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, 1995.
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.
The aggregate market value of the Common Stock (the only class of voting
stock) held by nonaffiliates of the Registrant as of March 15, 1996, was
approximately $5,329,145 (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 18,
1996: 4,060,714
DOCUMENTS INCORPORATED BY REFERENCE - NONE
Page 1 of 54 pages; with exhibits.
PART I.
ITEM 1. BUSINESS
General Development of Business
GeoResources, Inc. (the "Registrant" or the "Company") is a
natural resources company engaged principally in the following two
business segments: 1) oil and gas exploration, development and
production; and 2) mining of leonardite (oxidized lignite coal) and
manufacturing of leonardite based products which are sold primarily as
oil and gas drilling mud additives. The Registrant was incorporated
under Colorado law in 1958 and was originally engaged in uranium mining.
The Registrant built its first leonardite processing plant in 1964 in
Williston, North Dakota, and began participating in oil and gas
exploration and production in 1969. In 1982, the Registrant completed
construction of a larger leonardite processing plant in Williston that
is in use today. Financial information about the Registrant's two
industry segments is presented in Note B to the Financial Statements in
Item 8 of this report.
Oil and Gas Exploration, Development and Production
The Registrant's oil and gas exploration and production
efforts are presently concentrated on oil properties in the North Dakota
and Montana portions of the Williston Basin. The Registrant typically
generates prospects for its own exploitation, but when a prospect is
deemed to have substantial risk or cost, the Registrant may attempt to
raise all or a portion of the funds necessary for exploration or
development through farmouts, joint ventures, or other similar types of
cost-sharing arrangements. The amount of interest retained by the
Registrant in a cost-sharing arrangement varies widely and depends upon
many factors, including the exploratory costs and the risks involved.
In addition to originating its own prospects, the Registrant
occasionally participates in exploratory and development prospects
originated by other individuals and companies. The Registrant also
evaluates interests in various proved properties to acquire for further
operation and/or development.
The Registrant, where possible, supervises drilling and
production activities on new prospects and properties acquired. It does
not own and does not have any plans to acquire any rotary drilling
equipment. Hence, the Registrant uses independent drilling contractors
for the drilling of wells of which it is the operator.
As of December 31, 1995, the Registrant had developed oil and
gas leases covering approximately 12,166 net acres in Montana and North
Dakota and during 1995, sold an average 421 net equivalent barrels of
oil per day from 88 gross (61.90 net) producing wells located primarily
in North Dakota.
The Registrant sells its crude oil to purchasers with
facilities located near the Registrant's wells. The Registrant's gas
reserves are also contracted to purchasers in the area near the
Registrant's wells. The gas from the Registrant's Hammond Field in
Carter County, Montana is under contract to Williston Basin Interstate
Pipeline Company; however, no deliveries have been accepted since April
1987 due to an alleged force majeure claim by that gas purchaser. The
Company has instituted legal proceedings against the purchaser for
damages from the refusal to purchase. (See Item 3.)
Mining and Manufacturing Leonardite Products
The Registrant operates a leonardite mine and processing plant
in Williston, North Dakota. Leonardite is mined from leased reserves
and manufactured into several different dry, free flowing powders
primarily for the oil well drilling mud industry. Leonardite, in
combination with other additives, acts as a dispersant or thinner, and
provides filtration control in drilling muds. Leonardite is also sold
by the Registrant for use in metal working foundries and in agricultural
applications.
In 1995, the Company's leonardite products were sold to 42
customers, the majority of whom are drilling mud companies located in
coastal areas of the Gulf of Mexico. Demand for the plant's output is
governed mainly by the level of oil and gas drilling activities
particularly in the gulf coast area, both onshore and offshore.
Drilling activity declined substantially in the mid 1980's and has
remained at relatively low levels for the past several years. The
Registrant has no significant supply contracts with individual
customers.
Status of Products, Services or Industry Segments in
Development
The Company owns 78% of the stock of Belmont Natural Resource
Company, Inc. (BNRC), a Washington corporation formed for the purpose of
exploiting natural gas opportunities in the Pacific Northwest.
Activities in 1995 included geological mapping and purchasing oil and
gas leases on 6,713 gross acres (6,479 net) on a prospect located in the
State of Washington. (See Note A to the Financial Statements for
further information.)
In addition to its two principal business segments, the
Registrant owns a nonproducing silver property in Arizona. (See Item
2.) The Company also owns a minor amount of geothermal and other
mineral rights located in Oregon. The Registrant does not expect to
devote any substantial resources to hard mineral or geothermal
exploration or development in 1996.
Sources and Availability of Raw Materials and Leases
Maintaining sufficient leasehold mineral interests for oil and
gas exploration and development is a primary continuing need in the oil
and gas business. Management believes that the Company's current
undeveloped acreage is sufficient to meet its presently foreseeable oil
and gas leasehold needs. Maintaining sufficient leasehold mineral
interests for leonardite mining is also a continuing need for the
Registrant's mining and manufacturing of leonardite products.
