age: 57 1986; and since June 1987
Joseph V. Montalban Director Since June 1996 Age: 74
Paul A. Krile Director Since June 1997 Age: 70
	All of the directors' terms expire at the next annual meeting of shareholders or when their successors have been elected and qualified. The executive officers of the Company serve at the discretion of the Board of Directors.
	Jeffrey P. Vickers received a Bachelor of Science degree in Geological Engineering with a Petroleum Engineering option from the University of North Dakota in 1978. Prior to obtaining his degree, Mr. Vickers served two years overseas with the U.S. Army. In 1979, Mr. Vickers joined Amerada Hess Corporation as an Associate Petroleum Engineer in the Williston Basin. In 1981, Mr. Vickers was employed by the Company as the Drilling and Production Manager where he was responsible for providing technical assistance and supervision of drilling and production operations and generated development drilling programs. He became President of the Company on January 1, 1983. In June 1982, Mr. Vickers became a director of the Company.
	Thomas F. Neubauer is Vice President of Leonardite Operations and plant manager of the Company. Mr. Neubauer has been employed by the Company since July 1965.
	Cathy Kruse is Secretary, Treasurer and business office manager of the Company. Ms. Kruse graduated from the Atlanta College of Business in 1977 and was employed as a Legal Assistant for four years prior to her employment with the Company in May 1981. In June, 1996, Ms. Kruse became a director of the Company.
	H. Dennis Hoffelt has been President of Triangle Electric Inc., Williston, North Dakota, an electrical contracting firm, for over the past five years. He served as a director of the Company from 1967 through June of 1986 and was elected as a director again in 1987.
	Joseph V. Montalban has been a director of the Company since June 1996. He is a petroleum engineering consultant and was the founder of Mountain States Resources, Inc. and Monte Grande Exploration Ltd., the companies that merged to create MSR Exploration Ltd. He held various offices on the MSR Board until his resignation in 1994. Mr. Montalban is the President and Chief Executive Officer of Montalban Oil & Gas Operations, Inc.
	Paul A. Krile has been a director of the Company since June 1997. He has been the President and owner of Ranco Fertiservice, a manufacturer of dry fertilizer handling equipment, headquartered in Sioux Rapids, Iowa for more than the last five years.
	Cathy Kruse, Secretary and Treasurer of the Company, is the sister-in-law of Jeffrey P. Vickers. No other family relationship exists between or among any of the above named persons. There are no arrangements or undertakings between any of the named directors and any other persons pursuant to which any director was selected as a director or was nominated as a director. Based solely upon a review of Forms 3, 4 and 5 furnished to the Company, no officer or director failed to file any of the above forms on a timely basis.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
	The following table presents the aggregate compensation which was earned by the Chief Executive Officer for each of the past three years. The Company does not have an employment contract with any of its executive officers. With the exception of Jeffrey P. Vickers, no employee of the Company earned total annual salary and bonus in excess of $100,000. There has been no compensation awarded to, earned by or paid to any employee required to be reported in any table or column in any fiscal year covered by any table, other than what is set forth in the following table.
Summary Compensation Table
Long Term Compensation Annual Compensation Awards Payouts All Other Restricted Securities Other Name and Annual Stock Underlying LTIP Compen- Principal Salary Bonus Compen- Award(s) Options Payouts sation Position Year ($) ($) sation ($) SARs(#) ($) ($)
Jeffrey 1997 $82,596 25,000 -0- N/A 71,000 N/A $8,747 P. 1996 $78,443 -0- -0- N/A -0- N/A $11,766 Vickers 1995 $74,659 -0- -0- $925 35,000 N/A $8,150 CEO
	In the table above, the column titled "Restricted Stock Awards" is comprised of a 1995 grant of 1,000 shares of common stock from the Registrant to each full-time employee, including Jeffrey P. Vickers. Restricted Stock Awards are "restricted securities" as defined in Rule 144 adopted under the Securities Act of 1933. The column titled "All Other Compensation" is comprised entirely of profit sharing amounts.
	If the Company achieves net income in a fiscal year, the Board of Directors may determine to contribute an amount based on the Company's profits to the Employees' Profit Sharing Plan and Trust adopted in December 1978 (the "Profit Sharing Plan"). An eligible employee may be allocated from 0% to 15% of his compensation depending upon the total contribution to the plan. A total of 20% of the amount allocated to an individual vests after three years of service, 40% after four years, 60% after five years, 80% after six years and 100% after seven or more years. On retirement, an employee is eligible to receive the vested amount. On death, 100% of the amount allocated to an individual is payable to the employee's beneficiary. The Company accrued a $21,508 contribution for 1997 with contributions for 1996 and 1995 being $60,000 and $35,000, respectively. As of December 31, 1997, vested amounts in the Profit Sharing Plan for all officers as a group were approximately $366,000.
	Effective July 1, 1997, the Company executed an Adoption Agreement Nonstandardized Code 401(k) Profit Sharing Plan that includes a 401(k) Plan into the existing Profit Sharing Plan. Eligible employees are allowed to defer up to 15% of their compensation with the Company matching up to 5%.
Aggregated Option/SAR Exercises in last Fiscal Year and FY-End Option/SAR Values
Value of Number of Unexercised Unexercised In-the-Money Options/SARs Options/SARs Shares at FY-End(#) at FY-End($) Acquired on Value Exercisable/ Exercisable/ Name Exercise(#) Realized($) Unexercisable Unexercisable Jeffrey P. Vickers, CEO -0- -0- 106,000/0 $245,125/0
	At the 1993 Annual Meeting of Shareholders, the Company's 1993 Employees' Incentive Stock Option Plan (the "Plan") was approved by shareholders. The purpose of the Plan is to enable the Corporation to attract persons of training, experience and ability to continue as employees and to furnish additional incentive to such persons, upon whose initiative and efforts the successful conduct and development of the business of the Corporation largely depends, by encouraging such persons to become owners of the common stock of the Corporation.
	The term of the Plan expires February 17, 2003, ten years from the date the Plan was approved by the Board of Directors. If within the duration of an option, there shall be a corporate merger consolidation, acquisition of assets or other reorganization; and if such transaction shall affect the optioned stock, the optionee shall thereafter be entitled to receive upon exercise of his option those shares or securities that he would have received had the option been exercised prior to such transaction and the optionee had been a stockholder of the Corporation with respect to such shares.
