SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
___X___Annual Report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the fiscal year ended December 31, 1998.
_______Transition Report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the transition period from________to________.
Commission File Number - 0-8041
GeoResources, Inc.
(Exact name of Registrant as specified in its charter)
Colorado 84-0505444
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
1407 West Dakota Parkway, Suite 1-B 58801
Williston, North Dakota (Zip Code)
(Address of Principal executive offices)
(Registrant's telephone number including area code) (701) 572-2020
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12 (g) of the Act:
Common Stock, par value $0.01
________________________________________
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes___X___ No_______
________________________________________
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained,
to the best of Registrant's knowledge in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. ___X___
________________________________________
The aggregate market value of the Common Stock (the only class of voting
stock) held by nonaffiliates of the Registrant as of March 19, 1999, was
approximately $2,310,914 (based on the closing price of the Registrant's
common stock on the NASDAQ system on such date.)
Shares of $0.01 par value Common Stock outstanding at March 19,
1999: 4,071,652
________________________________________
Documents Incorporated By Reference - None
PART I.
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, 1998, the Registrant had developed oil and gas
leases covering approximately 12,932 net acres in Montana and North Dakota,
and during 1998 sold an average 478 net equivalent barrels of oil per day
from 110 gross (77.78 net) productive 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 1998, 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 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 83% 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 3,988 gross acres (3,754 net) on a gas prospect
located in the State of Washington. Activities in 1998 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 1999.
In addition to its two principal business segments, the
Registrant owns a nonproducing silver property in Arizona. (See Item 2.)
The Company also owns a minor amount of geothermal and other mineral rights
located in Oregon. The Registrant does not expect to devote any
substantial resources to hard mineral or geothermal exploration or
development in 1999.
Sources and Availability of Raw Materials and Leases
Maintaining sufficient leasehold mineral interests for oil and
gas exploration and development is a primary continuing need in the oil and
gas business. Management believes that the Company's current undeveloped
acreage is sufficient to meet its presently foreseeable oil and gas
leasehold needs. Maintaining sufficient leasehold mineral interests for
leonardite mining is also a continuing need for the Registrant's mining and
manufacturing of leonardite products. Management believes the leonardite
held under current leases is sufficient to maintain the present output for
many years. (See Item 2.)
Major Customers
In 1998, Registrant sold its crude oil to 26 purchasers. Koch
Oil Company was the major customer, accounting for approximately 77% of the
Registrant's oil and gas revenue in 1998 or approximately 54% of the
Registrant's total operating revenue. Management believes there are other
crude oil purchasers to whom the Company would be able to sell its oil if
it lost any of its current customers.
In 1998, the Registrant sold leonardite products to 44 customers.
The largest customer in 1998 for leonardite products made purchases
totaling 26% of the Registrant's mining and manufacturing revenue or
approximately 8% of the Registrant's total operating revenue.
Backlog Orders, Research and Development
The Registrant does not have any material long-term or short-term
contracts to supply leonardite products. All orders are reasonably
expected to be filled within three weeks of receipt. From time to time,
the Registrant enters into short-term contracts to deliver quantities of
oil or gas; however, no significant backlog exists. The Company's oil and
gas division order contracts and off lease marketing arrangements are
typical of those in the industry with 30 to 90 day cancellation notice
provisions and generally do not require long-term delivery of fixed
quantities of oil or gas. The Registrant has not spent any material time
or funds on research and development, and does not expect to do so in the
foreseeable future.
Competition
Oil and Gas: In addition to being highly speculative, the oil and
gas business is intensely competitive among the many independent operators
and major oil companies in the industry. Many competitors possess
financial resources and technical facilities greater than those available
to the Registrant and may, therefore, be able to pay more for desirable
properties or to find more potentially productive prospects. However,
management believes the Registrant has the ability to obtain leasehold
interests which will be sufficient to meet its oil and gas needs in the
foreseeable future.
Leonardite Products: Uses and specifications of leonardite-based
drilling mud additives are subject to change if better products are found.
The Registrant's products compete with leonardite and non-leonardite
products used as additives in numerous types of drilling mud. In addition,
leonardite deposits are available in other areas within the United States
and competitors may be able to enter the leonardite business with relative
ease. At the present time, similar products are marketed by other
companies who mine, process and market leonardite products. Competition
lies primarily in delivery time, transportation costs, quality of the
product, performance of the product when used in drilling mud and access to
high-quality leonardite.
Environmental Regulations
All of the Registrant's operations are generally subject to
federal, state or local environmental regulations. The Registrant's oil
and gas business segment is affected particularly by those environmental
regulations concerned with the disposal of produced oilfield brines and
other oil-related wastes. The Registrant's leonardite mining and
processing segment is also subject to numerous state and federal
environmental regulations, particularly those concerned with air
contaminant emission levels of the Company's processing plant, and mine
permit and reclamation regulations pertaining to surface mining at the
Company's leonardite mine. The Company believes that maintenance of
acceptable air contaminant emission levels at its processing plant could
become more costly in the future if plant production increases
substantially above levels experienced over the past several years.
Management believes significantly higher plant utilization would increase
emission levels and could make it necessary to replace or upgrade air
quality control equipment. Future environmental compliance costs that
might be required to upgrade the equipment are not known at this time.
Foreign Operations and Export Sales
The Registrant has no production facilities or operations in
foreign countries and has no direct export sales. Some of the Company's
leonardite products are sold to distributors in the United States who in
turn export these products.
Employees
As of March 15, 1999, the Registrant had 13 full-time employees.
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
1998 7,772 $ 92.47
1997 8,094 $ 94.44
1996 8,909 $ 94.49
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 17,760
gross (12,932 net) acres as of December 31, 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**
1998 173,102 8,491 174,517 $ 9.54 $ 1.26 $ 5.33
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
_____________________________
*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 December 31, 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
110 77.78 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 December 31,
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 7,637 17,377 17,302 26,377 24,939
North Dakota 8,760 5,295 30,026 13,304 44,786 18,599
Washington 0 0 3,988 3,754 3,988 3,754
ALL STATES 17,760 12,932 57,391 34,360 75,151 47,292
_____________________________
*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
1998 0.00 0.00 0.00 0.00 0.00
1997 0.00 0.02 1.67 0.00 1.69
1996 0.00 0.08 0.67 0.00 0.75
Present Activities: From January 1, 1999 to March 15, 1999, the
Registrant had no wells in the process of drilling.
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, 1998 have
been filed with any federal authority or agency. Estimated total proved
net oil and gas reserves will be filed with the Energy Information
Administration of the Department of Energy (DOE) in April 1999 for reserves
at year-end 1998. The difference between the oil and gas reserves reported
in this Form 10-K and those to be filed with the DOE will not exceed 1%.
Other than the estimates of reserves at December 31, 1997, 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 metal ore production was in 1989 under a lease
arrangement. In 1999, the Registrant entered into a License Agreement with
another company to allow commercial rock production from the patented
claims. Under the terms of this agreement, the Registrant is to receive a
10% of gross selling price royalty on all rock products produced and sold
from the property. The agreement also provides for a minimum royalty of
$250 per month to continue the agreement in effect through its three-year
term ending January 15, 2002. No mining activities are presently being
conducted on this property. Management has no plans to devote significant
financial resources to this property in 1999; however, it continues to
investigate ways to further exploit the property.