Management believes the leonardite held under current leases is
sufficient to maintain the present output for many years. (See Item 2.)
Major Customers
In 1995, Registrant sold its crude oil to 18 purchasers. Koch
Oil Company, Placid Refining Company, and Apache Energy Resources
Corporation were the major customers, accounting for approximately 70%,
7%, and 5%, respectively, of the Registrant's oil and gas revenue in
fiscal 1995, which was approximately 53%, 5%, and 4%, respectively, of
the Registrant's total revenue. Management believes there are other
crude oil purchasers to whom the Company would be able to sell its oil
if it lost any of its current customers.
In 1995, the Registrant sold leonardite products to 42
customers. The largest customer in 1995 for leonardite products made
purchases that totaled 20% of the Registrant's mining and manufacturing
revenue, which was approximately 5% of the Registrant's total operating
revenue.
Backlog Orders, Research and Development
The Registrant does not have any material long-term or short-
term contracts to supply leonardite products. All orders are reasonably
expected to be filled within three weeks of receipt. From time to time,
the Registrant does have short-term contracts to deliver quantities of
oil or gas; however, no significant backlog exists. The Company's oil
and gas division order contracts and off lease marketing arrangements
are typical of those in the industry with 30 to 90 day cancellation
notice provisions and they generally do not require long-term delivery
of fixed quantities of oil or gas. The Registrant has not spent any
material time or funds on research and development, and does not expect
to do so in the foreseeable future.
Competition
Oil and Gas
In addition to being highly speculative, the oil and gas
business is intensely competitive among the many independent
operators and major oil companies in the industry. Many competitors
possess financial resources and technical facilities greater than those
available to the Registrant and may, therefore, be able to pay more for
desirable properties or to find more potentially productive prospects.
However, management believes the Registrant has the ability to obtain
leasehold interests which will be sufficient to meet its future oil and
gas needs.
Leonardite Products
Uses and specifications of leonardite-based drilling mud
additives are subject to change if better products are found.
The Registrant's products compete with leonardite and non-leonardite
products used as additives in numerous different types of drilling mud.
In addition, leonardite deposits are available in other areas within
the United States and competitors may be able to enter the
leonardite business with relative ease. At the present time, similar
products are marketed by other companies who mine, process and market
leonardite products. Competition lies primarily in delivery time,
transportation costs, quality of the product, performance of the product
when used in drilling mud and access to high-quality leonardite.
Environmental Regulations
All of the Registrant's operations are generally subject to
federal, state or local environmental regulations. The Registrant's oil
and gas business segment is affected particularly by those environmental
regulations concerned with the disposal of produced oilfield brines and
other wastes. The Registrant's leonardite mining and processing segment
is also subject to numerous state and federal environmental regulations,
particularly those concerned with air quality at the Company's
processing plant, and mine permit and reclamation regulations pertaining
to surface mining at the Company's leonardite mine. The Company
believes that maintenance of future acceptable air quality levels at its
processing plant could become more costly. If and when plant production
increases substantially above 1995 levels, management believes that it
could become necessary to replace or upgrade air quality control
equipment. Future environmental compliance costs that might be required
to upgrade the equipment cannot be known at this time.
Foreign Operations and Export Sales
The Registrant has no production facilities or operations in
foreign countries and has no direct export sales. Some of the Company's
leonardite products are sold to distributors in the United States who in
turn export these products.
Employees
As of March 15, 1996, the Registrant had 12 full-time employees.
ITEM 2. PROPERTIES
The Registrant's properties consist of four main categories:
office, leonardite plant and mine, oil and gas, and a nonproducing
silver property. Certain of these properties are mortgaged to the
Company's bank. (See Note E to the Financial Statements for further
information.)
Office
The Registrant owns a 17,500 square foot office building which
is located on a one acre lot in Williston, North Dakota. The Company
utilizes approximately 5,000 square feet of the building and rents the
remainder to other unaffiliated businesses.
Leonardite Plant and Mine
The site of the Registrant's plant covers approximately nine
acres located one mile east of Williston in Williams County, North
Dakota. This site and an additional 20 acres of undeveloped property
are owned by the Company. The plant has approximately 11,500 square
feet of floor area composed of warehousing and processing space.
Therein is equipment able to process and ship approximately 3,000 tons
of leonardite products per month. Finished product leonardite sales for
the past three years are shown below.
Finished Average
Products Sales Price
Year (Tons) Per Ton
1995 7,528 $ 93.51
1994 8,141 $ 93.05
1993 7,157 $ 95.29
The Registrant's leonardite mining properties consist of a
developed lease from private parties and one undeveloped lease from the
United States Department of the Interior, Bureau of Land Management.