	The Plan is administered by the Board of Directors. The exercise price of the common stock offered to eligible participants under the Plan by grant of an option to purchase common stock may not be less than the fair market value of the common stock at the date of grant; provided, however, that the exercise price shall not be less than 110% of the fair market value of the common stock on the date of grant in the event an optionee owns 10% or more of the common stock of the Corporation. A total of 300,000 shares have been reserved for issuance pursuant to options to be granted under the Plan. Of the 300,000 reserved shares, options have been issued for 295,000 shares pursuant to the Plan.
Directors' Compensation
	The officers of the Company who are also directors receive no additional compensation for attendance at Board meetings. Directors, other than Jeffrey P. Vickers and Cathy Kruse, were paid $200 per month for Board meetings in 1997.
ITEM 12.
ITEM 12. SECURITES OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
	The following table sets forth the number of shares of common stock beneficially owned by each officer, director and nominee for director of the Company and by all directors and officers as a group, as of March 15, 1998. Unless otherwise indicated, the shareholders listed in the table have sole voting and investment powers with respect to the shares indicated.
Name of Person or Number of Amount of Class of Directors and Shares and Nature of Percent Securities Officers as a Group Beneficial Ownership of Class
Common Stock, Jeffrey P. Vickers 374,934-Direct and 9.2% $.01 par value Indirect(a)
Common Stock, Paul A. Krile 207,500-Direct(b) 5.1% $.01 par value
Common Stock, Cathy Kruse 19,450-Direct(d) (c) $.01 par value
Common Stock, Thomas F. Neubauer 20,500-Direct(e) (c) $.01 par value
Common Stock, H. Dennis Hoffelt 39,000-Direct and (c) $.01 par value Indirect(f)
Common Stock, Joseph V. Montalban 463,800-Direct(g) 11.3% $.01 par value
Common Stock, Officers and 1,125,184-Direct and 27.5% $.01 par value Directors as Indirect a Group- (a)(b)(c)(d)(e)(f)(g) (six persons) - ------------------------	 (a) Included in the 374,934 shares listed for Jeffrey P. Vickers are 139,634 shares owned directly by him, 2,500 in a self-directed individual retirement account, 70,000 shares held jointly with his wife, Nancy J. Vickers, 25,500 shares held directly by his wife, 1,300 shares in his wife's self-directed individual retirement account, and an aggregate 30,000 shares held by him as custodian for his three minor children. Also included are 106,000 shares which may be purchased by Mr. Vickers under presently exercisable stock options granted pursuant to the Company's 1993 Employees' Incentive Stock Option Plan.
(b) Mr. Krile has sole voting and investment powers over these shares.
(c) Less than 1%.
(d) Included in the 19,450 are 14,500 shares which may be purchased by Ms. Kruse under presently exercisable stock options granted pursuant to the Company's 1993 Employees' Incentive Stock Option Plan.
(e) Included in the 20,500 are 9,500 shares which may be purchased by Mr. Neubauer under presently exercisable stock options granted pursuant to the Company's 1993 Employees' Incentive Stock Option Plan.
(f) Mr. Hoffelt has sole voting and investment power over 11,500 of shares and has shared voting and investment powers over the remaining 27,500.
(g) Mr. Montalban has sole voting and investment powers over these shares.
	The following table sets forth information concerning persons known to the Company to be the beneficial owners of more than 5% of the Company's outstanding common stock as of March 15, 1998.
Amount of Class of Name and Shares and Nature of Percent Securities Address of Person Beneficial Ownership of Class
Common Stock, Joseph V. Montalban 463,800-Direct(a) 11.3% $.01 par value Montalban Oil & Gas Operations, Inc. Box 200 Cut Bank, MT 59247
Common Stock, Jeffrey P. Vickers 374,934-Direct and 9.2% $.01 par value 1814 14th Ave. W. Indirect(b) Williston, ND 58801
Common Stock, Paul Krile 207,500-Direct(a) 5.1% $.01 par value P. O. Box 329 Sioux Rapids, IA 50585
	 (a) This information was obtained from a Securities and Exchange Commission filing.
(b) See footnote (a) of the immediately preceding table.
	No arrangements are known by the Company which could, at a subsequent date, result in a change in control of the Company. The Company is not aware of any officer, director or holder of greater than 10% of the Company's common stock who has failed to file the required SEC Forms 3, 4 or 5 on a timely basis for 1997.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
	There are no transactions or series of similar transactions since the beginning of the Company's last fiscal year or any currently proposed transaction or series of similar transactions to which the Company was or is to be a party, and which the amount involved exceeds $10,000 and in which any director, executive officer, principal shareholder or any member of their immediate family had or will have a direct or indirect material interest.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Documents filed as Part of this Report
(1) Financial Statements and Schedules See "Index to Consolidated Financial Statements and Supplementary Data" on next page. There are no financial statement schedules filed herewith.
(2) Disclosures About Oil and Gas Producing Activities - Unaudited See "Index to Consolidated Financial Statements and Supplementary Data" on next page.
(3) Exhibits See "Exhibit Index" on page 51.
(b) Reports on Form 8-K None.
(c) Exhibits required by Item 601 of Regulation S-K See (a)(3) above.
(d) Financial Statement Schedules required by Regulation S-X See (a)(1) above.
GEORESOURCES, INC., AND SUBSIDIARY INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page REPORT OF INDEPENDENT AUDITORS ON THE CONSOLIDATED FINANCIAL STATEMENTS 27
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated balance sheets 28 Consolidated statements of operations 29 Consolidated statements of stockholders' equity 30 Consolidated statements of cash flows 31 - 32 Notes to consolidated financial statements 33 - 46
UNAUDITED SUPPLEMENTARY INFORMATION - Disclosures about oil and gas producing activities 47 - 49
REPORT OF INDEPENDENT AUDITORS ON THE CONSOLIDATED FINANCIAL STATEMENTS
To the Board of Directors and Shareholders GeoResources, Inc.
