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, 1999.
_____ 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 15, 2000, was
approximately $5,937,000 (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 15,2000: 3,990,352
________________________________________
Documents Incorporated By Reference - None
PART I.
ITEM 1. BUSINESS
General Development of Business
GeoResources, Inc. 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. We were
incorporated under Colorado law in 1958 and were originally engaged in
uranium mining. We built our first leonardite processing plant in 1964 in
Williston, North Dakota, and began participating in oil and gas exploration
and production in 1969. In 1982, we completed construction of a larger
leonardite processing plant in Williston that is in use today. Financial
information about our two operating 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 of
these words or comparable terminology. In addition, all statements other
than statements of historical facts that address activities, events or
developments that we expect, believe or anticipate will or may occur in the
future, and other such matters, are forward-looking statements.
Our future results may vary materially from those anticipated by
management and may be affected by various trends and factors which are
beyond our control. These risks include the competitive environment in
which we operate; 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 in this report.
Oil and Gas Exploration, Development and Production
Our oil and gas exploration and production efforts are
concentrated on oil properties in the North Dakota and Montana portions of
the Williston Basin. We typically generate prospects for our own
exploitation, but when a prospect is believed to have substantial risk or
cost, we 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 us in a cost-sharing arrangement varies widely and depends upon
many factors, including the exploratory costs and the risks involved.
In addition to originating our own prospects, we occasionally
participate in exploratory and development prospects originated by other
individuals and companies. We also evaluate interests in various proved
properties to acquire for further operation and/or development.
Where possible, we supervise drilling and production activities
on new prospects and properties acquired. We do not own or have any plans
to acquire any rotary drilling equipment. Thus, we use independent
drilling contractors for the drilling of wells of which we are the
operator. Therefore, our drilling activities can be subject to delays
caused by shortages of drilling equipment or other factors beyond our
control, including inclement weather.
As of December 31, 1999, we had developed oil and gas leases
covering approximately 13,765 net acres in Montana and North Dakota, and
during 1999 sold an average 503 net equivalent barrels of oil per day from
134 gross (104 net) productive wells located primarily in North Dakota.
We sell our crude oil to purchasers with facilities located near
our wells. Our gas reserves are also contracted to purchasers in the area
near our wells.
Mining and Manufacturing of Leonardite Products
We operate 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 powdered specialty products which are
used primarily in 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 us for use in
metal working foundries and in agricultural applications.
In 1999, our 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. We have no significant supply contracts with individual
customers.
Status of Products, Services or Industry Segments in Development
We own 84% of the voting 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
in the State of Washington. Activities in 1999 consisted of a small amount
of geological field work in an effort to further define the prospect. We
do not expect to devote any substantial resources to this project in 2000.
In addition to our two principal business segments, we own a
nonproducing silver property in Arizona. (See Item 2.) We also own a
minor amount of geothermal and other mineral rights in Oregon. We do not
expect to devote any substantial resources to hard mineral or geothermal
exploration or development in 2000.
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 our current undeveloped acreage is
sufficient to meet our presently foreseeable oil and gas leasehold needs.
Maintaining sufficient leasehold mineral interests for leonardite mining is
also a continuing need for our mining and manufacturing of leonardite
products. Management believes the leonardite held under current leases is
sufficient to maintain our present output for many years. (See Item 2.)
Major Customers
In 1999, we sold our crude oil to 19 purchasers. Koch Petroleum
Group, L.P. was the major customer, accounting for approximately 74% of our
oil and gas revenue in 1999 or approximately 60% of our total operating
revenue. Management believes there are other crude oil purchasers to whom
we would be able to sell our oil if we lost any of our current customers.
In 1999, we sold leonardite products to 40 customers. The
largest customer in 1999 for leonardite products made purchases totaling
31% of our mining and manufacturing revenue or approximately 6% of our
total operating revenue.
Backlog Orders, Research and Development
We do 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, we enter into
short-term contracts to deliver quantities of oil or gas; however, no
significant backlog exists. Our 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. We have not spent
any material time or funds on research and development and do 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 us and they may, therefore, be able to pay more for desirable properties
or to find more potentially productive prospects. However, we believe we
have the ability to obtain leasehold interests which will be sufficient to
meet our 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.
Our leonardite 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 our operations are generally subject to federal, state or
local environmental regulations. Our oil and gas business segment is
affected particularly by environmental regulations regarding the disposal
of produced oilfield brines and other oil-related wastes, and to Spill
Control and Countermeasure Plan (SPCC) rules adopted by the Environmental
Protection Agency (EPA) for all oil producing well and treating facilities.
Many of our oil producing properties, particularly those acquired from
other operators, require SPCC plans to be updated to meet current EPA
rules. We began reviewing and updating those plans in 1999 and expect to
complete SPCC plans on all our properties in 2000. Costs to complete
updates for 2000 are estimated to be $50,000.
Our leonardite mining and processing segment is also subject to
numerous state and federal environmental regulations, particularly those
concerned with air contaminant emission levels of our processing plant and
mine permit and reclamation regulations pertaining to surface mining at our
leonardite mine. We believe that maintenance of acceptable air contaminant
emission levels at our 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 air
quality control equipment are not known at this time.
Foreign Operations and Export Sales
We have no production facilities or operations in foreign
countries and have no direct export sales. Some of our leonardite products
are sold to distributors in the United States who in turn export these
products.
Employees
As of March 15, 2000, we had 13 full-time employees.
ITEM 2. PROPERTIES
Our properties consist of four main categories: Office, oil and
gas, leonardite plant and mine, and a nonproducing silver property.
Certain of these properties are mortgaged to our bank. See Note E to the
Financial Statements for further information.
Office
We own a 17,500 square foot office building which is located on a
one-acre lot in Williston, North Dakota. We use about 6,000 square feet of
the building and rent the remainder to unaffiliated businesses.