The leased land is located about one mile from the plant site in
Williams County, North Dakota. The private-party (fee) lease totals
approximately 160 acres. The federal lease from the Bureau of Land
Management (BLM) covers 160 undeveloped acres. In 1994, the Company
formed a 240 acre logical mining unit (LMU), in accordance with BLM
regulations, consisting of 80 acres of the fee lease and 160 acres of
the BLM lease. This LMU allows current operations on the fee lease to
satisfy diligent development and other requirements for 160 acres of the
BLM lease. Management believes the leonardite contained in the 240 acre
LMU is sufficient to supply its plant's raw material requirements for
many years and that before these reserves were exhausted, the Company
would be able to acquire other fee or federal coal leases in the same
area.
Oil and Gas Properties
The Registrant owns developed oil and gas leases totaling
16,280 gross acres (12,166 net acres) as of March 15, 1996, plus
associated production equipment and also owns a number of undeveloped
oil and gas leases. The acreage and other additional information
concerning the Registrant's oil and gas operations are presented in the
following tables.
Estimated Net Quantities of Oil and Gas and Standardized
Measure of Future Net Cash Flows
All the Registrant's oil and gas reserves are located in the United
States. Information concerning the estimated net quantities of all the
Registrant's proved reserves and the standardized measure of future net cash
flows from such reserves is presented as unaudited supplementary information
following the Financial Statements in Item 8. The estimates are based upon
the report of Broschat Engineering and Management Services, an independent
petroleum engineering firm in Williston, North Dakota. The Registrant has no
long-term supply or similar agreements with foreign governments or
authorities, and the Registrant does not own an interest in any reserves
accounted for by the equity method.
Net Oil and Gas Production, Average Price and Average
Production Cost
The net quantities of oil and gas produced and sold for
each of the last three fiscal years, the average sales price per unit
sold and the average production cost per unit are presented below.
OIL & GAS
Net Average Average Average
Net Net Oil & Gas Oil Gas Prod.
Oil Gas Prod. Sales Sales Cost Per
Prod. Prod. (Equiv. Price Price Equiv.
Year (Bbls) (MCF) Bbls)* Per Bbl Per MCF Bbl**
1995 151,467 13,061 153,644 $14.34 $ 0.98 $ 6.18
1994 138,552 9,191 140,084 $12.11 $ 1.19 $ 6.92
1993 126,300 17,086 129,148 $13.26 $ 1.06 $ 6.78
*Equivalent barrels have been calculated on the basis of six thousand
cubic feet (6 MCF) of natural gas equals 1 barrel of oil.
**Average production cost includes lifting costs, remedial workover
expenses and production taxes.
Gross and Net Productive Wells
As of December 31, 1995, the Registrant's total gross and net
productive wells were as follows:
Productive Wells*
Oil Gas
Gross Wells Net Wells Gross Wells Net Wells
93 65.82 24 24.00
*There are no wells with multiple completions. A gross well is a well
in which a working interest is owned. The number of net wells
represents the sum of fractional working interests the Company owns in
gross wells. Productive wells are producing wells plus shut-in wells
the Company deems capable of production.
Gross and Net Developed and Undeveloped Acres
As of March 15, 1996, the Registrant had total gross and net developed
and undeveloped oil and gas leasehold acres as set forth below. The developed
acreage is stated on the basis of spacing units designated by state regulatory
authorities.
Leasehold Acreage*
DEVELOPED UNDEVELOPED TOTAL
Gross Net Gross Net Gross Net
Montana 9,000 7,630 17,539 17,309 26,539 24,939
North Dakota 7,280 4,536 28,097 10,277 35,377 14,813
Washington 0 0 5,236 5,054 5,236 5,054
ALL STATES 16,280 12,166 50,872 32,640 67,152 44,806
*Gross acres are those acres in which a working interest is owned. The
number of net acres represents the sum of fractional working interests
the Company owns in gross acres.
Exploratory Wells and Development Wells
For each of the last three fiscal years ended December 31, the
number of net exploratory and development productive and dry wells drilled
by the Company was as set forth below.
Net Exploratory Net Development Total Net
Year Wells Drilled Wells Drilled Wells Drilled
Productive Dry Productive Dry
1995 0.00 0.00 1.34 0.00 1.34
1994 0.00 0.00 2.00 0.00 2.00
1993 0.00 0.03 0.63 0.00 0.66
Present Activities
From January 1, 1996 to March 15, 1996, the Registrant had no wells
in the process of drilling.
Supply Contracts or Agreements
The Registrant is not obligated to provide a fixed or determinable
quantity of oil and gas in the future under any existing contract or
agreement, beyond the short term contracts customary in division orders and
off lease marketing arrangements within the industry.
Reserve Estimates Filed with Agencies
No estimates of total proved net oil and gas reserves for the year
ended December 31, 1995 have been filed with any federal authority or agency.
Other than the estimates of reserves at December 31, 1994, filed with the
Securities and Exchange Commission, the Registrant did not file reserve
reports with any other federal agencies within the past 12 months.