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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the fourth quarter of 1998, no matter was submitted to a
vote of security holders of the Company through the solicitation of proxies
or otherwise.
PART II
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
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
1998 1st Quarter $1.92 $2.27
2nd Quarter $1.69 $2.02
3rd Quarter $1.19 $1.48
4th Quarter $ .83 $1.15
As of March 15, 1999, 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.
On January 28, 1999, the NASDAQ Stock Market ("NASDAQ") notified
the Company that it was not in compliance with the $1 minimum bid
requirement, one of several listing requirements of the NASDAQ SmallCap
Market. The Company is in compliance with the other requirements. If the
Company is unable to meet compliance with the $1 minimum bid requirement on
or before April 28, 1999, the Company's common stock could be delisted from
NASDAQ. To avoid delisting of its securities, the Company, in accordance
with NASDAQ procedural guidelines, may request a hearing with NASDAQ before
April 27, 1999, to seek a stay of delisting. The Company's management
believes the Company should be granted a stay but it is unknown at this
time whether NASDAQ would grant it. The Company will also continue to
investigate any other options it might have to meet compliance with the
minimum bid requirement.
ITEM 6. SELECTED FINANCIAL DATA
1998 1997 1996 1995 1994
Operating
Revenue $2,380,651 $4,189,793 $3,806,790 $2,874,001 $2,442,850
Net Income
(Loss) (1,605,218) 766,265 733,726 303,889 40,141
Net Income
(Loss)
Per Share (.39) .19 .18 .08 .01
AT YEAR END:
Total Assets 6,704,724 8,032,328 7,909,965 6,690,285 5,796,354
Long-term
Debt 1,625,004 666,000 998,097 958,330 787,035
Current
Maturities 316,000 457,097 283,200 511,594 385,219
Working
Capital 111,515 18,240 205,463 (171,949) (86,786)
(Deficit)
Stockholders'
Equity 4,052,114 5,691,597 4,873,927 4,114,001 3,798,549
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 1998 to 1997 Revenue and Gross Margin
Oil and gas sales were $1,662,000 in 1998 compared to $3,425,000
in 1997, a decrease of $1,763,000 or 51%. This decrease in revenue was due
to a 41% decrease in average oil prices and an 18% decline in the volume of
oil and gas sold. The 1998 average oil price per barrel was $9.54 compared
to an average of $16.15 in 1997. 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 1998 decreased 38,000 barrels, or 18%, to 175,000 barrels of
oil equivalent (BOE) from 213,000 BOE in 1997. The lower 1998 average oil
price resulted from a collapse in world oil prices that occurred during
1998. The lower 1998 production volumes resulted from the Company
"shutting in" or curtailing production from numerous marginal wells in an
effort to control production costs. As of February 1, 1999, the Company
had shut in a total of approximately 35 operated wells to reduce production
costs.
Oil and gas production costs were $930,000 in 1998 compared to
$1,336,000 in 1997, a decrease of $406,000 or 30%. These lower costs were
due to two primary factors, the efforts to reduce costs by shutting in
marginal wells as discussed above and lower production taxes resulting from
lower oil prices. Production costs expressed on a per equivalent barrel
basis declined $0.94 per BOE or 15% to average $5.33 for 1998 compared to
$6.27 for 1997. The decrease in per barrel costs occurred because total
production expenses declined by a higher percentage than the decline in the
volume of oil and gas sales. Gross margin for 1998 oil and gas operations
before deductions for depletion, a non-cash writedown of oil and gas
properties and selling, general and administrative (SG&A) expenses
decreased to $732,000 or 44% of revenue compared to $2,090,000 or 61% of
revenue for 1997.
Leonardite product sales were $719,000 in 1998 compared to
$764,000 in 1997, a decrease of $46,000 or 6%. This decrease was due to a
4% decrease in tonnage sold in 1998 resulting from weaker demand for the
Company's oil and gas related drilling products during 1998. Production
sold in 1998 was 7,772 tons at an average price of $92.47, compared to
8,094 tons at an average price of $94.44 for 1997.
Cost of leonardite sold was $603,000 in 1998 compared to $598,000
in 1997, an increase of $5,000 or 1%. Production costs per ton were $77.61
and $73.86 for 1998 and 1997, respectively. Costs per ton increased
approximately 5% for 1998 compared to 1997 due in part to the lower
production volumes that spread fixed costs over fewer tons.
Gross margin for 1998 leonardite operations before deductions for
depreciation and selling, general and administrative expenses was $115,000
or 16% of revenue compared to $167,000 or 22% of revenue for 1997. The
decline in 1998 gross margin resulted from the combination of the decline
in leonardite sales and a slight increase in production costs previously
discussed.
Comparison of 1998 to 1997 Consolidated Analysis
Total revenue for 1998 decreased $1,809,000 or 43% to $2,381,000
from $4,190,000 in 1997. This decrease was primarily due to the
substantially lower oil prices that existed during 1998 and, to a lesser
extent, the lower oil production, both previously discussed.
Total operating costs for 1998 increased $843,000 or 26% to
$4,076,000 compared to $3,233,000 in 1997. These increased costs resulted
entirely from a non-cash write-down of oil and gas properties charged to
operating expenses in accordance with Securities and Exchange Commission
(SEC) rules. Without the write-down, operating expenses in all the normal
expense categories, except cost of leonardite sold, declined such that
total operating expenses would have been $2,776,000 for 1998 which was
$457,000 or 14% less than the $3,233,000 for 1997. Normal operating
expenses were lower due to the oil and gas cost cutting measures discussed
above and to general efforts to reduce costs.
Lower 1998 total revenue and higher total operating costs
resulted in an operating loss of $1,696,000 for 1998 compared to operating
income of $957,000 in 1997. Nonoperating expenses increased $24,000 from
$80,000 in 1997 to $105,000 in 1998, yielding a loss before taxes of
$1,800,000 in 1998 compared to a pretax income of $876,000 in 1997.
The income tax benefit in 1998 was $195,000 compared to a tax
expense of $110,000 in 1997. The 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.
The net loss for 1998 was $1,605,000 or $.39 per share compared
to net income of $766,000 or $.19 per share in 1997.
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 was 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.
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 1998, the Company had current assets of $999,000
compared to current liabilities of $888,000 for a current ratio of 1.13 to
1 and working capital of $112,000. This compares to a current ratio of
1.01 to 1 at December 31, 1997, and working capital of $18,000. Cash was
significantly lower at year-end 1998, as a result of the Company using cash
to reduce accounts payable from the prior year's level. Current
liabilities also declined because less of the Company's debt was scheduled
to mature in 1998 and 1999. See Note F to the Financial Statements for
further information. Working capital at year-end 1998 was higher than year-
end 1997 because current liabilities were reduced more than current assets.
This was due to the lower current maturities discussed above and to higher
inventories resulting from the Company holding oil in lease tanks awaiting
higher oil prices.