We have audited the accompanying consolidated balance sheets of GeoResources, Inc., and Subsidiary as of December 31, 1997 and 1996, and the related consolidated statements of operations, stockholders' equity, and cash flows for the years ended December 31, 1997, 1996 and 1995. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GeoResources, Inc., and Subsidiary as of December 31, 1997 and 1996, and the results of its operations and its cash flows for the years ended December 31, 1997, 1996 and 1995, in conformity with generally accepted accounting principles.
/s/ Richey, May & Co., P. C. Denver, Colorado March 1, 1998
GEORESOURCES, INC., AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1997 AND 1996
ASSETS CURRENT ASSETS: 1997 1996 Cash and equivalents $ 490,385 $ 754,888 Trade receivables, net 521,934 936,045 Inventories 288,264 251,499 Prepaid expenses 31,422 18,201 Investments 25,966 57,771
Total current assets 1,357,971 2,018,404
PROPERTY, PLANT AND EQUIPMENT, at cost: Oil and gas properties, using the full cost method of accounting: Properties being amortized 17,997,596 16,450,061 Properties not subject to amortization 124,672 93,640 Leonardite plant and equipment 3,211,825 3,216,597 Other 702,068 693,641
22,036,161 20,453,939 Less accumulated depreciation, depletion, amortization and impairment (15,510,109) (14,708,047)
Net property, plant and equipment 6,526,052 5,745,892
OTHER ASSETS: Mortgage loans receivable, related party 103,321 103,321 Other 44,984 42,348
Total other assets 148,305 145,669
TOTAL ASSETS $ 8,032,328 $ 7,909,965
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES: Accounts payable $ 770,204 $ 1,343,677 Current maturities of long-term debt 457,097 283,200 Accrued expenses 112,430 186,064
Total current liabilities 1,339,731 1,812,941
LONG-TERM DEBT, less current maturities 666,000 998,097
DEFERRED INCOME TAXES 335,000 225,000
CONTINGENCIES (NOTE I)
STOCKHOLDERS' EQUITY: Common stock, par value $.01 per share; authorized 10,000,000 shares; issued and outstanding, 4,097,214 and 4,060,714 shares, respectively 40,972 40,607 Additional paid-in capital 880,797 829,757 Retained earnings 4,769,828 4,003,563 Total stockholders' equity 5,691,597 4,873,927
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 8,032,328 $ 7,909,965
The accompanying notes are an integral part of these consolidated financial statements.
GEORESOURCES, INC., AND SUBSIDIARY CONSOLIDATED STATEMENTS OF OPERATIONS YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
1997 1996 1995 OPERATING REVENUE: Oil and gas sales $ 3,425,395 $ 2,964,939 $ 2,170,057 Leonardite sales 764,398 841,851 703,944
4,189,793 3,806,790 2,874,001
OPERATING COSTS AND EXPENSES: Oil and gas production 1,335,605 1,082,324 950,116 Cost of leonardite sold 597,813 667,437 559,659 Depreciation, depletion and amortization 850,599 674,805 601,814 Selling, general and administrative 449,161 498,882 341,008
3,233,178 2,923,448 2,452,597
Operating income 956,615 883,342 421,404
OTHER INCOME (EXPENSE): Interest expense (125,007) (113,384) (128,689) Interest income 25,036 18,287 10,808 Other income and losses, net 19,621 31,050 28,366
(80,350) (64,047) (89,515)
Income before income taxes 876,265 819,295 331,889
INCOME TAX EXPENSE 110,000 85,569 28,000
Net income $ 766,265 $ 733,726 $ 303,889
EARNINGS PER SHARE:
	Net income, basic and diluted $ .19 $ .18 $ . 08
Weighted average number of shares outstanding 4,076,284 4,056,274 4,025,234
Dilutive potential shares - Stock options 63,361 38,686 13,470
Adjusted weighted average shares 4,139,645 4,094,960 4,038,704
The accompanying notes are an integral part of these consolidated financial statements.
GEORESOURCES, INC., AND SUBSIDIARY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
Additional Common Stock Paid-in Retained Shares Amount Capital Earnings Total
Balance, December 31, 1994 4,023,214 $ 40,232 $ 792,369 $2,965,948 $3,798,549 Issuance of common stock as compensation 12,500 125 11,438 -- 11,563 Net income -- -- -- 303,889 303,889
Balance, December 31, 1995 4,035,714 40,357 803,807 3,269,837 4,114,001
Issuance of common stock as compensation 25,000 250 25,950 -- 26,200 Net income -- -- -- 733,726 733,726
Balance, December 31, 1996 4,060,714 40,607 829,757 4,003,563 4,873,927
Issuance of common stock as compensation 20,000 200 30,400 -- 30,600 Stock options exercised 16,500 165 20,640 -- 20,805 Net income -- -- -- 766,265 766,265
Balance, December 31, 1997 4,097,214 $ 40,972 $ 880,797 $4,769,828 $5,691,597
The accompanying notes are an integral part of these consolidated financial statements.
GEORESOURCES, INC., AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
1997 1996 1995 CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 766,265 $ 733,726 $ 303,889 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 850,599 674,805 601,814 Deferred income taxes 110,000 74,000 28,000 Issuance of common stock as compensation -- 26,200 11,563 Other 2,364 2,192 2,326 Changes in assets and liabilities: Decrease (increase) in: Trade receivables 414,111 (345,715) (96,735) Inventories (36,765) 33,519 (38,551) Prepaid expenses and other (13,221) (741) (187) Hedging instruments 31,805 (47,652) 10,853 Increase (decrease) in: Accounts payable 145,629 (87,604) (78,831) Accrued expenses (43,034) 87,527 59,473 Net cash provided by operating activities 2,227,753 1,150,257 803,614
CASH FLOWS FROM INVESTING ACTIVITIES Additions to property, plant and equipment (2,707,097) (583,128) (899,677) Proceeds from sale of property and equipment 364,550 -- 20,234 Other (7,314) (12,756) (47,215)
Net cash used in investing activities (2,349,861) (595,884) (926,658)
CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term borrowings 425,000 325,000 665,000 Principal payments on long-term debt (583,200) (513,627) (367,330) Proceeds from issuance of common stock 20,805 -- -- Debt issue costs (5,000) (2,936) (5,225)
Net cash provided by (used in) financing activities (142,395) (191,563) 292,445
NET INCREASE (DECREASE) IN CASH AND EQUIVALENTS (264,503) 362,810 169,401
CASH AND EQUIVALENTS, beginning of year 754,888 392,078 222,677
CASH AND EQUIVALENTS, end of year $ 490,385 $ 754,888 $ 392,078
The accompanying notes are an integral part of these consolidated financial statements.