Silver Property
The Registrant owns seven patented mining claims and 15
unpatented mining claims in Pinal County, Arizona. These claims,
referred to as the Reymert Silver Property, have produced silver
sporadically since the 1880's. The property's last ore production was
in 1989 under a lease arrangement. In 1993, the Registrant entered into
a License Agreement with another company to allow commercial rock
production from the patented claims. The Registrant receives a royalty
of $2 per ton for rock severed from the property. No commercial rock
production occurred in 1995. No mining activities, other than required
assessment work, are presently being conducted on this property.
Management has no plans to devote significant financial resources to
this property in 1996; however, it continues to investigate ways to
further exploit the property.
ITEM 3. LEGAL PROCEEDINGS
On May 12, 1989, the Registrant 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 alleges, among other things,
breach of contract by defendants, in price, delivery and tax
reimbursement relating to a take or pay natural gas contract with the
Registrant covering certain interests in Carter County, Montana. The
Complaint also alleges breaches of Defendants' good faith obligation to
carry out the terms of the contract and an attempt by the Defendants to
coerce the Registrant into modifying or amending the contract. The
Registrant has asked for damages against Defendants in amounts
specifically to be proven at trial, along with exemplary damages and
such further relief as the Court may deem just and equitable. The
Defendants have denied the allegations in their Answer filed with the
Court on June 1, 1989. Management believes that the Registrant will
prevail in its claim, although the extent of award cannot be predicted
at this time. Other than the foregoing legal matter, the Company is not
a party, nor is any of its property subject to, any pending material
legal proceedings. The Company knows of no legal proceedings
contemplated or threatened against it.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the fourth quarter of 1995 no matter was submitted to a
vote of security holders of the Company, through the solicitation of
proxies or otherwise.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The Registrant's Common Stock trades on The Nasdaq SmallCap
market under the Symbol "GEOI." The following table sets forth for the
period indicated the lowest and highest trade prices for the
Registrant's Common Stock as reported by the Nasdaq Stock Market. These
trade prices may represent prices between dealers and do not include
retail markups, markdowns or commissions.
Trade Price
Calendar Low High
1994 1st Quarter $ .69 $ .69
2nd Quarter $ .62 $ .69
3rd Quarter $ .69 $ .81
4th Quarter $ .81 $ 1.12
1995 1st Quarter $ 1.00 $ 1.75
2nd Quarter $ 1.25 $ 1.62
3rd Quarter $ 1.12 $ 1.50
4th Quarter $ 1.06 $ 1.38
As of March 15, 1996, there were approximately 1,500 holders
of record of the Registrant's Common Stock. Management believes that
there are also approximately 1,000 additional beneficial owners of
common stock held in "street name".
The Registrant has never declared or paid a cash dividend on
its Common Stock nor does it anticipate that dividends will be paid in
the near future. Further, certain of the Company's financing agreements
restrict the payment of cash dividends. (See Note E to the Financial
Statements for further information.)
ITEM 6. SELECTED FINANCIAL DATA
1995 1994 1993 1992 1991
Operating
Revenue $2,888,402 $2,446,093 $ 2,375,150 $2,498,230 $2,453,722
Income (Loss)
Before Cumula-
tive Effect
of Accounting
Change $ 303,889 $ 40,141 $(1,654,090) $ 104,420 $ 99,145
Net Income
(Loss) $ 303,889 $ 40,141 $(1,077,090) $ 104,420 $ 99,145
Income (Loss)
Per Share From
Continuing
Operations $ .08 $ .01 $ (.41) $ .03 $ .03
Net Income
(Loss)
Per Share $ .08 $ .01 $ (.27) $ .03 $ .03
AT YEAR END:
Total Assets $6,690,285 $5,796,354 $ 5,856,396 $7,325,479 $6,648,716
Long-term
Debt $ 958,330 $ 787,035 $ 1,019,792 $1,129,897 $ 546,097
Working
Capital
(Deficit) $ (171,949) $ (86,786) $ 149,646 $ 261,251 $ 27,944
Stockholders'
Equity $4,114,001 $3,798,549 $ 3,758,408 $4,789,594 $4,685,174
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
INTRODUCTION
The Company conducts business through two primary segments:
1) oil and gas exploration and production; and 2) leonardite mining and
processing wherein the Company's major products are oil and gas drilling
mud additives. Each of the Company's segments is discussed herein.
RESULTS OF OPERATIONS
Comparison of 1995 to 1994 Revenue and Gross Margin
Oil and gas sales were $2,184,000 in 1995 compared to
$1,689,000 in 1994, an increase of $495,000 or 29%. This increase in
revenue resulted from an 18% increase in average oil prices combined
with a 10% increase in the volume of oil and gas sold. The 1995 average
oil price was $14.34 compared to an average of $12.11 in 1994. The
volume of oil and gas sold in 1995 increased to 154,000 BOE (Barrel of
Oil Equivalent) from 140,000 BOE in 1994. The higher 1995 production
volumes resulted from production contributed by the Company's Oscar
Fossum H1 horizontal well (.67 net) that was drilled and completed in
the first quarter of 1995. The Company also drilled a second horizontal
well, the Oscar Fossum H2, during 1995; but that well did not begin
producing until mid December 1995, and therefore, did not have a
significant impact on 1995 oil production. Management expects
production from the H2 well will increase oil production in 1996.