During the year ended December 31, 1998, the Company generated
cash flows from operating activities of $124,000 which was $2,104,000 less
than the amount generated during 1997. This decrease was essentially due
to substantially lower oil prices that existed in 1998. The Company
anticipates that cash flows from operations and funds available under a
$3,000,000 revolving line of credit will be sufficient to meet its short-
term cash requirements. 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 1998, the Company's investing activities used $1,287,000
of cash which was primarily for additions to property, plant and equipment
related to the drilling and completion of the Oscar Fossum H4 horizontal
well in early 1998 and proved property acquisitions during 1998. The
additions to property and equipment consists of the approximate amounts as
follows: Exploration and development costs of $884,000 that included the
paid portion of costs for drilling and completing the Oscar Fossum H4 in
early 1998, proved property acquisition costs of $236,000 associated with
acquiring interests in thirteen producing wells in two separate
acquisitions, unproved property costs of $38,000 primarily for oil and gas
lease costs.
During 1998, the Company's financing activities consisted of
proceeds from borrowings of $1,275,000 and $457,000 of cash utilized for
regularly scheduled principal payments under long-term debt agreements. In
addition the Company used $96,000 of cash to purchase its own stock on the
open market.
Management estimates that the Company's development costs for
1999 related to the Company's proved developed nonproducing and proved
undeveloped oil and gas properties will be substantially less than the
$1,000,000 or more that they have been in recent years. Planned
expenditures for 1999 consist of delay rentals and other exploration costs
of approximately $100,000. Capital expected to be used for 1999 principal
payments required under existing debt agreements totals $316,000. The
estimated amounts for exploration and development are uncertain because of
the extremely low oil prices that have existed throughout 1998 and the
first quarter of 1999. During March 1999, crude oil prices on the NYMEX
recovered modestly. Dramatic fluctuations in world oil prices can occur as
a result of the market's perception of what major oil producing countries
will do to control oil supplies. The price the Company receives for its
oil production is tied directly to world oil markets, and lower prices
result in reduced cash flow. The Company budgets and estimates its capital
expenditures, but these estimates can change, either upward or downward,
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 future cash flows from
operations, and if necessary, possible forward sales of oil reserves or
additional debt or equity financing.
YEAR 2000 READINESS
The Company expects to complete the review, resolution and
testing of all its internal computer systems prior to December 31, 1999, so
that it is Year 2000 compliant. Essentially all of the Company's office
computer systems are desktop computers, including its complete accounting
system. The maker of the Company's accounting software has represented
that it has run a 2000 compliant version in house for over a year, and the
Company expects to upgrade to that version before August 31, 1999. All
other office desktop systems are either already Year 2000 compliant or will
be upgraded before December 31, 1999. The Company does not expect that the
cost of upgrading any of its computer systems will have a material impact
on the Company's financial position, results of operations or cash flows in
future periods. The Company's oil and gas production operations equipment
and its leonardite processing operations equipment are both not dependent
on any material amount of in house computerized controls or embedded chip
devices and as such are not deemed to be affected by Year 2000 compliance
issues. Both of these operational segments are, however, significantly
dependent on the Year 2000 readiness of their respective customers and on
supplies provided by third parties, particularly for energy in the form of
electricity and natural gas. The Company cannot guarantee that there will
not be material adverse effects to the Company if customers or utilities
and other of the Company's suppliers have difficulties related to Year 2000
readiness. The Company believes the availability of supplies and services
from third parties to be the most significant risk related to the Year 2000
issue.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See "Index to Consolidated Financial Statements and Supplementary
Data" on page 25.
ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
Not applicable.
PART III
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: 46 Director
Thomas F. Neubauer Vice President Since June 1992
Age: 64 of Leonardite
Operations
Cathy Kruse Secretary, Since October 1981;
Age: 44 Treasurer and October 1981 to May
Director 1985 and since June
1990; since June 1996
H. Dennis Hoffelt Director From 1967 through
Age: 58 June 1986; and since
June 1987
Joseph V. Montalban Director Since June 1996
Age: 75
Paul A. Krile Director Since June 1997
Age: 71
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 for 1998, no officer or director failed to file any of the
above forms on a timely basis.
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. 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 1998 $82,596 -0- -0- N/A -0- N/A $4,130
P. 1997 $82,596 25,000 -0- N/A 71,000 N/A $8,747
Vickers 1996 $78,443 -0- -0- N/A -0- N/A $11,766
CEO
In the table above, the column titled "All Other Compensation" is
comprised entirely of profit sharing amounts and the 401(k) Company
matching funds discussed below.
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 Profit Sharing 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 did not make a contribution in 1998.
Contributions for 1997 and 1996 were $21,508 and $60,000, respectively. As
of December 31, 1998, vested amounts in the Profit Sharing Plan for all
officers as a group were approximately $418,500.
Effective July 1, 1997, the Company executed an Adoption
Agreement Nonstandardized Code 401(k) Profit Sharing Plan that includes a
401(k) Plan into the existing Profit Sharing Plan. Eligible employees are
allowed to defer up to 15% of their compensation with the Company matching
up to 5%.
Aggregated Option/SAR Exercises in last Fiscal Year
and FY-End Option/SAR Values
Value of
Number of Unexercised
Unexercised In-the-Money
Options/SARs Options/SARs
Shares at FY-End(#) at FY-End($)
Acquired on Value Exercisable/ Exercisable/
Name Exercise(#) Realized($) Unexercisable Unexercisable
Jeffrey P.
Vickers, CEO -0- -0- 106,000/0 0/0
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 Company 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
Company largely depends, by encouraging such persons to become owners of
the common stock of the Company.
The term of the Plan expires February 17, 2003. 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 Company 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 Company. 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 1998.
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, 1999. 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 14,700-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) 11.4%
$.01 par value
Common Stock, Officers and 1,120,434-Direct and 27.5%
$.01 par value Directors as Indirect
a Group- (a)(b)(c)(d)
(six persons) (e)(f)(g)
(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 14,700 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, 1999.
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) 11.4%
$.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.
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. 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 52.
(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 - 50
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, 1998 and 1997, and
the related consolidated statements of operations, stockholders' equity,
and cash flows for the years ended December 31, 1998, 1997 and 1996. 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, 1998 and 1997, and
the results of its operations and its cash flows for the years ended
December 31, 1998, 1997 and 1996, in conformity with generally accepted
accounting principles.
/s/ Richey, May & Co., P. C.