Oil and Gas Properties
We own developed oil and gas leases totaling 18,419 gross (13,765
net) acres as of December 31, 1999, plus associated production equipment.
We also own a number of undeveloped oil and gas leases. The acreage and
other additional information concerning our 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 of our oil and gas reserves are located in
the United States. Information concerning the estimated net quantities of
all of our proved reserves and the standardized measure of future net cash
flows from the reserves is presented as unaudited supplementary information
following the Financial Statements in Item 14. The estimates are based
upon the report of Broschat Engineering and Management Services, an
independent petroleum engineering firm in Williston, North Dakota. We have
no long-term supply or similar agreements with foreign governments or
authorities, and we do 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 by us 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**
1999 182,356 8,042 183,696 $ 14.70 $ 1.10 $ 6.61
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
_________________________
*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, 1999, our
total gross and net productive wells were as follows:
Productive Wells*
Oil Gas
Gross Wells Net Wells Gross Wells Net Wells
110 80.04 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 we own in gross wells. Productive
wells are producing wells plus shut-in wells we deem capable of production.
Gross and Net Developed and Undeveloped Acres - As of December 31,
1999, we 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 17,137 17,179 26,137 24,816
North Dakota 9,419 6,128 30,019 10,976 39,438 17,104
Washington 0 0 3,988 3,754 3,988 3,754
ALL STATES 18,419 13,765 51,144 31,909 69,563 45,674
________________________
*Gross acres are those acres in which a working interest is owned. The
number of net acres represents the sum of fractional working interests we
own 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 us was as set forth below.
Although we did not drill any productive or dry wells in 1999, we drilled
1.98 net service wells in order to attempt to increase production in a
waterflood of an existing field.
Net Exploratory Net Development Total Net Productive
Year Wells Drilled Wells Drilled or Dry Wells Drilled
Productive Dry Productive Dry
1999 0.00 0.00 0.00 0.00 0.00
1998 0.00 0.00 0.00 0.00 0.00
1997 0.00 0.02 1.67 0.00 1.69
Present Activities - From January 1, 2000, to March 15, 2000, we
had no wells in the process of drilling.
Supply Contracts or Agreements - We are 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, 1999, have
been filed by us with any federal authority or agency. Estimates of our
total proved net oil and gas reserves were 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 filed with the DOE did not
exceed 1%. Other than the estimates of reserves at December 31, 1998,
filed with the Securities and Exchange Commission, we did not file reserve
reports with any other federal agencies within the past 12 months.
Leonardite Plant and Mine
The site of our leonardite plant covers about nine acres located
one mile east of Williston in Williams County, North Dakota. We own this
site and an additional 20 acres of undeveloped property. The plant has
approximately 11,500 square feet of floor area consisting of warehousing
and processing space. Within the plant 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
1999 7,736 $ 84.26
1998 7,772 $ 92.47
1997 8,094 $ 94.44
Our 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 our 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, we 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. We believe that the
leonardite contained in the 240-acre LMU is sufficient to supply our
plant's raw material requirements for many years and that before these
reserves were to be exhausted, we would be able to acquire other fee or
federal coal leases in the same area.
Silver Property
We own 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, we entered into a license agreement with another company to allow
commercial rock production from the patented claims. Under the terms of
this agreement, we will 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 metal
ore mining activities are presently being conducted on this property.
Management has no plans to devote significant financial resources to this
property in 2000; however, it continues to investigate other ways to
further exploit the property.
ITEM 3. LEGAL PROCEEDINGS
On May 12, 1989, we 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
us into modifying the contract. The defendants answered the complaint on
June 1, 1989. Afterwards, no further materials were filed with the court,
but we believed that the case remained pending. We 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, we
contacted the court in September 1996 and were informed by the court that
the case had been dismissed in 1991. On January 15, 1997, we refiled our
action against MDU Resources Group, Inc. Management cannot predict the
outcome of this action, although we intend to pursue its available
remedies.
Other than the foregoing legal proceeding, we are not a party,
nor are any of our properties subject, to any pending material legal
proceedings. We know of no legal proceedings contemplated or threatened
against us.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the fourth quarter of 1999, no matter was submitted to a
vote of our security holders through the solicitation of proxies or
otherwise.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Our 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 our 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
1999 1st Quarter $ .56 $ .83
2nd Quarter $ .85 $ 1.15
3rd Quarter $ 1.04 $ 1.25
4th Quarter $ 1.11 $ 1.43
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, 2000, there were approximately 1,300 holders of
record of our Common Stock. We believe that there are also approximately
750 additional beneficial owners of Common Stock held in "street name".
We have never declared or paid a cash dividend on our Common
Stock nor do we anticipate that dividends will be paid in the near future.
Further, certain of our financing agreements restrict the payment of cash
dividends. See Note E to the Financial Statements for further information.
ITEM 6. SELECTED FINANCIAL DATA
1999 1998 1997 1996 1995
Operating
Revenue $3,340,489 $2,380,651 $4,189,793 $3,806,790 $2,874,001
Net Income
(Loss) 481,552 (1,605,218) 766,265 733,726 303,889
Net Income
(Loss)
Per Share .12 (.39) .19 .18 .08
AT YEAR END:
Total Assets 7,328,840 6,704,724 8,032,328 7,909,965 6,690,285
Long-term
Debt 1,610,008 1,625,004 666,000 998,097 958,330
Current
Maturities 175,000 316,000 457,097 283,200 511,594
Working
Capital 638,549 111,515 18,240 205,463 (171,949)
(Deficit)
Stockholders'
Equity 4,462,475 4,052,114 5,691,597 4,873,927 4,114,001
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
INTRODUCTION
We operate through two primary segments: 1) oil and gas
exploration and production; and 2) leonardite mining and processing. Our
major leonardite products are oil and gas drilling mud additives. Each of
our segments is discussed below.