Oil and gas production costs were $950,000 in 1995 compared to
$969,000 in 1994, a decline of 2%. Costs were lower because the Company
performed less workovers during 1995 when its operations and cash flow
were focused on horizontal drilling. Production costs on a per
equivalent barrel basis averaged $6.18 in 1995 compared to $6.92 for
1994. Per barrel costs were lower due to the contribution of lower cost
horizontal well "flush" production from the Oscar Fossum H1 well. Gross
margin for 1995 oil and gas operations before depletion and selling,
general and administrative (SG&A) expenses was $1,234,000 or 56% of
revenue, compared to $720,000 or 43% of revenue for 1994. The increase
in gross margin was due to the increased average oil price and
production volumes previously discussed.
Leonardite sales were $704,000 in 1995 compared to $758,000 in
1994, a decline of 7%. This decline was due to an 8% decrease in
production sold, resulting from lower demand. Production sold in 1995
was 7,528 tons at an average price of $93.51 per ton, compared to 8,141
tons at an average price of $93.05 for 1994.
Cost of leonardite sold was $560,000 in 1995 compared to
$585,000 in 1994, a decline of 4%. This decline resulted from the lower
1995 production. Production costs per ton were $74.34 and $71.89 for
1995 and 1994, respectively. Costs per ton for 1995 were higher than
1994 due to the lower production volume which spread fixed costs over
fewer tons.
Gross margin for 1995 leonardite operations before
depreciation and SG&A expenses was $144,000 or 20% of revenue, compared
to $172,000 or 23% of revenue, for 1994. The decline in 1995 gross
margin was due to the lower production level.
Comparison of 1995 to 1994 Consolidated Analysis
Total revenue for 1995 increased $442,000 or 18% to $2,888,000
from $2,446,000 in 1994. This increase was due to the oil revenue
increase previously discussed.
Total operating costs for 1995 increased $120,000 or 5% to
$2,453,000 from $2,333,000 in 1994. Operating costs increased in 1995
because of higher depletion and SG&A expenses. Depletion expense
increased due to increases in full cost pool assets associated with
horizontal drilling done in 1995 and undeveloped locations planned in
the next three years. SG&A expense increased because the Company made a
more substantial contribution to its employees' profit sharing plan in
light of the higher 1995 net income.
Due to higher revenue, operating income for 1995 increased
$323,000 or 286% to $436,000 compared to $113,000 in 1994. Nonoperating
expense for 1995 increased $39,000 or 60% to $104,000 compared to
$65,000 in 1994. Higher nonoperating expenses were primarily the result
of higher interest expense. As a result of higher operating income,
1995 income before taxes increased $284,000 or 592% to $332,000 compared
to $48,000 in 1994.
Income tax expense in 1995 was $28,000 compared to $8,000 in
1994. The expense amount for each year reflects the net changes in the
Company's deferred tax assets and liabilities.
Net income for 1995 increased $264,000 or 660% to $304,000 (8 cents per
share) compared to $40,000 (1 cent per share) in 1994.
Comparison of 1994 to 1993 Revenue and Gross Margin
Oil and gas sales were $1,689,000 in 1994 compared to
$1,693,000 in 1993, a slight decline of $4,000 or 0.2%. This
essentially stable revenue was due to an 8.7% decline in average oil
prices that was offset by an 8.5% increase in the volume of oil and gas
sold. The 1994 average oil price was $12.11 compared to an average of
$13.26 in 1993. The volume of oil and gas sold in 1994 increased to
140,000 BOE (Barrels of Oil Equivalent) from 129,000 BOE in 1993. The
lower 1994 average oil price was entirely due to substantially lower
prices in the first half of 1994. The average price per BOE for the
first half of 1994 was $11.21 compared to $12.95 for the second half of
1994. The higher 1994 production volumes resulted from 1993 and 1994
workover and drilling operations and sales from year end 1993 inventory.
Oil and gas production costs were $969,000 in 1994 compared to
$875,000 in 1993, an increase of 10.7%. This increase was primarily
related to the 8.5% oil and gas sales volume increase. Production costs
on a per equivalent barrel basis averaged $6.92 for 1994 compared to
$6.78 for 1993. Gross margin for 1994 oil and gas operations before
deductions for depletion and selling, general and administrative
expenses was $720,000, or 43% of revenue, compared to $818,000, or 48%
of revenue, for 1993. The decline in 1994 gross margin was primarily
due to lower 1994 oil prices previously discussed.
Leonardite sales were $758,000 in 1994 compared to $682,000
in 1993, an increase of $76,000, or 11%. This increase was primarily
due to a 14% increase in production sold. Production sold in 1994 was
8,141 tons at an average price of $93.05, compared to 7,157 tons at an
average price of $95.29 for 1993. Variations in sales volumes and
average prices were normal fluctuations associated with drilling mud
additive demand levels during 1994 and 1993.