Englewood, Colorado
March 4, 1999
GEORESOURCES, INC., AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1998 AND 1997
ASSETS
CURRENT ASSETS: 1998 1997
Cash and equivalents $ 40,673 $ 490,385
Trade receivables, net 524,132 521,934
Inventories 403,529 288,264
Prepaid expenses 26,468 31,422
Investments 4,319 25,966
Total current assets 999,121 1,357,971
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, using the
full cost method of accounting:
Properties being amortized 19,139,363 17,997,596
Properties not subject to amortization 141,019 124,672
Leonardite plant and equipment 3,206,217 3,211,825
Other 704,357 702,068
23,190,956 22,036,161
Less accumulated depreciation, depletion,
amortization and impairment (17,635,373) (15,510,109)
Net property, plant and equipment 5,555,583 6,526,052
OTHER ASSETS:
Mortgage loans receivable, related party 103,321 103,321
Other 46,699 44,984
Total other assets 150,020 148,305
TOTAL ASSETS: $ 6,704,724 $ 8,032,328
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 472,345 $ 770,204
Current maturities of long-term debt 316,000 457,097
Accrued expenses 99,261 112,430
Total current liabilities 887,606 1,339,731
LONG-TERM DEBT, less current maturities: 1,625,004 666,000
DEFERRED INCOME TAXES: 140,000 335,000
CONTINGENCIES (NOTE I):
STOCKHOLDERS' EQUITY:
Common stock, par value $.01 per share;
authorized 10,000,000 shares; issued
and outstanding, 4,071,652 and
4,097,214 shares, respectively 40,717 40,972
Additional paid-in capital 846,787 880,797
Retained earnings 3,164,610 4,769,828
Total stockholders' equity 4,052,114 5,691,597
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY: $ 6,704,724 $ 8,032,328
GEORESOURCES, INC., AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1998 1997 1996
OPERATING REVENUE:
Oil and gas sales $ 1,661,977 $ 3,425,395 $ 2,964,939
Leonardite sales 718,674 764,398 841,851
2,380,651 4,189,793 3,806,790
OPERATING COSTS AND EXPENSES:
Oil and gas production 929,560 1,335,605 1,082,324
Cost of leonardite sold 603,208 597,813 667,437
Depreciation, depletion
and amortization 830,871 850,599 674,805
Write-down of oil and
gas properties 1,300,000 -- --
Selling, general and
administrative 412,729 449,161 498,882
4,076,368 3,233,178 2,923,448
Operating income (loss) (1,695,717) 956,615 883,342
OTHER INCOME (EXPENSE):
Interest expense (143,588) (125,007) (113,384)
Interest income 17,231 25,036 18,287
Other income and losses, net 21,856 19,621 31,050
(104,501) (80,350) (64,047)
Income (loss) before
income taxes (1,800,218) 876,265 819,295
INCOME TAX (EXPENSE) BENEFIT: 195,000 (110,000) (85,569)
Net income (loss) $(1,605,218) $ 766,265 $ 733,726
EARNINGS PER SHARE:
Net income (loss),
basic and diluted $ (.39) $ .19 $ .18
Weighted average number
of shares outstanding 4,080,092 4,076,284 4,056,274
Dilutive potential shares -
Stock options -- 63,361 38,686
Adjusted weighted average shares 4,080,092 4,139,645 4,094,960
GEORESOURCES, INC., AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Additional
Common Stock Paid-in Retained
Shares Amount Capital Earnings Total
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
Purchase of
common stock (56,562) (565) (95,351) -- (95,916)
Issuance of common
stock for acquisition
of oil and gas
properties 31,000 310 61,341 -- 61,651
Net income (loss) -- -- -- (1,605,218) (1,605,218)
Balance,
December 31, 1998 4,071,652 $ 40,717 $ 846,787 $3,164,610 $4,052,114
GEORESOURCES, INC., AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1998 1997 1996
CASH FLOWS FROM OPERATING ACTIVITIES;
Net income (loss) $(1,605,218) $ 766,265 $ 733,726
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities:
Depreciation, depletion,
amortization and
valuation allowance 2,130,871 850,599 674,805
Deferred income taxes (benefit) (195,000) 110,000 74,000
Issuance of common stock
as compensation -- -- 26,200
Other 7,192 2,364 2,192
Changes in assets and liabilities:
Decrease (increase) in:
Trade receivables (2,198) 414,111 (345,715)
Inventories (115,265) (36,765) 33,519
Prepaid expenses and other 4,954 (13,221) (741)
Investments 21,647 31,805 (47,652)
Increase (decrease) in:
Accounts payable (109,569) 145,629 (87,604)
Accrued expenses (13,169) (43,034) 87,527
Net cash provided by operating
activities 124,245 2,227,753 1,150,257
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant
and equipment (1,287,321) (2,707,097) (583,128)
Proceeds from sale of property
and equipment -- 357,236 --
Other -- -- (12,756)
Net cash used in investing
activities (1,287,321) (2,349,861) (595,884)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings 1,275,000 425,000 325,000
Principal payments on long-term debt (457,093) (583,200) (513,627)
Proceeds from issuance of common stock -- 20,805 --
Cost to purchase common stock (95,916) -- --
Debt issue costs (8,627) (5,000) (2,936)
Net cash provided by (used in)
financing activities 713,364 (142,395) (191,563)
NET INCREASE (DECREASE) IN CASH
AND EQUIVALENTS: (449,712) (264,503) 362,810
CASH AND EQUIVALENTS, beginning of year: 490,385 754,888 392,078
CASH AND EQUIVALENTS, end of year: $ 40,673 $ 490,385 $ 754,888
GEORESOURCES, INC., AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1998 1997 1996
SUPPLEMENTAL DISCLOSURE OF
CASH FLOW INFORMATION
Cash paid for:
Interest $ 138,791 $ 124,245 $ 114,850
Income taxes 14,573 9,922 1,569
NONCASH INVESTING AND FINANCING ACTIVITIES
During 1998, the Company issued 31,000 shares of common stock valued at
$61,651 as partial consideration of the purchase price of various oil
and gas properties.
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 83% 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 affects 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 $3.86, $3.40 and $3.27 for 1998, 1997 and 1996,
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. During 1998, the selling prices of the Company's oil and
gas products declined significantly, reaching their lowest point of the
year in mid December with only a small increase through December 31,
1998, and some additional increase after year-end. In consideration of
the price increase subsequent to year-end, the Company computed the
"ceiling test" using prices in effect on March 4, 1999. As a result,
the net capitalized costs of the Company's oil and gas properties
exceeded their "estimated present value" based upon the "ceiling"
limitation and consequently, the Company recognized a charge to
operations of $1,300,000 or $0.32 per share. Had the Company determined
the "ceiling" limitation using year-end prices, it would have recognized
an additional charge to operations of approximately $900,000 or $0.22
per share.
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, 1998, consist of the
unevaluated, unimpaired cost of undeveloped oil and gas properties which
were acquired during the following years:
1998 $ 21,168
1997 32,859
1996 16,258
1995 and prior 70,734
Total $ 141,019
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, 1998,
1997 and 1996.
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 adjusted weighted
average number of common shares outstanding. The effect of outstanding
stock options was antidilutive in 1998.
Recently Issued Accounting Standards
In 1998, the FASB issued SFAS No. 133-Accounting for Derivative
Instruments and Hedging Activities. SFAS No. 133 establishes standards
for the accounting and reporting of all derivative instruments at their
fair value as assets or liabilities on the balance sheet. SFAS No. 133
is effective for periods beginning after June 15, 1999 and requires
restatement of information presented for prior periods. The adoption of
SFAS No. 133 will not have a material impact on these financial
statements.
B. INDUSTRY SEGMENTS AND MAJOR CUSTOMER:
Segment information
The Company assesses performance and allocates resources based upon its
products and the nature of its production processes, 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 operating segments and all operations are conducted
within the United States. Certain corporate costs, assets and capital
expenditures that are considered to benefit the entire organization are
not allocated to the Company's operating segments. Interest income,
interest expense and income taxes are also not allocated to operating
segments. There are no significant accounting differences between
internal segment reporting and consolidated external reporting.