GEORESOURCES, INC., AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued) YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
1997 1996 1995 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Cash paid for: Interest $ 124,245 $ 114,850 $ 127,990 Income taxes 9,922 1,569 336
The accompanying notes are an integral part of these consolidated financial statements.
GEORESOURCES, INC., AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. SIGNIFICANT ACCOUNTING POLICIES:
Nature of Operations and Principles of Consolidation
The accompanying consolidated financial statements include the accounts of GeoResources, Inc., and its 82% owned subsidiary, Belmont Natural Resource Company, Inc. ("BNRC"). All material intercompany transactions and balances between the entities have been eliminated. The minority interest in BNRC is not presented, as the amount is immaterial.
GeoResources, Inc. (the "Company") is primarily involved in oil and gas exploration, development and production in North Dakota and Montana and the mining of leonardite and manufacturing of leonardite products in North Dakota to be sold to customers located primarily in the Gulf of Mexico coastal areas. BNRC was incorporated in 1991 to exploit natural gas opportunities in the Pacific Northwest. All properties of the Company and BNRC are located in the United States.
Reclassifications
Certain accounts in the prior-year financial statements have been reclassified for comparative purposes to conform with the presentation in the current-year financial statements.
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. Significant estimates used in preparing these financial statements include the unaudited quantity of oil and gas reserves which directly effects the computation of depletion of oil and gas properties. It is at least reasonably possible that the estimates used will change within the next year.
Cash Equivalents
For purposes of the statements of cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.
Inventories
Inventories are stated at the lower of cost (first-in, first-out method) or market.
Investments
The Company's investments consist of marketable equity securities and various derivative financial instruments related to crude oil and other energy products.
Marketable equity securities are stated at market value. Securities acquired with the intent to resell in order to profit from short-term price movements are classified as trading account securities and related unrealized gains and losses are included in other income. Other securities are classified as assets available-for-sale and related unrealized gains or losses are recorded as a component of stockholders' equity. The specific security sold is used to compute realized gains or losses. All of the Company's securities are classified as trading account securities.
The Company periodically uses various derivative financial instruments to hedge a portion of future oil sales against the risk of possible decreases of crude oil prices. These instruments are accounted for as hedges and, accordingly, gains and losses are deferred and recognized when the future oil sales occur.
Oil and Gas Properties
The Company utilizes the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas reserves (including costs of abandoned leaseholds, delay lease rentals, dry hole costs, geological and geophysical costs, certain internal costs associated directly with acquisition, exploration and development activities, and site restoration and environmental exit costs) are capitalized.
All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-of- production method using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. The Company's oil and gas depreciation, depletion and amortization rate per equivalent barrel of oil produced was $3.40, $3.27 and $3.09 for 1997, 1996 and 1995, respectively.
In addition, the capitalized costs are subject to a "ceiling test," which basically limits such costs to the aggregate of the "estimated present value," discounted at a 10-percent interest rate of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties.
Gains or losses are not recognized upon the sale or other disposition of oil and gas properties, except in extraordinary transactions.
Costs not being amortized at December 31, 1997, consist of the unevaluated, unimpaired cost of undeveloped oil and gas properties which were acquired during the following years:
1997 $ 40,264 1996 15,993 1995 44,203 1994 and prior 24,212
Total $ 124,672
It is expected that evaluation of the above properties will occur primarily over the next four years.
Other Property and Equipment
Depreciation of other property and equipment is computed principally on the straight-line method over the following estimated useful lives:
Buildings 10-25 years Machinery and equipment 3-10 years
Impairment of Long-Lived Assets
Potential impairment of long-lived assets (other than oil and gas properties) is reviewed whenever events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. Impairment is recognized when the estimated future net cash flows (undiscounted and without interest charges) from the asset are less than the carrying amount of the asset. No impairment losses have been recognized on long-lived assets for the years ended December 31, 1997, 1996 and 1995.
Operating Costs and Expenses
Oil and gas production costs and the cost of leonardite sold exclude a provision for depreciation and depletion. Depreciation and depletion expense is shown in the aggregate in the accompanying statements of operations.
Income Taxes
Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes on temporary differences between the amount of taxable income and pretax financial income and between the tax bases of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. A valuation allowance is provided for deferred tax assets not expected to be realized. 	 Earnings Per Share of Common Stock
Earnings per share has been computed based on the weighted average number of common shares outstanding. The dilutive effect of outstanding stock options was immaterial.
Recently Issued Accounting Standards
In June 1997, the FASB issued SFAS No. 130-Reporting Comprehensive Income. SFAS No. 130 requires the reporting and display, in a full set of general-purpose financial statements, of all items that are required to be recognized under accounting standards as components of comprehensive income. SFAS No. 130 is effective for financial statements issued for periods beginning after December 15, 1997 and reclassification of financial statements for earlier periods for comparative purposes is required. The adoption of SFAS No. 130 will not have a material impact on these financial statements
In June 1997, the FASB issued SFAS No. 131-Disclosures about Segments of an Enterprise. SFAS No. 131 establishes standards for the way that public companies report information about their operating segments, products and services, geographic areas, and major customers. SFAS No. 131 is effective for periods beginning after December 15, 1997 and requires restatement of information presented for prior periods. The adoption of SFAS No. 131 will not have a material impact on these financial statements.