Cost of leonardite sold was $585,000 in 1994 compared to
$542,000 in 1993, an increase of $43,000 or 7.9%. This increase
resulted from the 14% increase in 1994 production. Production costs per
ton were $71.89 and $75.76 for 1994 and 1993, respectively. Costs per
ton for 1994 were lower than 1993 due to the higher production volume
which spread fixed costs over more tons.
Gross margin for 1994 leonardite operations before deductions
for depreciation and selling, general and administrative expenses was
$172,000, or 23% of revenue, compared to $140,000, or 20% of revenue,
for 1993. The increase in 1994 gross margin was primarily due to the
lower per ton production costs discussed above.
Comparison of 1994 to 1993 Consolidated Analysis
Total revenue for 1994 increased $71,000, or 3%, to $2,446,000
from $2,375,000 in 1993. This increase was due to the $76,000
leonardite revenue increase previously discussed.
Operating costs for 1994 declined $15,000 or 0.6%, to
$2,333,000 compared to $2,348,000 exclusive of the write-down for oil
and gas properties in 1993. These stable costs resulted from lower
depletion expense and higher oil and gas and leonardite production
costs. Selling, general and administrative expenses were virtually
unchanged from 1993 to 1994. Total operating costs for 1994 decreased
$1,431,000 or 38% to $2,333,000 from $3,763,000 in 1993 due to the
$1,415,000 non-cash write-down of oil and gas properties that increased
operating cost in 1993.
Higher 1994 total revenue coupled with lower operating costs
resulted in operating income of $113,000 for 1994. Nonoperating
expenses decreased $5,000 from $70,000 in 1993 to $65,000 in 1994,
yielding an income before taxes of $48,000 in 1994 compared to a
$1,458,000 loss in 1993.
Income tax expense in 1994 was $8,000 compared to $196,000 in
1993. The expense amount for each year is reflective of the net changes
in the Company's deferred tax assets and deferred tax liabilities and
include only a minimal amount of income taxes currently paid. Effective
January 1, 1993, the Company adopted Statement of Financial Accounting
Standard No. 109, "Accounting for Income Taxes." The cumulative effect
of the change on prior years was reflected as a $577,000 benefit in
1993. (See Notes A and F to the Financial Statements for further
information.)
Net income for 1994 was $40,000 or 1 cent per share compared
to a net loss, after the cumulative effect of the change in accounting
for income taxes, of $1,077,000 or 27 cents per share in 1993.
Liquidity and Capital Resources at year end 1995.
At December 31, 1995, the Company had current assets of
$1,295,000 compared to current liabilities of $1,467,000 for a current
ratio of .88 to 1 and negative working capital of $172,000. This
compares to a current ratio of .92 to 1 at December 31, 1994. This
negative working capital was caused by the costs associated with the
drilling and completion of the Oscar Fossum H2 late in the fourth
quarter of 1995. The Company expects to return to a positive working
capital during 1996.
During the year ended December 31, 1995, the Company generated
cash flows from operating activities of $804,000 which is $146,000
greater than the amount generated during 1994. Management believes that
cash flows from operations for 1996 should increase above 1995 levels
particularly if the Company continues successful horizontal development
of certain of its properties. During 1995, the Company drilled two
horizontal wells (2 gross, 1.34 net) in one of its existing fields.
These wells were successful, and the second well was put on production
in December 1995. The Company anticipates that cash flows from
operations and bank borrowings will be sufficient to meet its short-term
cash requirements.
During 1995, the Company's investing activities totaled
$947,000 which was primarily for additions to property, plant and
equipment. Part of the source of these funds was $20,000 realized from
the sale of property and equipment leaving net cash used in investing of
$927,000. The $900,000 cash portion of additions to property and
equipment consists of the approximate amounts as follows: exploration
and development costs of $633,000 that included the paid portion of
costs for drilling and completing 2 gross (1.34 net) horizontal oil
wells; proved property acquisition costs of $189,000 that included the
cost of acquiring interests in several producing wells; unproved
property costs of $15,000 primarily for oil and gas lease costs; delay
rental costs of $37,000; and improvements to the Company's leonardite
plant of $26,000. Over and above the additions to property and
equipment, the Company also used $47,000 to fund oil and gas leasehold
purchases in the State of Washington through its 78% owned subsidiary,
Belmont Natural Resource Company, Inc. During 1995, the Company's
financing activities also utilized $367,000 of cash for principal
payments required under long-term debt agreements.
The sources of cash in 1995 for the investing and financing
activities discussed above were the cash flows provided by operating
activities, the $20,000 sale of properties discussed above, $415,000 of
borrowings on the Company's 1993 revolving line of credit and $250,000
of borrowings on the Company's 1995 revolving line of credit.
During fiscal 1996, the Company estimates it will incur
development costs of at least $800,000 related to the Company's proved
developed nonproducing and proved undeveloped oil and gas properties.