Presented below is information concerning the Company's operating
segments for the years ended December 31, 1998, 1997 and 1996:
1998 1997 1996
Revenue:
Oil and gas $ 1,661,977 $ 3,425,395 $ 2,964,939
Leonardite 718,674 764,398 841,851
$ 2,380,651 $ 4,189,793 $ 3,806,790
Operating income (loss):
Oil and gas $(1,279,105) $ 1,365,729 $ 1,330,169
Leonardite (8,975) 33,859 40,737
General corporate activities (407,637) (442,973) (487,564)
$(1,695,717) $ 956,615 $ 883,342
Depreciation and depletion:
Oil and gas $ 711,522 $ 724,061 $ 552,446
Leonardite 101,468 108,903 107,087
General corporate activities 17,881 17,635 15,272
$ 830,871 $ 850,599 $ 674,805
Identifiable assets, net:
Oil and gas $ 4,702,417 $ 5,452,759 $ 5,014,782
Leonardite 1,347,521 1,452,847 1,501,054
General corporate activities 654,786 1,126,722 1,394,129
$ 6,704,724 $ 8,032,328 $ 7,909,965
Capital expenditures incurred:
Oil and gas $ 1,158,211 $ 1,920,470 $ 1,156,842
Leonardite -- 43,498 29,160
General corporate activities 2,289 9,927 21,095
$ 1,160,500 $ 1,973,895 $ 1,207,097
Major Customer
Sales to a major oil and gas customer were 54%, 71% and 65% of total
revenue for the years ended December 31, 1998, 1997 and 1996,
respectively. Accounts receivable from this major customer were 36% and
44% of total accounts receivable at December 31, 1998 and 1997,
respectively.
C. TRADE RECEIVABLES AND INVENTORIES:
Trade receivables at December 31, 1998 and 1997 are comprised of the
following:
1998 1997
Oil and gas purchasers $ 353,607 $ 318,096
Leonardite customers 181,941 215,254
535,548 533,350
Less allowance for
doubtful accounts (11,416) (11,416)
$ 524,132 $ 521,934
As of December 31, 1998 and 1997, inventories by major classes are
comprised of the following:
1998 1997
Crude oil $ 114,464 $ 29,550
Leonardite inventories:
Finished products 108,951 90,302
Raw materials 90,167 85,433
Materials and supplies 89,947 82,979
Total leonardite inventories 289,065 258,714
$ 403,529 $ 288,264
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, 2002. The Company received interest income from these loans
of $8,100 for each of the years ended December 31, 1998, 1997 and 1996.
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
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.
F. LONG-TERM DEBT:
Long-term debt at December 31, 1998 and 1997 consists of the following
loans and a revolving line of credit (RLOC) which are all with one bank:
1998 1997
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
The 1993 Oil & Gas Loan, prime plus 1%
(8.75% total rate at December 31, 1998),
due in monthly installments of $16,000 plus
interest, due September 1999, collateralized
by oil and gas properties 141,000 333,000
The 1995 Oil & Gas Loan, prime plus 1%
(8.75% total rate at December 31, 1998),
due in monthly installments of $14,583 plus
interest, due December 2001, collateralized
by oil and gas properties 525,004 700,000
The 1997 Oil & Gas RLOC, $3,000,000
revolving line of credit, interest payable
monthly at prime plus .75%, (8.5% total
rate at December 31, 1998), expires
January 5, 2005, collateralized by
oil and gas properties 1,275,000 --
Total long-term debt 1,941,004 1,123,097
Less current maturities (316,000) (457,097)
Long-term debt, less current
maturities $ 1,625,004 $ 666,000
Aggregate maturities required on long-term debt at December 31, 1998,
are as follows:
Year Ending December 31:
1999 $ 316,000
2000 175,000
2001 493,754
2002 318,750
2003 318,750
Thereafter 318,750
$ 1,941,004
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; 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,
1998, 1997 and 1996, are as follows:
1998 1997 1996
Current tax (expense) $ -- $ -- $ (11,569)
Deferred tax benefit (expense) 685,000 (369,000) (232,000)
Decrease (increase) in deferred
tax assets valuation allowance (490,000) 259,000 158,000
Income tax (expense) benefit $ 195,000 $ (110,000) $ (85,569)
During 1998, the Company recorded a deferred tax benefit of $685,000.
This resulted from a) the reversal of temporary differences related to
oil and gas properties caused by the $1,300,000 write-down discussed in
Note A, and b) the additional net loss incurred for which there are no
currently refundable taxes. The Company also increased the deferred tax
asset valuation allowance by $490,000 based upon the projection of
utilizing less statutory depletion carryforwards in the future.
During 1997 and 1996, the Company recorded deferred tax expense of
$369,000 and $232,000, respectively. This related primarily to net
income which was not currently taxable due to the deduction of
intangible drilling costs for tax purposes. The Company also decreased
the deferred tax asset valuation allowance by $259,000 and $158,000
during 1997 and 1996, 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, 1998 and 1997, are as follows:
1998 1997
Deferred Tax Assets:
Net operating loss carryforward $ 454,000 $ 390,000
Statutory depletion carryforward 1,252,000 1,113,000
Tax credit carryforwards 55,000 69,000
Other 46,000 47,000
1,807,000 1,619,000
Valuation Allowance:
Beginning of year (492,000) (751,000)
(Increase) decrease (490,000) 259,000
End of year (982,000) (492,000)
Deferred Tax Liabilities:
Accumulated depreciation and
depletion (965,000) (1,462,000)
Net Deferred Tax Liability, long-term $ (140,000) $ (335,000)
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, 1998,
1997 and 1996 is as follows:
1998 1997 1996
Income tax expense (benefit)
at statutory rate (35)% 35% 35%
Change in valuation allowance 27 (30) (20)
Graduated tax rate difference -- -- (13)
State income taxes and other (3) 8 8
(11)% 13% 10%
For income tax purposes, the Company has a statutory depletion carryover
of approximately $3,495,000 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
1999-2000 $ -- $ 31,000
2001 412,000 --
2003 102,000 --
2008 115,000 --
2009 237,000 --
2012 342,000 --
2013 61,000 --
Total $ 1,269,000 $ 31,000
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.
Information with respect to the stock option plan's activity is as
follows:
Shares
Shares Subject to
Available Outstanding
for Options Options
December 31, 1995 205,000 95,000
Grants -- --
Exercises -- --
December 31, 1996 205,000 95,000
Grants (200,000) 200,000
Exercises -- (16,500)
December 31, 1997 5,000 278,500
Grants -- --
Exercises -- --
December 31, 1998 5,000 278,500
Information with respect to the options outstanding and exercisable at
December 31, 1998 and 1997, is as follows:
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 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 1997 net income and earnings per share would
have been reduced to pro forma amounts of $598,065 and $.15,
respectively. The fair value of the 1997 options on the date of grant
is estimated using the Black-Scholes option-pricing model with the
following assumptions:
Expected volatility 39%
Risk free interest rate 5.71%
Expected lives 3.5 years
Expected dividends 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,
1998, 1997 and 1996 were $19,883, $31,930 and $60,000, 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, 1998 and 1997:
1998 1997
Building and improvements $ 163,834 $ 163,834
Accumulated depreciation (63,754) (55,563)
$ 100,080 $ 108,271
The Company leases the remainder of the building to unaffiliated
businesses under cancelable lease agreements. During 1998, 1997 and
1996, the Company received $21,300, $22,200 and $20,938, 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 none and $6,007 at
December 31, 1998 and 1997, respectively. The fair value of those
instruments, based on quoted market prices, was none and ($4,291) at
December 31, 1998 and 1997, 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 $37,849, $30,269 and $102,656 for the years ended
December 31, 1998, 1997 and 1996, respectively.