BUSINESS ENVIRONMENT AND RISK FACTORS
This discussion and analysis of financial condition and results
of operations, and other sections of this report, contain forward-looking
statements within the meaning of the Private Securities Litigation Reform
Act of 1995, that are based on management's beliefs, assumptions, current
expectations, estimates and projections about the oil, gas and leonardite
industry, the economy and about us. Words such as "may," "will," "expect,"
"anticipate," "estimate" or "continue," or comparable words are intended to
identify forward-looking statements. These statements are not guarantees
of future performance and involve risks, uncertainties and assumptions that
are difficult to predict with regard to timing, extent, likelihood and
degree of occurrence. Therefore, our actual results and outcomes may
materially differ from what may be expressed or forecasted in our forward-
looking statements. Furthermore, we undertake no obligation to update,
amend or clarify forward-looking statements; whether as a result of new
information, future events or otherwise.
Important factors that could cause actual results to differ
materially from the forward-looking statements include, but are not limited
to, changes in production volumes; worldwide supply and demand which affect
commodity prices for oil; the timing and extent of our success in
discovering, acquiring, developing and producing oil, natural gas and
leonardite reserves; risks inherent in the drilling and operation of oil
and natural gas wells and the mining and processing of leonardite products;
future production and development costs; the effect of existing and future
laws, governmental regulations and the political and economic climate of
the United States; and conditions in the capital markets.
RESULTS OF OPERATIONS
Comparison of 1999 to 1998 Revenue and Gross Margin
Oil and gas sales were $2,689,000 in 1999 compared to $1,662,000
in 1998, an increase of $1,027,000 or 62%. This increase in revenue was
due to a 54% advance in average oil prices and a 5% increase in the volume
of oil and gas sold. The 1999 average oil price per barrel was $14.70
compared to an average of $9.54 in 1998. We periodically use 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 J
to the Financial Statements for further information. The volume of oil and
gas sold in 1999 increased 9,000 barrels of oil equivalent (BOE) or 5% to
184,000 BOE from 175,000 BOE in 1998. The higher 1999 average oil price
resulted from a rebound in world oil prices that occurred during the last
half of 1999. The higher 1999 production volumes sold resulted about
equally from three primary factors: (i) returning shut-in wells to
production, (ii) production contributed by wells we acquired in 1998, and
(iii) production held over in lease tanks as inventory at year-end 1998 and
not sold until 1999. These three factors were enough to offset the normal
production decline of all our wells resulting in an increase in the volumes
sold even though we did not add any production from new wells during 1999.
During a large part of 1998, we had shut in approximately 20 operated wells
to reduce production costs; however, by July 1, 1999, these wells were
returned to production as oil price advances made them economic to produce
again.
Oil and gas production costs were $1,214,000 in 1999 compared to
$930,000 in 1998, an increase of $284,000 or 31%. These higher costs were
due to three primary factors: (i) additional production costs of $78,000
that were recognized in 1999 as costs associated with oil sold from
inventory, (ii) higher state severance taxes that were directly related to
higher oil revenue and (iii) generally higher costs associated with
producing more wells which had been shut in during 1998 and modest start-up
costs related to those wells. Production costs expressed on a per
equivalent barrel basis increased $1.28 per BOE or 24% to average $6.61 for
1999 compared to $5.33 for 1998. The increase in per barrel costs occurred
because we were able to produce more of our marginal (higher cost per
barrel) wells in the oil price environment existing in 1999 than in 1998.
The 1998 cost per barrel was actually an unusually low number and the costs
for 1999 represented a return to a more historical normal range. Gross
margin for 1999 oil and gas operations before deductions for depletion, a
non-cash writedown of oil and gas properties in 1998 and selling, general
and administrative (SG&A) expenses, increased to $1,474,000 or 55% of
revenue compared to $732,000 or 44% of revenue for 1998.
Leonardite product sales were $652,000 in 1999 compared to
$719,000 in 1998, a decrease of $67,000 or 9%. This decrease was entirely
due to a 9% decrease in average price per ton for leonardite sold in 1999
resulting from less demand for our specialty products, which have higher
selling prices. Production sold in 1999 was 7,736 tons at an average price
of $84.26 compared to 7,772 tons at an average price of $92.47 for 1998.
Cost of leonardite sold was $563,000 in 1999 compared to $603,000
in 1998, a decrease of $40,000 or 7%. Average production costs per ton
were $72.79 and $77.61 for 1999 and 1998, respectively. Costs per ton
decreased approximately 6% for 1999 compared to 1998 due again to the lower
sales of specialty products that also have higher processing costs.
Gross margin for 1999 leonardite operations before deductions for
depreciation and selling, general and administrative expenses was $89,000
or 14% of revenue compared to $115,000 or 16% of revenue for 1998. The
modest decline in 1999 gross margin also resulted from the lower specialty
product sales discussed above.
Comparison of 1999 to 1998 Consolidated Analysis
Total revenue for 1999 increased $960,000 or 40% to $3,340,000
from $2,381,000 in 1998. This increase was primarily due to the
substantially higher oil prices that existed during 1999 compared to 1998,
and also due somewhat to modestly higher volumes of oil sold in 1999.
Total operating costs for 1999 decreased $1,356,000 or 33% to
$2,720,000 compared to $4,076,000 in 1998. This decrease in total costs
resulted entirely from an atypical non-cash charge to operating expenses in
1998 due to a write-down of oil and gas properties as prescribed by the
Securities and Exchange Commission rules. Without the write-down,
operating expenses in all the normal expense categories, totaled $2,720,000
for 1999 compared to $2,776,000 for 1998. Oil and gas production costs
were higher and cost of leonardite lower for the reasons previously
discussed. Depreciation, depletion and amortization expenses were lower
due to the 1998 write-down that reduced our full cost pool which in turn
reduced the amount to be depleted in 1999 and future years. Selling,
general and administrative costs were lower due to salary reductions and
other cost cutting measures, implemented in 1998 and continued through the
third quarter 1999, in order to control costs in the face of low oil
prices.