B. INDUSTRY SEGMENTS AND MAJOR CUSTOMER:
Segment information
The Company conducts all of its operations within the United States, which consist principally of oil and gas exploration and production and the mining and processing of leonardite. There are no sales or other transactions between these two business segments. Presented below is information concerning the Company's business segments for the years ended December 31, 1997, 1996 and 1995:
		1997			1996			1995	 	Revenue: Oil and gas $ 3,425,395 $ 2,964,939 $ 2,170,057 Leonardite 764,398 841,851 703,944
$ 4,189,793 $ 3,806,790 $ 2,874,001
Operating income: Oil and gas $ 1,365,729 $ 1,330,169 $ 744,465 Leonardite 33,859 40,737 10,657 General corporate activities (442,973) (487,564) (333,718)
$ 956,615 $ 883,342 $ 421,404
Depreciation and depletion: Oil and gas $ 724,061 $ 552,446 $ 475,476 Leonardite 108,903 107,087 111,958 	General corporate activities 17,635 15,272 14,380
$ 850,599 $ 674,805 $ 601,814
Identifiable assets, net: Oil and gas $ 5,452,759 $ 5,014,782 $ 4,110,608 Leonardite 1,452,847 1,501,054 1,552,442 	General corporate activities 1,126,722 1,394,129 1,027,235
$ 8,032,328 $ 7,909,965 $ 6,690,285
Capital expenditures incurred: Oil and gas $ 1,920,470 $ 1,156,842 $ 1,162,393 Leonardite 43,498 29,160 26,264 	General corporate activities 9,927 21,095 4,095
$ 1,973,895 $ 1,207,097 $ 1,192,752
Major Customer and Concentrations of Credit Risk
Sales to a major oil and gas customer were 71%, 65% and 53% of total revenue for the years ended December 31, 1997, 1996 and 1995, respectively. Accounts receivable from this major customer were 44% and 38% of total accounts receivable at December 31, 1997 and 1996, respectively.
The Company has two bank accounts with balances of approximately $191,000 and $226,000, at December 31, 1997. Each account is federally insured for balances up to $100,000.
C. TRADE RECEIVABLES AND INVENTORIES:
Trade receivables at December 31, 1997 and 1996 are comprised of the following:
1997 1996
Oil and gas purchasers $ 318,096 $ 700,833 Leonardite customers 215,254 246,628
533,350 947,461 	Less allowance for doubtful accounts (11,416) (11,416)
$ 521,934 $ 936,045
As of December 31, 1997 and 1996, inventories by major classes are comprised of the following:
1997 1996 	 Crude oil $ 29,550 $ 36,022
	Leonardite inventories: Finished products 90,302 52,543 Raw materials 85,433 94,387 Materials and supplies 82,979 68,547
Total leonardite inventories 258,714 215,477
$ 288,264 $ 251,499
D. MORTGAGE LOANS RECEIVABLE, RELATED PARTY
Mortgage loans receivable, related party represent mortgage loans on the residence of an officer/shareholder of BNRC purchased from a third party in November 1993, and are recorded at purchase cost. The mortgages require monthly payments of interest at 8% per annum with principal due January 14, 1999. The Company received interest income from these loans of $8,100 for each of the years ended December 31, 1997, 1996 and 1995.
E. VOLUMETRIC PRODUCTION PAYMENT
On December 3, 1997, the Company conveyed to Koch Producer Services, Inc., a volumetric production payment of 27,375 barrels of crude oil to be produced from a specified property through November 1998. The gross proceeds of this sale totaled $364,550 and were credited on the accompanying balance sheet to oil and gas properties being amortized. No gain or loss was recognized on the sale. The agreement requires the Company to maintain tangible net worth of not less than $3,500,000 and prohibits the Company from incurring any debt secured by the specified property.
F. LONG-TERM DEBT:
Long-term debt at December 31, 1997 and 1996 consists of the following loans and a revolving line of credit (RLOC) which are all with one bank:
1997 1996 The 1989 Leonardite Loan, prime plus 1% (9.5% total rate at December 31, 1997), due in monthly installments of $7,600 plus interest, due December 1998, unsecured $ 90,097 $ 181,297
The 1993 Oil & Gas Loan, prime plus 1% (9.5% total rate at December 31, 1997), due in monthly installments of $16,000 plus interest, due September 1999, collateralized by oil and gas properties 333,000 525,000
The 1995 Oil & Gas Loan, prime plus 1% (9.5% total rate at December 31, 1997), due in monthly installments of $14,583 plus interest, due December 2001, collateralized by oil and gas properties 700,000 575,000
The 1997 Oil & Gas RLOC, $3,000,000 revolving line of credit, interest payable monthly at prime plus .75%, (9.25% total rate at December 31, 1997), expires January 5, 2001, collateralized by oil and gas properties -- -- 	 Total long-term debt 1,123,097 1,281,297
Less current maturities (457,097) (283,200)
Long-term debt, less current maturities $ 666,000 $ 998,097
Aggregate maturities required on long-term debt at December 31, 1997, are as follows:
	Year Ending December 31: 1998 $ 457,097 1999 316,000 2000 175,000 2001 175,000
$ 1,123,097
The Company's borrowing base for debt secured by oil and gas properties is limited by the net present value of future oil and gas production of the properties as determined annually by the bank.
The Company's long-term debt was obtained pursuant to financing agreements which include the following covenants: Maintain a current ratio of not less than 1.25 to 1 exclusive of current maturities of long-term debt; maintain debt to tangible net worth of not more than 1.5 to 1; maintain a net worth of at least $3,500,000; not encumber certain of its assets; restricts borrowings from, and credit extensions to, other parties; restricts reorganization or mergers in which the Company is not the surviving corporation; and not pay cash dividends without the bank's consent.
G. INCOME TAXES:
The components of income tax expense for the years ended December 31, 1997, 1996 and 1995, are as follows: 1997 1996 1995 Current tax expense $ -- $ 11,569 $ -- Deferred tax expense 369,000 232,000 95,000 	Decrease in deferred tax assets valuation allowance (259,000) (158,000) (67,000)
$ 110,000 $ 85,569 $ 28,000
During 1997, 1996 and 1995, the Company recorded a deferred tax expense of $369,000, $232,000 and $95,000, respectively. This related primarily to net income which was not currently taxable due to the deduction of intangible drilling costs for tax purposes in 1997 and 1996 and the utilization of net operating loss carryforwards in 1995. The Company also decreased the deferred tax asset valuation allowance by $259,000, $158,000 and $67,000 during 1997, 1996 and 1995, respectively, primarily based upon the projection of utilizing additional statutory depletion carryforwards in the future.