At December 31, 1998, the Company had no derivative financial
instruments.
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
at December 31, 1997.
L. FOURTH QUARTER ADJUSTMENTS:
As discussed in Note A, the Company recorded a write-down of its oil and
gas properties of $1,300,000 during the fourth quarter of 1998 as a
result of significantly lower oil prices at that time.
During the fourth quarter of 1998, deferred income tax liabilities
decreased $185,000 and income tax benefit increased $185,000 over the
amounts reported at September 30, 1998, due to the write-down discussed
above and the operating loss incurred.
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, 1998, 1997 and
1996:
1998 1997 1996
Proved Properties $19,139,363 $17,997,596 $16,450,061
Unproved properties 141,019 124,672 93,640
Total 19,280,382 18,122,268 16,543,701
Less accumulated depreciation,
depletion, amortization and
impairment (15,081,319) (13,069,796) (12,345,734)
Net capitalized costs $ 4,199,063 $ 5,052,472 $ 4,197,967
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, 1998, 1997 and 1996:
1998 1997 1996
Property acquisition costs:
Proved $ 236,058 $ 28,420 $ 42,611
Unproved 37,756 55,230 21,027
Exploration costs 68,365 75,765 113,145
Development costs 816,032 1,761,055 980,059
$ 1,158,211 $ 1,920,470 $ 1,156,842
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, 1998, 1997 and 1996.
1998 1997 1996
Oil and gas sales $ 1,661,977 $ 3,425,395 $ 2,964,939
Production costs (929,560) (1,335,605) (1,082,324)
Depletion, depreciation
and amortization (711,522) (724,061) (552,446)
20,895 1,365,729 1,330,169
Imputed income tax provision -- -- 10,000
$ 20,895 $ 1,365,729 $ 1,320,169
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. The selling
price of oil was significantly lower at December 31, 1998, than at December
31, 1997 or 1996.
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, 1998, 1997 and 1996:
1998 1997 1996
Oil Gas Oil Gas Oil Gas
(bbl) (mcf) (bbl) (mcf) (bbl) (mcf)
Proved reserves,
beginning of
year 2,387,000 253,000 2,154,000 261,000 2,047,000 266,000
Purchases of
reserves-in-
place 78,000 -- 1,000 -- 21,000 --
Sales of
reserves
-in-place -- -- (25,000) -- -- --
Extensions and
discoveries -- -- 201,000 1,000 12,000 3,000
Improved
recovery 124,000 -- 350,000 -- 156,000 --
Revisions of
previous
estimates (1,130,000) (10,000) (83,000) 1,000 85,000 5,000
Production (173,000) (9,000) (211,000) (10,000) (167,000) (13,000)
Proved reserves,
end of year 1,286,000 234,000 2,387,000 253,000 2,154,000 261,000
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)
1998 1,286,000 234,000
1997 1,640,000 253,000
1996 1,366,000 261,000
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.
As shown on the next page, the future cash inflows as of December 31, 1998,
are significantly lower than in the prior years. This is primarily due to
the low oil price in effect on December 31, 1998. Future cash inflows will
change as oil and gas selling prices either increase or decrease from their
level on December 31, 1998.
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, 1998, 1997 and 1996:
1998 1997 1996
Future cash inflows $11,274,000 $33,521,000 $46,708,000
Future production costs (6,141,000) (13,602,000) (17,419,000)
Future development costs (242,000) (3,495,000) (3,078,000)
Future income tax expense (241,000) (5,318,000) (7,385,000)
Future net cash flows 4,650,000 11,106,000 18,826,000
Less effect of a 10%
discount factor (1,814,000) (4,587,000) (7,380,000)
Standardized measure of
discounted future net
cash flows relating to
proved reserves $ 2,836,000 $ 6,519,000 $11,446,000
The principal sources of change in the standardized measure of discounted
future net cash flows are as follows for the years ended December 31, 1998,
1997 and 1996:
1998 1997 1996
Standardized measure,
beginning of year $ 6,519,000 $11,446,000 $ 6,462,000
Sales of oil and gas produced, net
of production costs (732,000) (2,090,000) (1,985,000)
Net changes in prices and
production costs (8,027,000) (6,612,000) 6,452,000
Purchases of reserves-in-place 134,000 1,000 121,000
Sales of reserves-in-place -- (120,000) --
Extensions, discoveries and other
additions, less related costs 295,000 2,654,000 1,369,000
Revisions of previous quantity
estimates and other (3,054,000) (713,000) 1,209,000
Development costs incurred during
the year and changes in
estimated future development
costs 2,375,000 (1,011,000) (582,000)
Accretion of discount 983,000 1,595,000 850,000
Net change in income taxes 4,343,000 1,369,000 (2,450,000)
Standardized measure, end of year $ 2,836,000 $ 6,519,000 $11,446,000
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 29, 1999
/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- 3/29/99
J. P. Vickers tive officer and principal
financial officer) and Director
/s/ Cathy Kruse Secretary/Treasurer 3/29/99
Cathy Kruse and Director
/s/ Dennis Hoffelt Director 3/29/99
Dennis Hoffelt
Director
Joseph V. Montalban
/s/ Paul A. Krile Director 3/29/99
Paul A. Krile
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
GEORESOURCES, INC.