Higher 1999 total revenue and lower total operating costs
resulted in an operating income of $620,000 for 1999 compared to operating
loss of $1,696,000 in 1998. Nonoperating expenses increased $8,000, from
$105,000 in 1998 to $113,000 in 1999, primarily due to higher interest
expense, although some of this was offset by interest income on higher cash
balances. This yielded an income before taxes of $508,000 in 1999
compared to a pretax loss of $1,800,000 in 1998.
Income tax expense in 1999 was $26,000 compared to a tax benefit
of $195,000 in 1998. The amount for each year is primarily reflective of
changes in our deferred-tax asset valuation allowance under the provisions
of SFAS No. 109. The change in the valuation allowance is based upon
projections of the future utilization of statutory depletion carryforwards.
See Notes A and F to the Financial Statements for further information.
As a result of all the factors discussed above net income for
1999 was $482,000 or $.12 per share compared to a net loss of $1,605,000 or
$.39 per share in 1998.
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. We periodically used 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 J 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 our "shutting in" or
curtailing production from numerous marginal wells in an effort to control
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 (i) the efforts to reduce costs by shutting in marginal wells as
discussed above and (ii) 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 our
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
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 our 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 F 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.
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 1999, we had current assets of $1,729,000
compared to current liabilities of $1,090,000 for a current ratio of 1.59
to 1 and working capital of $639,000. This compares to a current ratio of
1.13 to 1 at December 31, 1998, and working capital of $112,000. Cash was
significantly higher at year-end 1999. Working capital at year-end 1999
was higher than year-end 1998, because of increased cash flows from
operations caused by higher oil prices.
During the year ended December 31, 1999, we generated cash flows
from operating activities of $1,085,000 which was $960,000 more than the
amount generated during 1998. This increase was essentially due to
substantially higher cash flow which was a result of the oil prices that
existed in 1999. We anticipate that cash flows from operations and funds
available under our $3,000,000 revolving line of credit will be sufficient
to meet our short-term cash requirements. The line of credit, which had an
available balance of $1,565,000 at December 31, 1999, allows borrowings
until January 5, 2001, with repayment of any amounts borrowed to begin by
that date. We can select a repayment schedule of up to a maximum of 48
months.
During 1999, our investing activities used $475,000 of cash which
was primarily for additions to property, plant and equipment related to the
drilling and completion of two service wells in our South Starbuck Madison
Unit in Bottineau County, North Dakota. The additions to property and
equipment consists of the approximate amounts as follows: Exploration and
development costs of $503,000 included the paid portion of costs for
drilling and completing the South Starbuck Madison Unit, proved property
acquisition costs of $20,000 and unproved property costs of $21,000.
During 1999, our financing activities consisted of proceeds from
borrowings of $160,000 and $316,000 of cash utilized for regularly
scheduled principal payments under long-term debt agreements. In addition
we used $71,000 of cash to purchase our Common Stock on the open market.
We estimate that our development costs for 2000 relating to our
proved developed nonproducing and proved undeveloped oil and gas properties
will be less than $1,000,000. Planned expenditures for 2000 consist of
delay rentals and other exploration costs of approximately $100,000.
Capital expected to be used for 2000 principal payments required under
existing debt agreements is $175,000.
We expect to continue to evaluate possible future purchases of
additional producing oil and gas properties and the further development of
our properties. We believe our 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.
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 of
our directors and executive officers:
Position(s) with Period of Service as
Name and Age the Company a Director or Officer
Jeffrey P. Vickers President and Since 1982
Age: 47 Director
Thomas F. Neubauer Vice President Since June 1992
Age: 65 of Leonardite
Operations
Cathy Kruse Secretary, Since October 1981;
Age: 45 Treasurer and October 1981 to May
Director 1985 and since June 1990;
since June 1996
H. Dennis Hoffelt Director From 1967 through June
Age: 59 1986; and since June 1987
Paul A. Krile Director Since June 1997
Age: 72
Duane Ashley Director Since June 1999
Age: 52
All of the directors' terms expire at the next annual meeting of
shareholders or when their successors have been elected and qualified. Our
executive officers serve at the discretion of the Board of Directors. The
Board of Directors has an audit committee consisting of Jeffrey P. Vickers,
H. Dennis Hoffelt and Paul A. Krile.
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 us as our 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 our President on
January 1, 1983. In June 1982, Mr. Vickers became a director.
Thomas F. Neubauer is Vice President of Leonardite Operations
and our plant manager. Mr. Neubauer has been employed by us since July
1965.
Cathy Kruse is our Secretary, Treasurer and business office
manager. 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 us in May 1981. In June 1996, Ms. Kruse became a director.
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 one of our directors from 1967 through June of
1986 and was elected as a director again in 1987.
Paul A. Krile has been one of our directors 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.
Duane Ashley has been one of our directors since June 1999. He
has been a Senior Salesman for GRACO Fishing and Rental Tools, Inc. since
January 1999, and for Weatherford Enteerra, Inc. for over five years prior
to that.
Cathy Kruse, our Secretary and Treasurer, 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 us for 1999, 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 our Chief Executive Officer for each of the past three years. We
do not have an employment contract with any of our executive officers.
None of our employees 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 1999 $76,307 -0- -0- N/A -0- N/A $1,820
P. 1998 $82,596 -0- -0- N/A -0- N/A $4,130
Vickers, 1997 $82,596 25,000 -0- N/A 71,000 N/A $8,747
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 we achieve net income in a fiscal year, our Board of Directors
may determine to contribute an amount based on our 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. We made total contributions to the plan, matching
and discretionary, for the years ended December 31, 1999, 1998 and 1997 of
$44,989, $19,883, and $31,930, respectively. As of December 31, 1999,
vested amounts in the Profit Sharing Plan for all officers as a group were
approximately $440,000.