The tax effects of significant temporary differences and carryforwards which give rise to the Company's deferred tax assets and liabilities at December 31, 1997 and 1996, are as follows: 1997 1996 Deferred Tax Assets: Net operating loss carryforward $ 390,000 $ 278,000 Statutory depletion carryforward 1,113,000 983,000 Tax credit carryforwards 69,000 226,000 Other 47,000 70,000 1,619,000 1,557,000 Valuation Allowance: Beginning of year (751,000) (909,000) (Increase) decrease 259,000 158,000 End of year (492,000) (751,000)
Deferred Tax Liabilities: 	Accumulated depreciation and depletion (1,462,000) (1,031,000)
Net Deferred Tax Liability, long-term $ (335,000) $ (225,000)
The provision for income taxes does not bear a normal relationship to pre-tax earnings. A reconciliation of the U.S. federal income tax rate with the actual effective rate for the years ended December 31, 1997, 1996 and 1995 is as follows:
1997 1996 1995
Income tax expense at statutory rate 35% 35% 35% Loss carryover benefits -- -- (14) Change in valuation allowance (30) (20) (21) Graduated tax rate difference -- (13) -- State income taxes and other 8 8 8
13% 10% 8%
For income tax purposes, the Company has a statutory depletion carryover of approximately $3,360,000 which, subject to certain limitations, may be utilized to reduce future taxable income. This carryforward does not expire. The Company also has net operating loss carryovers and investment tax credit carryovers (accounted for using the flow-through method), which, if not utilized, expire as follows:
Investment Net operating tax credit Year of expiration loss carryover carryover
1998-2000 $ -- $ 45,000 2001 412,000 -- 2003 102,000 -- 2008 115,000 -- 2009 237,000 -- 2012 313,000 --
Total $ 1,179,000 $ 45,000
H. STOCK OPTION AND PROFIT-SHARING PLANS:
Stock option plan
In 1993, the Company adopted the 1993 Incentive Stock Option Plan, whereby 300,000 shares of the Company's common stock are reserved for options which may be granted pursuant to the terms of the plan. Under the terms of the plan, the option price may not be less than 100% of the fair market value of the Company's common stock on the date of grant, and if the optionee owns more than 10% of the voting stock, the option price per share shall not be less than 110% of the fair market value.
Prior to 1995, no options had been granted. During 1995, options were granted to purchase 95,000 shares of common stock at an exercise price of $1.15 per share. No options were granted in 1996. During 1997, options were granted to purchase 102,500 shares at $2.37 per share and 97,500 shares at $2.31 per share. No options were exercised prior to 1997. During 1997, options were exercised to purchase 16,500 common shares for total proceeds to the Company of $20,805. At December 31, 1997, the following options are outstanding:
Number of shares Exercise Price Expiration Date 			 80,000 $ 1.15 November 2000 101,000 2.37 May 2002 97,500 2.31 December 2002
278,500
As permitted by SFAS No. 123, Accounting for Stock-Based Compensation, the Company continues to apply the provisions of APB Opinion 25 in accounting for its plan. Accordingly, no compensation cost was recognized for the options granted. Had stock-based compensation cost been determined based upon the fair value of the options estimated on the date of grant the Company's net income and earnings per share would have been reduced to pro forma amounts of $598,065 and $.15 and $269,839 and $.07, in 1997 and 1995, respectively. The fair value of the options on the date of grant is estimated using the Black-Scholes option-pricing model with the following assumptions:
1997 1995
Expected volatility 39% 31% Risk free interest rate 5.71% 5.77% Expected lives 3.5 years 4 years Expected dividends None None
Profit-sharing plan
The Company has a 401(k) profit sharing plan that covers all employees with one year of service who elect to enter the plan. Effective July 1, 1997, the Company amended the plan to provide for employee contributions. Employees may elect to contribute up to 15% of their compensation to a maximum of $10,000. The Company contributes an amount equal to each employee's contribution up to a maximum of 5% of the employee's compensation. The Company may also make additional discretionary contributions to the plan. Prior to 1997, contributions to the plan were at the discretion of the Board of Directors. The Company's contributions to the plan for the years ended December 31, 1997, 1996 and 1995 were $21,508, $60,000 and $35,000, respectively.
I. CONTINGENCIES:
All of the Company's operations are generally subject to federal, state or local environmental regulations. The Company's oil and gas business segment is affected particularly by those environmental regulations concerned with the disposal of produced oilfield brines and other wastes. The Company's leonardite mining and processing segment is subject to numerous state and federal environmental regulations, particularly those concerned with air quality at the Company's processing plant, and surface mining permit and reclamation regulations. The amount of future environmental compliance costs cannot be determined at this time.
J. OFFICE FACILITIES:
In 1991, the Company purchased an office building, one-third of which it occupies. The building is included in other property and equipment in the accompanying balance sheets and consists of the following at December 31, 1997 and 1996:
1997 1996
Building and improvements $ 163,834 $ 163,834 Accumulated depreciation (55,563) (47,371)
$ 108,271 $ 116,463
The Company leases the remainder of the building to unaffiliated businesses under cancelable lease agreements. During 1997, 1996 and 1995, the Company received $22,200, $20,938 and $19,500, respectively, in rental income from the building which is included in other income in the accompanying statements of operations.
K. FINANCIAL INSTRUMENTS:
The carrying amounts reflected in the consolidated balance sheets for cash and equivalents approximates their fair value due to the short maturity of the instruments. The carrying amount of marketable equity securities is fair value based on quoted market prices. The carrying amount of derivative financial instruments was $6,807 and $50,450 at December 31, 1997 and 1996, respectively. The fair value of those instruments, based on quoted market prices, was ($4,291) and $17,450 at December 31, 1997 and 1996, respectively. The carrying value of mortgage loans receivable approximates fair value based on discounted future cash flows.