(Commission File Number: 0-8041)
E X H I B I T I N D E X
FOR
Form 10-K for 1998 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 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 *
10.2 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 *
10.3 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 *
10.4 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 *
10.5 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 *
10.6 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 *
10.7 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 *
10.8 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 *
10.9 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 *
10.10 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 *
10.11 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 *
10.12 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. *
10.13 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. *
10.14 Mining Lease and Agreement dated May 14, 1998, by and
between Roger C. Ryan, Executor for the Estate of
Constance P. Ryan, and as a single man, Susan Ryan,
Joseph W. Ryan and Charlotte Friis as Lessors, and
GeoResources, Inc. as Lessee and all related documents 54
10.15 License Agreement dated January 22, 1999, by and
between GeoResources, Inc. and Silverado Landscape
Materials, and all related documents 57
27 Financial Data Schedule
MINING LEASE AND AGREEMENT
THIS MINING LEASE, (the "Lease"), is made and entered into as of the
14th date of May, 1998, by and between ROGER C. RYAN, Executor for the
Estate of CONSTANCE P. RYAN and as a single man, 17088 SE 58th Street,
Belview, WA 98006, SUSAN RYAN, a single woman, 19 East Santa Ana Avenue,
Fresno, CA 93704, JOSEPH W. RYAN, a/k/a JOSEPH WARREN RYAN, a single man,
2451 Perkins Lane West, Seattle, WA 98199, and CHARLOTTE FRIIS, a single
woman, 4610 92nd Ave. SE, Mercer Island, WA 98040, hereinafter called
"Lessor" (whether one or more) and GeoResources, Inc., a Colorado
corporation, P. O. Box 1505, Williston, ND 58802-1505, hereinafter called
Lessee:
WHEREAS, Lessor is the owner of interests in the following described
land in Williams County, North Dakota:
Township 154 North, Range 100 West
Section 8: SE1/4SW1/4
Section 17: E1/2NW1/4, SW1/4NW1/4
containing 160 acres, more or less
(the "Leased Premises");
AND WHEREAS, it is the desire of both parties hereto that Lessee be
permitted the right to mine coal, lignite, or oxidized lignite (hereinafter
referred to collectively as "Leonardite") from the Leased Premises;
NOW, THEREFORE, in consideration of the premises and of mutual
obligations here-inafter set forth and subject to the terms, conditions,
and covenants hereinafter expressed, the parties hereto agree as follows:
1. Lessor hereby leases to Lessee and Lessee hereby leases from
Lessor the exclusive rights to explore and mine the Leased Premises for
Leonardite, and to use so much of the surface as may be reasonably required
in the exercise of the rights herein granted. Lessee shall have exclusive
authority over its operation and shall be the sole judge of choice of
mining methods to be employed, of selecting the Leonardite to be mined, and
of determining the extent and timing of extraction.
2. Lessee agrees to tender to Lessor on or before the 20th day of
each of the months of January, April, July and October of each and every
year so long as this Lease continues in effect production royalties
according to the following royalty schedule for any Leonardite mined and
removed from the Leased Premises during the three calendar months
immediately preceding the payment date month. Lessee shall be responsible
for weighing all Leonardite removed from the Leased Premises and shall
promptly furnish Lessor copies of all weight receipts if so requested.
Lessor shall have the right to test the accuracy of any scale or weighing
device used by Lessee, and to inspect and examine any books or records of
Lessee relating to the quantity of Leonardite removed from the Leased
Premises, all such books and records to be maintained at Lessee's
Williston, North Dakota office.
ROYALTY SCHEDULE
At least Fifty-Six Cents ($.56) per ton but for each three
calendar month payment period not less than the Producer
Price Index (1982 reference base) for all commodities as
prepared and published by the United States Department of
Labor, Bureau of Labor Statistics, for the middle month of
each three month period divided by 105 and multiplied by
$0.56.
3. This Lease shall remain in force for a term of ten (10) years
from the 14th day of May, 1998, and ending the 13th day of May, 2008,
subject to the condition that on or before the 14th day of May each year
beginning May 14, 1998, Lessee tender to Lessor, as advance rental, the sum
of One Thousand Dollars ($1,000.00), which shall operate as annual minimum
royalty to maintain this lease in force. This rental shall be credited
against the first $1,000.00 of any royalties that accrue thereafter during
that year.
4. Lessee shall have the right to build roads necessary for
transporting the equipment and materials necessary for its operations;
provided, however, that all costs of construction and maintenance of
said roads shall be the full responsibility of Lessee.
5. Lessee agrees to exonerate, hold harmless, and indemnify
Lessor from and against any losses, damages, claims, suits, actions,
judgments and costs which may arise or grow out of any injury to or
death of persons or damage to property arising out of or attributable
to negligence, or acts or omissions, or use by Lessee, or its servants,
employees, guests, or customers on the Leased Premises. Lessee further
agrees to hold harmless, protect, and indemnify Lessor from any claims
arising from our asserted or alleged because of water or other
pollution in any manner attributable to Lessee's operations.
6. Lessor is not liable for any damage to any property of
Lessee kept or stored on the Leased Premises; all of such property kept
or stored on the Leased Premises is so kept or stored at the risk of
Lessee only and Lessee shall hold Lessor harmless from any claims
arising out of damage to same, including subrogation of any claims by
Lessee's insurer, unless the damage was caused by a willful act or the
gross negligence of Lessor.
7. Lessee warrants that its exploring, mining and reclamation
operations shall at all times be in full compliance with all laws,
statutes, ordinances and regulations of federal, state, county, and
municipal governments and agencies, including but not limited to, the
North Dakota Public Service Commission rules and regulations for
reclamation of surface-mined lands.
8. Lessee shall conduct its business in such a manner as to
insure that no lien, attachment or execution shall in any manner be
placed on the Leased Premises, but, if any such lien, attachment or
execution shall be so placed, Lessor may at its option, after giving
Lessee notice and reasonable opportunity to cure, discharge the same
and Lessee shall reimburse Lessor for all costs in connection
therewith, with interest at ten percent (10%).
9. Lessor shall have the right at all reasonable times and at
Lessor's risk and expense to inspect the Leased Premises and Lessee's
operations thereon.
10. Lessee shall pay all severance taxes and all taxes on
personal property, fixtures, and improvements placed on the Leased
Premises by Lessee as such taxes accrue, provided however, that if
Lessee fails to pay such taxes when due, Lessor may at its option pay
the taxes, and Lessee shall reimburse Lessor for any such payment with
interests at ten percent (10%).
11. Lessor is not required to provide any services or perform
any act except as other-wise provided herein, and rent and royalties
must be paid without any claim for diminution or abatement, and the
fact that Lessee's use of the Leased Premises is disturbed from any
cause whatsoever except Lessor's acts shall not in any way suspend,
abate or reduce the rental or royalty payments due except as otherwise
provided in this Lease.
12. If this Lease terminates because of default by the Lessee,
Lessor shall have a lien upon all personal property and improvements
placed on or under the Leased Premises by the Lessee for the amount due
under the Lease, and Lessee shall be prohibited from removing same
until all such amounts have been paid in full.
13. Any notice or demand contemplated by this Lease, other than
rental and royalty payments, shall be deemed given to Lessor five (5)
days after mailed by certified or registered mail, return receipt
requested, addressed to:
Joe Ryan Roger Ryan
2451 Perkins Lane W. 17088 SE 58th St.
Seattle, WA 98199 Belview, WA 98006
and to Lessee at:
GeoResources, Inc.
P. O. Box 1505
Williston, ND 58802-1505
or to such other address as either party may by notice in writing
specify.
14. (a) This Lease shall be governed by the laws of the State
of North Dakota.
(b) Division of this Lease into sections is for convenience
only, and shall not be considered in its interpretation.
(c) This Lease contains the entire agreement of the parties
concerning the Leased Premises and supersedes all prior statements of
agreements whether oral or written.
(d) No waiver of any covenant of this Lease shall be deemed a
waiver of any other covenant herein.
15. It is mutually understood and agreed that Lessee may at
any time surrender and terminate this Lease upon giving Lessor thirty
(30) days notice in writing and paying to Lessor all payments due to
the effective date of such surrender.
16. Each obligation and benefit hereunder shall be binding
upon and inure to the benefit of the respective heirs, executors,
administrators, successors and assigns of the parties, although it is
agreed that no change or division in ownership of the rentals or
royalties shall operate to enlarge the obligations or diminish the
rights of Lessee, and any such change shall not be binding on the
Lessee until after Lessee has been furnished with certified copies of
monuments of title.