Effective July 1, 1997, we executed an Adoption Agreement
Nonstandardized Code 401(k) Profit Sharing Plan that incorporated a 401(k)
Plan into the existing Profit Sharing Plan. Eligible employees are allowed
to defer up to 15% of their compensation and we match up to 5%.
Aggregated Option/SAR Exercises in last Fiscal Year
and FY-End Option/SAR Values
Value of
Number of Unexercised
Unexercised In-the-Money
Options/SARs Options/SARs
Shares at FY-End(#) at FY-End($)
Acquired on Value Exercisable/ Exercisable/
Name Exercise(#) Realized($) Unexercisable Unexercisable
Jeffrey P.
Vickers, CEO -0- -0- 106,000/0 0/0
At our 1993 Annual Meeting of Shareholders, a 1993 Employees'
Incentive Stock Option Plan (the "Plan") was approved by shareholders. The
purpose of the Plan is to enable us to attract persons of training,
experience and ability to continue as employees and to furnish additional
incentive to them, upon whose initiative and efforts the successful conduct
and development of the business largely depends, by encouraging them to
become owners of our Common Stock.
The term of the Plan expires on February 17, 2003. If within the
duration of an option, there is a corporate merger consolidation,
acquisition of assets or other reorganization; and if this transaction
affects the optioned stock, the optionee will 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 the transaction
and the optionee had been a stockholder with respect to such shares.
The Plan is administered by our 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 will 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. 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
Our officers, 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
service in 1999.
ITEM 12. SECURITES OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the number of shares of our Common
Stock beneficially owned by each of our officers and directors and by all
directors and officers as a group, as of March 15, 2000. 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 366,934-Direct and 9.2%
$.01 par value Indirect(a)
Common Stock, Paul A. Krile 211,500-Direct(b) 5.3%
$.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 41,000-Direct and 1.0%
$.01 par value Indirect(f)
Common Stock, Duane Ashley 0-Direct and (c)
$.01 par value Indirect
Common Stock, Officers and 654,634-Direct and 16.4%
$.01 par value Directors as Indirect
a Group- (a)(b)(c)(d)(e)(f)
(six persons)
_______________________
(a) Includes 139,634 shares owned directly by Mr. Vickers, 2,500 in a self-
directed individual retirement account, 72,000 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 20,000 shares held by him as custodian for
his two minor children. Also included are 106,000 shares which may be
purchased by Mr. Vickers under presently exercisable stock options
granted pursuant to our 1993 Employees' Incentive Stock Option Plan.
(b) Mr. Krile has sole voting and investment powers over these shares.
(c) Less than 1%.
(d) Included are 14,500 shares which may be purchased by Ms. Kruse under
presently exercisable stock options granted pursuant to our 1993
Employees' Incentive Stock Option Plan.
(e) Included are 9,500 shares which may be purchased by Mr. Neubauer under
presently exercisable stock options granted pursuant to our 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 29,500
shares.
The following table sets forth information concerning persons
known to us to be the beneficial owners of more than 5% of our outstanding
Common Stock as of March 15, 2000.
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) 11.6%
$.01 par value Montalban Oil & Gas
Operations, Inc.
Box 200
Cut Bank, MT 59247
Common Stock, Jeffrey P. Vickers 366,934-Direct and 9.2%
$.01 par value 1814 14th Ave. W. Indirect(b)
Williston, ND 58801
Common Stock, Paul A. Krile 211,500-Direct(c) 5.3%
$.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.
(c) See footnote (b) of the immediately preceding table.
We are not aware of any arrangements which could, at a subsequent
date, result in a change in control.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
There are no transactions or series of similar transactions since
the beginning of our last fiscal year or any currently proposed transaction
or series of similar transactions to which we were or are 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, 1999 and 1998, and
the related consolidated statements of operations, stockholders' equity,
and cash flows for the years ended December 31, 1999, 1998 and 1997. 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, 1999 and 1998, and
the results of its operations and its cash flows for the years ended
December 31, 1999, 1998 and 1997, in conformity with generally accepted
accounting principles.
/s/ Richey, May & Co., P. C.
Englewood, Colorado
February 26, 2000
GEORESOURCES, INC., AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1999 AND 1998
ASSETS
CURRENT ASSETS: 1999 1998
Cash and equivalents $ 423,361 $ 40,673
Trade receivables, net 991,153 524,132
Inventories 297,029 403,529
Prepaid expenses 17,257 26,468
Investments 106 4,319
Total current assets 1,728,906 999,121
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, using the full
cost method of accounting:
Properties being amortized 19,664,222 19,139,363
Properties not subject to amortization 143,413 141,019
Leonardite plant and equipment 3,206,217 3,206,217
Other 709,443 704,357
23,723,295 23,190,956
Less accumulated depreciation, depletion,
amortization and impairment (18,271,169) (17,635,373)
Net property, plant and equipment 5,452,126 5,555,583
OTHER ASSETS:
Mortgage loans receivable, related party 103,321 103,321
Other 44,487 46,699
Total other assets 147,808 150,020
TOTAL ASSETS $ 7,328,840 $ 6,704,724
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 747,557 $ 472,345
Current maturities of long-term debt 175,000 316,000
Accrued expenses 167,800 99,261
Total current liabilities 1,090,357 887,606
LONG-TERM DEBT, less current maturities 1,610,008 1,625,004
DEFERRED INCOME TAXES 166,000 140,000
Total liabilities 2,866,365 2,652,610
CONTINGENCIES (NOTE H)
STOCKHOLDERS' EQUITY:
Common stock, par value $.01 per share;
authorized 10,000,000 shares;
issued and outstanding, 4,005,352
and 4,071,652 shares, respectively 40,054 40,717
Additional paid-in capital 776,259 846,787
Retained earnings 3,646,162 3,164,610
Total stockholders' equity 4,462,475 4,052,114
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 7,328,840 $ 6,704,724