The Company uses derivative financial instruments to manage its crude oil commodity price risk. They are not used for trading purposes. The Company has in recent years hedged 5% to 35% of its crude oil sales using various financial instruments including "put" and "call" options and, to a lesser extent, actual future contracts on crude oil and energy products that trade on the New York Mercantile Exchange ("NYMEX"). The variation in types of instruments employed results from a strategy designed to provide primarily short to intermediate term protection (less than one year) from oil price declines that would occur in a wide range. Generally, the Company does not hedge against narrow- range oil price movements. Since these financial instruments correlate to crude oil and energy products price movements, gains or losses resulting from market changes will be offset by losses or gains on the Company's crude oil sales. Included in oil and gas sales are losses from hedging activities totaling $30,269, $102,656 and $10,401 for the years ended December 31, 1997, 1996 and 1995, respectively.
At December 31, 1997, the notional principal amount of outstanding call options was $15,800 and the principal amount of outstanding forward contracts was $318,980. Deferred net hedging losses amounted to $11,098 and $33,000 at December 31, 1997 and 1996, respectively.
L. FOURTH QUARTER ADJUSTMENTS: 	 During the fourth quarter of 1997, deferred income tax liabilities increased $54,000 and income tax expense increased $46,491 over the amounts reported at September 30, 1997, due to changes in estimates regarding the utilization of tax credit carryforwards.
GEORESOURCES, INC., AND SUBSIDIARY UNAUDITED SUPPLEMENTARY INFORMATION DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
Net capitalized costs related to the Company's oil and gas producing activities are summarized as follows as of December 31, 1997, 1996 and 1995:
1997 1996 1995 Proved Properties $ 17,997,596 $ 16,450,061 $ 15,272,170 Unproved properties 124,672 93,640 157,174
Total 18,122,268 16,543,701 15,429,344
Less accumulated depreciation, depletion, amortization and impairment (13,069,796) (12,345,734) (11,793,289)
Net capitalized costs $ 5,052,472 $ 4,197,967 $ 3,636,055
Costs incurred in oil and gas property acquisition, exploration and development activities, including capital expenditures are summarized as follows for the years ended December 31, 1997, 1996 and 1995:
1997 1996 1995 Property acquisition costs: Proved $ 28,420 $ 42,611 $ 189,036 Unproved 55,230 21,027 15,479 Exploration costs 75,765 113,145 115,957 Development costs 1,761,055 980,059 841,921
$ 1,920,470 $ 1,156,842 $ 1,162,393
The Company's results of operations from oil and gas producing activities (excluding corporate overhead and financing costs) are presented below for the years ended December 31, 1997, 1996 and 1995.
1997 1996 1995 Oil and gas sales $ 3,425,395 $ 2,964,939 $ 2,170,057 Production costs (1,335,605) (1,082,324) (950,116) Depletion, depreciation and amortization (724,061) (552,446) (475,476)
1,365,729 1,330,169 744,465
Imputed income tax provision -- 10,000 26,000
$ 1,365,729 $ 1,320,169 $ 718,465
GEORESOURCES, INC., AND SUBSIDIARY UNAUDITED SUPPLEMENTARY INFORMATION DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
The reserve information presented below is based upon reports prepared by the independent petroleum engineering firm of Broschat Engineering and Management Services. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of mature producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under economic and operating conditions existing as of the end of each respective year. The year-end selling price of oil and gas is one of the primary factors affecting the determination of proved reserve quantities which fluctuate directly with that price.
Presented below is a summary of the changes in estimated proved reserves of the Company, all of which are located in the United States, for the years ended December 31, 1997, 1996 and 1995:
1997 1996 1995 Oil Gas Oil Gas Oil Gas (bbl) (mcf) (bbl) (mcf) (bbl) (mcf) Proved reserves, beginning of year 2,154,000 261,000 2,047,000 266,000 1,642,000 244,000
Purchases of reserves-in- place 1,000 -- 21,000 -- 67,000 --
Sales of reserves -in-place (25,000) -- -- -- -- --
Extensions and discoveries 201,000 1,000 12,000 3,000 5,000 1,000
Improved recovery 350,000 -- 156,000 -- 443,000 --
Revisions of previous estimates (83,000) 1,000 85,000 5,000 42,000 34,000
Production (211,000) (10,000) (167,000) (13,000) (152,000) (13,000)
Proved reserves, end of year 2,387,000 253,000 2,154,000 261,000 2,047,000 266,000
GEORESOURCES, INC., AND SUBSIDIARY UNAUDITED SUPPLEMENTARY INFORMATION DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Proved developed reserves of the Company are presented below as of December 31:
Oil Gas (bbl) (mcf)
	1997		1,640,000		253,000
	1996		1,366,000		261,000
	1995		1,292,000		266,000
Statement of Financial Accounting Standards No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines which are briefly discussed below.
Future cash inflows and future production and development costs are determined by applying year-end selling prices and year-end production and development costs to the estimated quantities of oil and gas to be produced. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates are the basis for the valuation process. Estimated future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion, depletion carryforwards, net operating loss carryforwards, and investment tax credit carryforwards. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.
The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and, as such, do not necessarily reflect the Company's expectations of actual revenues or future net cash flows to be derived from those reserves nor their present worth.
GEORESOURCES, INC., AND SUBSIDIARY UNAUDITED SUPPLEMENTARY INFORMATION DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
Presented below is the standardized measure of discounted future net cash flows as of December 31, 1997, 1996 and 1995:
1997 1996 1995 Future cash inflows $ 33,521,000 $ 46,708,000 $ 30,628,000 Future production costs (13,602,000) (17,419,000) (13,369,000) Future development costs (3,495,000) (3,078,000) (2,993,000) Future income tax expense (5,318,000) (7,385,000) (3,423,000)
Future net cash flows 11,106,000 18,826,000 10,843,000
Less effect of a 10% discount factor (4,587,000) (7,380,000) (4,381,000)
Standardized measure of discounted future net cash flows relating to proved reserves $ 6,519,000 $ 11,446,000 $ 6,462,000
The principal sources of change in the standardized measure of discounted future net cash flows are as follows for the years ended December 31, 1997, 1996 and 1995:
1997 1996 1995 Standardized measure, beginning of year $ 11,446,000 $ 6,462,000 $ 4,280,000
Sales of oil and gas produced, net of production costs (2,090,000) (1,985,000) (1,234,000)
Net changes in prices and production costs (6,612,000) 6,452,000 2,256,000
Purchases of reserves-in-place 1,000 121,000 436,000
Sales of reserves-in-place (120,000) -- --
Extensions, discoveries and other additions, less related costs 2,654,000 1,369,000 2,203,000
Revisions of previous quantity estimates and other (713,000) 1,209,000 599,000
Development costs incurred during the year and changes in estimated future development costs (1,011,000) (582,000) (1,415,000)
Accretion of discount 1,595,000 850,000 514,000
Net change in income taxes 1,369,000 (2,450,000) (1,177,000)
Standardized measure, end of year $ 6,519,000 $ 11,446,000 $ 6,462,000
Signatures
	Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
GEORESOURCES, INC. (the "Registrant") Dated: March 27, 1998 /s/ J. P. Vickers J. P. Vickers, President
	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 Registrant and in the capacities and on the dates indicated.