17. This instrument may be executed in any number of counter
parts, each of which shall be considered an original for all purposes.
IN WITNESS WHEREOF, the Lessor and Lessee have executed this Lease
this 19th day of June, 1998, to be effective the day and year first above
written.
GEORESOURCES, INC.
/s/ Roger C. Ryan
ROGER C. RYAN
By: /s/ J. P. Vickers /s/ Roger C. Ryan, Executor
J. P. Vickers, President ROGER C. RYAN, Executor of the
Estate of CONSTANCE P. RYAN
/s/ Susan Ryan
ATTEST: SUSAN RYAN
/s/ Joseph W. Ryan
JOSEPH W. RYAN
/s/ Cathy Kruse
Cathy Kruse, Secretary /s/ Charlotte Friis
CHARLOTTE FRIIS
LESSEE LESSOR
LICENSE AGREEMENT
This agreement is made and entered into this 22nd day of January,
1999, by and between GeoResources, Inc. a Colorado Corporation ("Geo")
and Silverado Landscape Materials, an Arizona Limited Liability
Corporation ("SLM").
1. Grant of License. Geo hereby grants to SLM a exclusive license to
enter onto the property known as the Reymert Property located in the
Tonto National Forest in Pinal County, Arizona (the "Property") which is
shown in Exhibit A attached hereto, for the sole purpose of producing
and marketing decorative rock, boulders, rip rap, road base material and
similar commercial rock products. SLM shall be responsible for
providing all production equipment, including but not limited to all
trucks and manpower to produce such materials at its sole cost and
expense.
2. Term. The term of this Agreement shall commence on January 15,
1999, and shall continue in force and effect until January 15, 2002,
unless terminated earlier in accordance with the provisions of Section
10 hereof.
3. Designation of Locations for Production. The precise location or
locations for the production of materials from the Property shall be
determined by mutual agreement between Geo and SLM, taking into account
such factors as the quality of rock materials which can be produced, the
ease of access to such locations, and such other factors as the parties
shall deem relevant. In addition, Geo will provide access to a site or
sites on the Property for the set up and operation of SLM's production
equipment, and the storage of manufactured products and the disposition
of by-products or waste rock. SLM will do all site preparation work
necessary to provide access both to the production and the processing
sites and any other on-site work necessary to facilitate its operations.
4. Royalties. In consideration for the license hereby granted, SLM
will pay to Geo a royalty of Ten Percent (10%) of the gross selling
price before taxes as invoiced for all products produced and sold from
the Property. Such royalties will be paid on or before the 25th day of
each month for the term of this agreement for all material sold by
invoice during each second preceding calendar month. As an example of
this, invoiced sales for January, 1999 would have royalties due March
25th, 1999. In addition if SLM can show GEO documentation, acceptable
to GEO, that payment was never received for a particular invoiced sale
then royalties would not be due on that sale. If royalties for any
calendar month do not equal at least $250.00 then SLM agrees to pay GEO
a monthly minimum royalty of $250.00 to continue this license agreement
in effect. The failure of SLM to pay royalties or minimum royalties
under the terms of this paragraph shall terminate the license agreement
under the terms of paragraph 10
5. License Bonus Payment. As further consideration for the exclusive
license hereby granted SLM agrees to pay GEO an initial license bonus
payment of Twenty Five Hundred Dollars ($2500.00) which GEO and SLM
agree prepays any minimum royalties due for products sold through April
30th 1999, such that only monthly royalties in excess of $250.00 would
be due for calendar months January through April 1999.
6. Conduct of Operations. SLM agrees to conduct all of its operations
in compliance with the regulations of all state and federal governmental
agencies having jurisdiction over the Property. Such agencies include
but are not limited to the United States Forest Service and the Mine
Safety and Health Administration. Any bonds, permits or other
regulatory requirements by governmental agencies will be the provided by
SLM at its sole cost and expense.
7. Liability Insurance. During the term of this Agreement, SLM agrees
to carry comprehensive general liability insurance covering its
operations at the Property with liability in the amount of not less than
One Million Dollars ($1,000,000.00). Such insurance shall name Geo as
an additional insured and shall provide that it may not be cancelled
without at least 30 days advance written notice to Geo.
8. Indemnification. SLM will indemnify, defend and hold Geo harmless
from any loss or liability resulting from its operations on the Property
under this Agreement. Geo shall indemnify, defend and hold SLM harmless
for any loss, cost or injury resulting from any operations by GEO on the
Property.
9. Ownership of Reymert Porperty. GEO agrees that it will not enter
into any agreement to sell the Property to any third party without
giving SLM 60 days advance written notice of such intent.
10. Cancellation. Geo shall be entitled to terminate this Agreement
before January 15th, 2002, upon not less than 90 days advance written
notice to SLM if, in the exercise of its good faith judgment, Geo can
demonstrate that the continued operation by SLM at the Property shall
materially interfere with other more economic activities of Geo on the
Property. In addition, Geo may cancel this Agreement if, at any time,
SLM has failed to comply with all of its obligations hereunder and,
having received written notice of such failure, has not cured such
failure within 30 days after receipt of such notice or if SLM's
operation on the Property should be determined to be in violation of any
applicable law, rule or regulation of any governmental body having
jurisdiction.
SLM may cancel this Agreement upon not less than 30 days advance
written notice to GEO if they are unable to locate commercially
marketable material at a mutually acceptable location on the
Property or if SLM's operation on the Property should be determined
to be in violation of any applicable law, rule or regulation of any
governmental body having jurisdiction.
11. Notices. Various provisions of this agreement provide for delivery
of notices or other communications from one party to the other. Any
such notices shall be given in writing and may be delivered in person or
by deposit into the United States mails, by delivery by FAX or by any
overnight courier. Notices delivered in person, by deposit into the
United States mail or by overnight courier shall be effective when
received. Notices delivered by FAX shall be effective when sent but any
such notices shall be followed by delivery of a signed original notice.
Any such notices shall be sent to the following addresses:
Silverado Landscaping Material
6504 East Orion Street
Mesa, AZ 85215
Attn: Steve Young, President
FAX: (602) 654-2704
GeoResources, Inc.
P. O. Box 1505
1407 W. Dakota Parkway, Ste. 1B
Williston, ND 58801
Attn: J. P. Vickers, President
Fax: (701) 572-0277
13. Taxes. SLM shall be responsible for the payment of any severance,
mining or sales taxes due to the State of Arizona on account of the
operations hereunder. Geo shall be responsible for the payment of
all property taxes payable on its Property.
14. Choice of Laws. This Agreement shall be deemed to have been made
in the State of Arizona and shall be subject to the jurisdiction of
Arizona courts. In the event of any litigation between the parties
with respect to the Agreement, the prevailing party shall be entitled
to recover such attorneys' fees and costs as the court may award.
IN WITNESS WHEREOF this Agreement is made as of the date first
above written.
SILVERADO LANDSCAPE MATERIAL
an Arizona Limited Liability Corporation
By /s/ Randy Parsons
Randy Parsons
Vice President
GeoResources, Inc.
a Colorado Corporation
By /s/ J. P. Vickers
J. P. Vickers
President
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