The accompanying notes are an integral part of these
consolidated financial statements
GEORESOURCES, INC., AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
1999 1998 1997
OPERATING REVENUE:
Oil and gas sales $ 2,688,642 $ 1,661,977 $ 3,425,395
Leonardite sales 651,847 718,674 764,398
3,340,489 2,380,651 4,189,793
OPERATING COSTS AND EXPENSES:
Oil and gas production 1,214,169 929,560 1,335,605
Cost of leonardite sold 563,081 603,208 597,813
Depreciation, depletion
and amortization 635,797 830,871 850,599
Write-down of oil and gas properties -- 1,300,000 --
Selling, general and administrative 307,336 412,729 449,161
2,720,383 4,076,368 3,233,178
Operating income (loss) 620,106 (1,695,717) 956,615
OTHER INCOME (EXPENSE):
Interest expense (165,395) (143,588) (125,007)
Interest income 27,591 17,231 25,036
Other income and losses, net 25,250 21,856 19,621
(112,554) (104,501) (80,350)
Income (loss) before income taxes 507,552 (1,800,218) 876,265
INCOME TAX (EXPENSE) BENEFIT (26,000) 195,000 (110,000)
Net income (loss) $ 481,552 $ (1,605,218) $ 766,265
EARNINGS PER SHARE:
Net income (loss),
basic and diluted $ .12 $ (.39) $ .19
Weighted average number of shares
outstanding 4,040,425 4,080,092 4,076,284
Dilutive potential shares -
Stock options -- -- 63,361
Adjusted weighted average shares 4,040,425 4,080,092 4,139,645
The accompanying notes are an integral part of these
consolidated financial statements
GEORESOURCES, INC., AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
Additional
Common Stock Paid-in Retained
Shares Amount Capital Earnings Total
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
Purchase of common
stock (66,300) (663) (70,528) -- (71,191)
Net income -- -- -- 481,552 481,552
Balance,
December 31, 1999 4,005,352 $ 40,054 $ 776,259 $ 3,646,162 $ 4,462,475
The accompanying notes are an integral part of these
consolidated financial statements
GEORESOURCES, INC., AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
1999 1998 1997
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 481,552 $ (1,605,218) $ 766,265
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities:
Depreciation, depletion, amortization
and valuation allowance 635,797 2,130,871 850,599
Deferred income taxes (benefit) 26,000 (195,000) 110,000
Other 2,192 7,192 2,364
Changes in assets and liabilities:
Decrease (increase) in:
Trade receivables (467,021) (2,198) 414,111
Inventories 106,500 (115,265) (36,765)
Prepaid expenses and other 9,211 4,954 (13,221)
Investments 4,213 21,647 31,805
Increase (decrease) in:
Accounts payable 217,537 (109,569) 145,629
Accrued expenses 68,539 (13,169) (43,034)
Net cash provided by operating
activities 1,084,520 124,245 2,227,753
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant
and equipment (484,095) (1,287,321) (2,707,097)
Proceeds from sale of property
and equipment 9,450 -- 357,236
Net cash used in investing
activities (474,645) (1,287,321) (2,349,861)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings 160,000 1,275,000 425,000
Principal payments on long-term debt (315,996) (457,093) (583,200)
Proceeds from issuance of common stock -- -- 20,805
Cost to purchase common stock (71,191) (95,916) --
Debt issue costs -- (8,627) (5,000)
Net cash provided by (used in)
financing activities (227,187) 713,364 (142,395)
NET INCREASE (DECREASE) IN CASH
AND EQUIVALENTS 382,688 (449,712) (264,503)
CASH AND EQUIVALENTS, beginning of year 40,673 490,385 754,888
CASH AND EQUIVALENTS, end of year $ 423,361 $ 40,673 $ 490,385
The accompanying notes are an integral part of these
consolidated financial statements
GEORESOURCES, INC., AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
1999 1998 1997
SUPPLEMENTAL DISCLOSURE OF
CASH FLOW INFORMATION
Cash paid (received) for:
Interest $ 165,435 $ 138,791 $ 124,245
Income taxes (10,752) 14,573 9,922
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.
The accompanying notes are an integral part of these
consolidated financial statements
GEORESOURCES, INC., AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. SIGNIFICANT ACCOUNTING POLICIES:
Nature of Operations and Principles of Consolidation
The accompanying consolidated financial statements include the accounts
of GeoResources, Inc., and its 84% 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. Similarly, cash flows from such
transactions are included in the statements of cash flows as cash flows
from operating activities.
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 $2.99, $3.86 and $3.40 for 1999, 1998 and 1997,
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. 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.
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, 1999, consist of the
unevaluated, unimpaired cost of undeveloped oil and gas properties that
were acquired during the following years:
1999 $ 10,953
1998 20,253
1997 31,999
1996 and prior 80,208
Total $ 143,413
It is expected that evaluation of the above properties will occur
primarily over the next three 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, 1999,
1998 and 1997.
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 1999.
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 fiscal quarters of fiscal years beginning after June
15, 2000 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, 1999, 1998 and 1997:
1999 1998 1997
Revenue:
Oil and gas $ 2,688,642 $ 1,661,977 $ 3,425,395
Leonardite 651,847 718,674 764,398
$ 3,340,489 $ 2,380,651 $ 4,189,793
Operating income (loss):
Oil and gas $ 955,066 $ (1,279,105) $ 1,365,729
Leonardite (35,538) (8,975) 33,859
General corporate activities (299,422) (407,637) (442,973)
$ 620,106 $ (1,695,717) $ 956,615
Depreciation and depletion:
Oil and gas $ 519,407 $ 711,522 $ 724,061
Leonardite 100,590 101,468 108,903
General corporate activities 15,800 17,881 17,635
$ 635,797 $ 830,871 $ 850,599
Identifiable assets, net:
Oil and gas $ 4,894,495 $ 4,702,417 $ 5,452,759
Leonardite 1,417,100 1,347,521 1,452,847
General corporate activities 1,017,245 654,786 1,126,722
$ 7,328,840 $ 6,704,724 $ 8,032,328
Capital expenditures incurred:
Oil and gas $ 544,049 $ 1,158,211 $ 1,920,470
Leonardite -- -- 43,498
General corporate activities 5,086 2,289 9,927
$ 549,135 $ 1,160,500 $ 1,973,895
Major Customer
Sales to a major oil and gas customer were 60%, 54% and 71% of total
revenue for the years ended December 31, 1999, 1998 and 1997,
respectively. Accounts receivable from this major customer were 42% and
36% of total accounts receivable at December 31, 1999 and 1998,
respectively.