(Power of Attorney)
	Each person whose signature appears below constitutes and appoints J. P. VICKERS and DENNIS HOFFELT his true and lawful attorneys-in- fact and agents, each acting alone, with full power of stead, in any and all capacities, to sign any or all amendments to this Annual Report on Form 10-K and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, each acting alone, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in each acting alone, or his substitute or substitutes, may lawfully do or cause to be done by virtue thereof.
Signatures Title Date
/s/ J. P. Vickers President (principal execu- 3/27/98 J. P. Vickers tive officer and principal financial officer) and Director
/s/ Cathy Kruse Secretary/Treasurer 3/27/98 Cathy Kruse and Director
/s/ Dennis Hoffelt Director 3/27/98 Dennis Hoffelt
/s/ Joseph V. Montalban Director 3/27/98 Joseph V. Montalban
/s/ Paul A. Krile Director 3/27/98 Paul A. Krile
SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 		 GEORESOURCES, INC. (Commission File Number: 0-8041) 		 EXHIBIT INDEX FOR Form 10-K for 1997 fiscal year. 		 Page Number in Sequential Numbering of all Form 10-K and Exhibit Exhibit Pages
3.1 Registrant's Bylaws, as amended, November 30, 1994 *
3.2 Registrant's Articles of Incorporation, as amended to date, incorporated by reference to Exhibit 3.1 of the Registrant's Form 	10-K for fiscal year, 1983	 *	
10.1 Mining Lease and Agreement dated April 6, 1988, by and between Roger C. Ryan, Susan Ryan, Constance Ryan, Charlotte McConnell and Joseph W. Ryan as Lessors, and GeoResources, Inc. as Lessee incorporated by reference to Exhibit 10.4 of Registrant's Form 10-Q for fiscal quarter ended 	March 31, 1988	 *	
10.2 Credit Agreement dated January 24, 1989, by and between GeoResources, Inc. and Norwest Bank Billings, incorporated by reference to Exhibit 10.25 of the Registrant's Form 10-K for fiscal 	year, 1988	 *	
10.3 Promissory Note dated January 24, 1989, by and between GeoResources, Inc., as Borrower and Norwest Bank Billings, incorporated by reference to Exhibit 10.26 of the Registrant's 	Form 10-K for fiscal year, 1988	 *	
10.4 Combination Mortgage, Security Agreement and Fixture Financing Statement dated January 24, 1989, by and between GeoResources, Inc., as Mortgagor/Debtor and Norwest Bank Billings, as Mortgagee/Secured party, incorporated by reference to Exhibit 10.27 of the Registrant's Form 10-K for fiscal year, 1988 *	
10.5 Mortgage, Security Agreement, Assignment of Production and Financing Statement dated January 24, 1989, by and between GeoResources, Inc., as Mortgagor/Debtor and Norwest Bank Billings, as Mortgagee/Secured party, incorporated by reference to Exhibit 10.28 of the Registrant's Form 10-K for fiscal year, 1988 *	
10.6 Modification of Note of January 24, 1989, by and between Norwest Bank Billings and GeoResources, Inc., effective January 2, 1992, incorporated by reference to Exhibit 10.1 of the Registrant's Form 10-Q for fiscal quarter ended March 31, 1992 *	
10.7 License Agreement dated March 22, 1993, by and between GeoResources, Inc. and Central Arizona Material Co., incorporated by reference to Exhibit 10.1 of the Registrant's Form 	10-Q for fiscal quarter ended March 31, 1993	 *	
10.8 Secured Form Loan and Revolving Credit Agreement dated April 29, 1993, by and between GeoResources, Inc. and Norwest Bank Billings, incorporated by reference to Exhibit 10.1 of the 	Registrant's Form 10-Q for fiscal quarter ended June 30, 1993 *	
10.9 Mortgage, Security Agreement, Assignment of Production and Financing Statement dated April 29, 1993, by and between GeoResources, Inc., as Mortgagor and Norwest Bank Billings, as Mortgagee, incorporated by reference to Exhibit 10.2 of the Registrant's Form 10-Q for fiscal quarter ended June 30, 1993	 *	
10.10 The Registrant's 1993 Employees' Incentive Stock Option Plan, incorporated by reference as Exhibit A to the Registrant's definitive Proxy Statement dated May 5, 1993 *	
10.11 Amended and Restated Secured Term Loan and Revolving Credit Agreement made as of September 1, 1995, by and between GeoResources, Inc. and Norwest Bank Montana *	
10.12 First Amendment of Mortgage, Security Agreement, Assignment of Production and Financing Statement and Mortgage - Collateral Real Estate Mortgage dated September 1, 1995, by and between 	GeoResources, Inc. and Norwest Bank Montana	 *	
10.13 Commercial Installment Note with addendum dated February 1, 1997, by and between GeoResources, Inc. and Norwest Bank Billings, incorporated by reference to Exhibit 10.13 of Registrant's Form 10-K for fiscal year ended December 31, 1997 *
10.14 Purchase Agreement for Volumetric Production Payment dated as of December 3, 1997, by and between GeoResources, Inc. and Koch Producer Services, Inc. and all related documents. 54
10.15 Amended and Restated Secured Term Loan and Revolving Credit Agreement made as of December 5, 1997, by and Between GeoResources, Inc. and Norwest Bank Montana, and all related documents. 196
27 Financial Data Schedule