This estimated amount is somewhat uncertain at this time because the
Company could, relatively quickly, decide to either increase or reduce
the level of horizontal drilling contemplated for 1996. Other planned
expenditures for 1996 consist of delay rentals and other exploration
costs of approximately $100,000. Capital expected to be used for 1996
principal payments required under existing debt agreements totals
$512,000.
Management expects to continue to evaluate possible future
purchases of additional producing oil and gas properties and the further
development of currently owned properties. Management believes the
Company's long-term cash requirements for such investing activities and
the repayment of long-term debt can be met by the continued future cash
flows from operations, the remaining available $750,000 of the
$1,000,000 line of credit established in 1995 and, if necessary,
possible 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
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following sets forth certain information concerning each
director and executive officer of the Company:
Position(s) with Period of Service as
Name and Age the Company a Director or Officer
Rollin C. Vickers Chairman of the Since 1958
Age: 71 Board
Jeffrey P. Vickers President and Since 1982
Age: 43 Director
Thomas F. Neubauer Vice President Since June, 1992
Age: 61 of Leonardite
Operations
Cathy Callahan Kruse Secretary Since October, 1981;
Age: 41 Treasurer October, 1981 to May,
1985 and since June,
1990
H. Dennis Hoffelt Director From 1967 through June,
Age: 54 1986; and since June, 1987
Jeff Greek Director 1989 and since August,
Age: 36 1991
Patrick M. Montalban Director Since August, 1991
Age: 39
All of the directors' terms expire at the next annual meeting
of shareholders or when their successors have been elected and
qualified. The executive officers of the Company serve at the
discretion of the Board of Directors.
Rollin C. Vickers holds a Bachelor of Arts degree (Geology -
1950) from Cornell University, a Master of Science degree (Geology -
1952) from Syracuse University and a Doctor of Science degree (Economic
Geology and Mining - 1957) from the University of Wisconsin. Dr.
Vickers has served as Chairman of the Board of the Company since 1958.
Jeffrey P. Vickers received a Bachelor of Science degree in
Geological Engineering with a Petroleum Engineering option from the
University of North Dakota in 1978. Prior to obtaining his degree, Mr.
Vickers served two years overseas with the U.S. Army. In 1979, Mr.
Vickers joined Amerada Hess Corporation as an Associate Petroleum
Engineer in the Williston Basin. In 1981, Mr. Vickers was employed by
the Company as the Drilling and Production Manager where he was
responsible for providing technical assistance and supervision of
drilling and production operations and generated development drilling
programs. He became President of the Company on January 1, 1983. In
June, 1982, Mr. Vickers became a director of the Company.
Thomas F. Neubauer is Vice President of Leonardite Operations
and plant manager of the Company. Mr. Neubauer has been employed by the
Company since July, 1965.
Cathy Callahan Kruse is Secretary, Treasurer and business
office manager of the Company. Ms. Kruse graduated from the Atlanta
College of Business in 1977 and was employed as a Legal Assistant for
four years prior to her employment with the Company in May, 1981.
H. Dennis Hoffelt has been President of Triangle Electric
Inc., Williston, North Dakota, an electrical contracting firm, for over
the past five years. He served as a director of the Company from 1967
through June of 1986 and was elected as a director again in 1987.
Jeff Greek received a Bachelor of Science, Business
Administration Degree in Accounting from the University of North Dakota
in 1981. He received his Certified Public Accountant certificate in
1981 and was employed by the Company from February, 1982 to April, 1990.
From April, 1991 to August, 1994 he was the Financial Accounting
Supervisor at Souris River Telecommunication Cooperative, Minot, North
Dakota. He is currently the financial consultant for Citrus Energy,
Castle Rock, Colorado.
Patrick M. Montalban has been a director of the Company since
1991. He is a Petroleum Geologist who graduated from the University of
Montana in 1981. Mr. Montalban is the Executive Vice President and
Chief Operating Officer of MSR Exploration Ltd., a company with a class
of equity securities registered under the Securities Exchange Act of
1934, for over the past five years.
Jeffrey P. Vickers is the son of Rollin C. Vickers. Cathy
Callahan Kruse, Secretary and Treasurer of the Company, is the sister-
in-law of Jeffrey P. Vickers. No other family relationship exists
between or among any of the above named persons. Except for Mr.
Montalban, no officer or director is a director of any other company
having a class of equity securities registered under the Securities Act
of 1934, as amended, or any company registered as an investment company
under the Investment Company Act of 1940, as amended. There are no
arrangements or undertakings between any of the named directors and any
other persons pursuant to which any director was selected as a director
or was nominated as a director. Based solely upon a review of Forms 3,
4 and 5 furnished to the Company no officer or director failed to file
any of the above forms on a timely basis.
ITEM 11. EXECUTIVE COMPENSATION
The following table presents the aggregate compensation which
was earned by the Chief Executive Officer for each of the past three
years. No employee of the Company earned total annual salary and bonus
in excess of $100,000. There has been no compensation awarded to,
earned by or paid to any employee required to be reported in any table
or column in any fiscal year covered by any table, other than what is
set forth in the following table.