C. TRADE RECEIVABLES AND INVENTORIES:
Trade receivables at December 31, 1999 and 1998 are comprised of the
following:
1999 1998
Oil and gas purchasers $ 618,131 $ 353,607
Leonardite customers 384,438 181,941
1,002,569 535,548
Less allowance for
doubtful accounts (11,416) (11,416)
$ 991,153 $ 524,132
As of December 31, 1999 and 1998, inventories by major classes are
comprised of the following:
1999 1998
Crude oil $ 36,384 $ 114,464
Leonardite inventories:
Finished products 91,863 108,951
Raw materials 86,567 90,167
Materials and supplies 82,215 89,947
Total leonardite inventories 260,645 289,065
$ 297,029 $ 403,529
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 mortgage loans are expected to be repaid through
sale of the residence prior to the maturity date. The Company's interest
income from these loans was $8,100 for each of the years ended December
31, 1999, 1998 and 1997.
E. LONG-TERM DEBT:
Long-term debt at December 31, 1999 and 1998 consists of the following
loans and a revolving line of credit (RLOC) which are all with one bank:
1999 1998
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, collateralized by oil
and gas properties $ -- $ 141,000
The 1995 Oil & Gas Loan, prime
plus 1% (9.50% total rate at
December 31, 1999), due in monthly
installments of $14,583 plus
interest, due December 2001,
collateralized by oil and gas
properties 350,008 525,004
The 1997 Oil & Gas RLOC, $3,000,000
revolving line of credit, interest
payable monthly at prime plus .75%,
(9.5% total rate at December 31,
1999), expires January 5, 2005,
collateralized by oil and gas
properties 1,435,000 1,275,000
Total long-term debt 1,785,008 1,941,004
Less current maturities (175,000) (316,000)
Long-term debt, less current
maturities $ 1,610,008 $ 1,625,004
Aggregate maturities required on long-term debt at December 31, 1999,
are as follows:
Year Ending December 31:
2000 $ 175,000
2001 533,758
2002 358,750
2003 358,750
2004 358,750
Thereafter --
$ 1,785,008
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; restrict borrowings from, and
credit extensions to, other parties; restrict reorganization or mergers
in which the Company is not the surviving corporation; and not pay cash
dividends without the bank's consent.
F. INCOME TAXES:
The components of income tax expense for the years ended December 31,
1999, 1998 and 1997, are as follows:
1999 1998 1997
Current tax (expense) $ -- $ -- $ --
Deferred tax benefit (expense) (168,000) 685,000 (369,000)
Decrease (increase) in deferred
tax assets valuation allowance 142,000 (490,000) 259,000
Income tax (expense) benefit $ (26,000) $ 195,000 $ (110,000)
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 1999 and 1997, the Company recorded deferred tax expense of
$168,000 and $369,000, respectively. This related primarily to net
income that was not currently taxable due to the utilization of net
operating loss carryforwards and the deduction of intangible drilling
costs for tax purposes, respectively. The Company also decreased the
deferred tax asset valuation allowance by $142,000 and $259,000 during
1999 and 1997, 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, 1999 and 1998, are as follows:
1999 1998
Deferred Tax Assets:
Net operating loss carryforward $ 245,000 $ 454,000
Statutory depletion carryforward 1,205,000 1,252,000
Tax credit carryforwards 56,000 55,000
Other 35,000 46,000
1,541,000 1,807,000
Valuation Allowance:
Beginning of year (982,000) (492,000)
(Increase) decrease 142,000 (490,000)
End of year (840,000) (982,000)
Deferred Tax Liabilities:
Accumulated depreciation and
depletion (867,000) (965,000)
Net Deferred Tax Liability, long-term $ (166,000) $ (140,000)
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, 1999,
1998 and 1997 is as follows:
1999 1998 1997
Income tax expense (benefit)
at statutory rate 35% (35)% 35%
Change in valuation allowance (28) 27 (30)
State income taxes and other (2) (3) 8
5% (11)% 13%
For income tax purposes, the Company has a statutory depletion carryover
of approximately $3,765,000 that, 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
2000 $ -- $ 16,000
2003 16,000 --
2008 115,000 --
2009 237,000 --
2017 342,000 --
2018 55,000 --
Total $ 765,000 $ 16,000
G. 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, 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
Grants -- --
Exercises -- --
December 31, 1999 5,000 278,500
Information with respect to the options outstanding and exercisable at
December 31, 1999 and 1998, 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
The average exercise price is $2.00 for options outstanding and
exercisable at December 31, 1999.
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. The Company's total
contributions to the plan, matching and discretionary, for the years
ended December 31, 1999, 1998 and 1997 were $44,989, $19,883 and
$31,930, respectively.
H. 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.
I. 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, 1999 and 1998:
1999 1998
Building and improvements $ 163,834 $ 163,834
Accumulated depreciation (71,945) (63,754)
$ 91,889 $ 100,080
The Company leases the remainder of the building to unaffiliated
businesses under cancelable lease agreements. During 1999, 1998 and
1997, the Company received $21,300, $21,300 and $22,200, respectively,
in rental income from the building which is included in other income in
the accompanying statements of operations.
J. 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
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 $108,199, $37,849 and $30,269 for the years ended
December 31, 1999, 1998 and 1997, respectively. At December 31, 1999
and 1998, the Company had no derivative financial instruments.
K. 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, 1999, 1998 and
1997:
1999 1998 1997
Proved properties $ 19,664,222 $ 19,139,363 $ 17,997,596
Unproved properties 143,413 141,019 124,672
Total 19,807,635 19,280,382 18,122,268
Less accumulated depreciation,
depletion, amortization and
impairment (15,600,726) (15,081,319) (13,069,796)
Net capitalized costs $ 4,206,909 $ 4,199,063 $ 5,052,472
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, 1999, 1998 and 1997:
1999 1998 1997
Property acquisition costs:
Proved $ 20,259 $ 236,058 $ 28,420
Unproved 21,159 37,756 55,230
Exploration costs 57,310 68,365 75,765
Development costs 445,321 816,032 1,761,055
$ 544,049 $ 1,158,211 $ 1,920,470
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, 1999, 1998 and 1997:
1999 1998 1997
Oil and gas sales $ 2,688,642 $ 1,661,977 $ 3,425,395
Production costs (1,214,169) (929,560) (1,335,605)
Depletion, depreciation
and amortization (519,407) (711,522) (724,061)
955,066 20,895 1,365,729
Imputed income tax provision (104,000) -- --
$ 851,066 $ 20,895 $ 1,365,729
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, 1999 or 1997.
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, 1999, 1998 and 1997:
1999 1998 1997
Oil Gas Oil Gas Oil Gas
(bbl) (mcf) (bbl) (mcf) (bbl) (mcf)
Proved reserves,
beginning of
year 1,286,000 234,000 2,387,000 253,000 2,154,000 261,000
Purchases of
reserves-in-
place -- -- 78,000 -- 1,000 --
Sales of reserves
-in-place -- -- -- -- (25,000) --
Extensions and
discoveries -- -- -- -- 201,000 1,000
Improved
recovery 44,000 -- 124,000 -- 350,000 --
Revisions of
previous
estimates 1,418,000 31,000 (1,130,000) (10,000) (83,000) 1,000
Production (182,000) (8,000) (173,000) (9,000) (211,000) (10,000)
Proved reserves,
end of year 2,566,000 257,000 1,286,000 234,000 2,387,000 253,000
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)
1999 2,566,000 257,000
1998 1,286,000 234,000
1997 1,640,000 253,000
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,
were significantly lower than at December 31, 1999 or 1997. This is
primarily due to the low oil price in effect 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, 1999, 1998 and 1997:
1999 1998 1997
Future cash inflows $ 55,686,000 $ 11,274,000 $ 33,521,000
Future production costs (19,665,000) (6,141,000) (13,602,000)
Future development costs (3,738,000) (242,000) (3,495,000)
Future income tax expense (8,449,000) (241,000) (5,318,000)
Future net cash flows 23,834,000 4,650,000 11,106,000
Less effect of a 10%
discount factor (10,106,000) (1,814,000) (4,587,000)
Standardized measure of
discounted future net
cash flows relating to
proved reserves $ 13,728,000 $ 2,836,000 $ 6,519,000
The principal sources of change in the standardized measure of discounted
future net cash flows are as follows for the years ended December 31, 1999,
1998 and 1997:
1999 1998 1997
Standardized measure, beginning
of year $ 2,836,000 $ 6,519,000 $ 11,446,000
Sales of oil and gas produced,
net of production costs (1,474,000) (732,000) (2,090,000)
Net changes in prices and
production costs 7,219,000 (6,032,000) (6,612,000)
Purchases of reserves-in-place -- 134,000 1,000
Sales of reserves-in-place -- -- (120,000)
Extensions, discoveries and other
additions, less related costs 351,000 295,000 2,654,000
Revisions of previous quantity
estimates and other 11,321,000 (2,673,000) (713,000)
Development costs incurred during
the year and changes in
estimated future development
costs (2,006,000) 1,904,000 (1,011,000)
Accretion of discount 200,000 447,000 1,595,000
Net change in income taxes (4,719,000) 2,974,000 1,369,000
Standardized measure, end of year $ 13,728,000 $ 2,836,000 $ 6,519,000
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 24, 2000 /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 executive 3/24/00
J. P. Vickers officer and principal financial
officer) and Director
/s/ Cathy Kruse Secretary/Treasurer 3/24/00
Cathy Kruse and Director
/s/ Dennis Hoffelt Director 3/24/00
Dennis Hoffelt
/s/ Paul A. Krile Director 3/24/00
Paul A. Krile
/s/ Duane Ashley Director 3/24/00
Duane Ashley
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 1999 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 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 *
10.2 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 *
10.3 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 *
10.4 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 *
10.5 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 *
10.6 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 *
10.7 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. *
10.8 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. *
10.9 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 *
10.10 License Agreement dated January 22, 1999, by and
between GeoResources, Inc. and Silverado Landscape
Materials, and all related documents *
27 Financial Data Schedule
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 423,361
<SECURITIES> 106
<RECEIVABLES> 991,153
<ALLOWANCES> 0
<INVENTORY> 297,029
<CURRENT-ASSETS> 1,728,906
<PP&E> 23,723,295
<DEPRECIATION> (18,271,169)
<TOTAL-ASSETS> 7,328,840
<CURRENT-LIABILITIES> 1,090,357
<BONDS> 1,610,008
0
0
<COMMON> 40,054
<OTHER-SE> 4,422,421
<TOTAL-LIABILITY-AND-EQUITY> 7,328,840
<SALES> 3,340,489
<TOTAL-REVENUES> 3,393,330
<CGS> 1,777,250
<TOTAL-COSTS> 2,720,383
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 165,395
<INCOME-PRETAX> 507,552
<INCOME-TAX> 26,000
<INCOME-CONTINUING> 481,552
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 481,552
<EPS-BASIC> .12
<EPS-DILUTED> .12
</TABLE>