SUMMARY COMPENSATION TABLE
Long Term Compensation
Annual Compensation Awards Payouts
All
Other Restricted Other
Name and Annual Stock LTIP Compen-
Principal Salary Bonus Compen- Award(s) Options Payouts sation
Position Year ($) ($) sation ($) SARs(#) ($) ($)
Jeffrey 1995 $74,659 -0- -0- $925 35,000 N/A $7,566
P. 1994 $73,929 -0- -0- N/A -0- N/A $2,343
Vickers 1993 $71,700 -0- -0- $18,000 -0- N/A $3,500
CEO
In the table above, the column titled "Restricted Stock
Awards" is comprised of a 1995 grant of 1,000 shares of common stock
from the Registrant to each full-time employee, including Mr. Vickers.
The 1993 Restricted Stock Awards (24,000 shares of common stock) is
compensation from the Registrant for accrued unpaid vacation through
December 31, 1992. All of the Restricted Stock Awards are "restricted
securities" as defined in Rule 144 adopted under the Securities Act of
1933. The column titled "All Other Compensation" is comprised entirely
of profit sharing amounts.
If the Company achieves net income in a fiscal year, the Board
of Directors may determine to contribute an amount based on the
Company's profits to the Employees' Profit Sharing Plan and Trust
adopted in December, 1978 (the "Profit Sharing Plan"). An eligible
employee may be allocated from 0% to 15% of his compensation depending
upon the total contribution to the plan. A total of 20% of the amount
allocated to an individual vests after three years of service, 40% after
four years, 60% after five years, 80% after six years and 100% after
seven or more years. On retirement, an employee is eligible to receive
the vested amount. On death, 100% of the amount allocated to an
individual is payable to the employee's beneficiary. The Company
accrued a $35,000 contribution for 1995 with contributions for 1994 and
1993 being $10,000 each. As of December 31, 1995, before earnings and
the 1995 contribution, vested amounts in the Profit Sharing Plan for all
officers as a group were approximately $299,611.
Aggregated Option/SAR Exercises in last Fiscal Year
and FY-End Option/SAR Values
Value of
Number of Unexercised
Unexercised In-the-Money
Options/SARs Options/SARs
Shares at FY-End(#) at FY-End($)
Acquired on Value Exercisable/ Exercisable/
Name Exercise(#) Realized($) Unexercisable Unexercisable
Jeffrey P.
Vickers, CEO -0- -0- 35,000/0 $7,875/0
At the 1993 Annual Meeting of Shareholders, the Company's 1993
Employees' Incentive Stock Option Plan (the "Plan") was approved by
shareholders. The purpose of the plan is to enable the Corporation to
attract persons of training, experience and ability to continue as
employees, and to furnish additional incentive to such persons, upon
whose initiative and efforts the successful conduct and development of
the business of the Corporation largely depends, by encouraging such
persons to become owners of the common stock of the Corporation.
The term of the Plan expires February 17, 2003, ten years from
the date the Plan was approved by the Board of Directors. If within the
duration of an option; there shall be a corporate merger consolidation,
acquisition of assets, or other reorganization; and if such transaction
shall affect the optioned stock, the optionee shall thereafter be
entitled to receive upon exercise of his option those shares or
securities that he would have received had the option been exercised
prior to such transaction and the optionee had been a stockholder of the
Corporation with respect to such shares.
The Plan is administered by the Board of Directors. The
exercise price of the common stock offered to eligible participants
under the Plan by grant of an option to purchase common stock may not be
less than the fair market value of the common stock at the date of
grant; provided, however, that the exercise price shall not be less than
110% of the fair market value of the common stock on the date of grant
in the event an optionee owns 10% or more of the common stock of the
Corporation. A total of 300,000 shares has been reserved for issuance
pursuant to options to be granted under the Plan.
DIRECTORS' COMPENSATION
With the exception of Rollin C. Vickers and Jeffrey P.
Vickers, directors were paid $150 per Board meeting attended during
1995. The officers of the Company who are also directors receive no
additional compensation for attendance at Board meetings.
ITEM 12. PRINCIPAL SHAREHOLDERS AND MANAGEMENT SHAREHOLDERS
The following table sets forth the number of shares of common
stock beneficially owned by each officer, director and nominee for
director of the Company and by all directors and officers as a group, as
of March 1, 1996. 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 299,234-Direct and 7.4%
$.01 par value Indirect(a)
Common Stock, Rollin C. Vickers 191,767-Direct and 4.7%
$.01 par value Indirect(b)
Common Stock, Cathy Kruse 14,950-Direct(d) (c)
$.01 par value
Common Stock, Thomas F. Neubauer 11,000-Direct(e) (c)
$.01 par value
Common Stock, H. Dennis Hoffelt 39,000-Direct and (c)
$.01 par value Indirect(f)
Common Stock, Jeff Greek 2,000-Direct (c)
$.01 par value
Common Stock, Officers and 557,951-Direct and 13.7%
$.01 par value Directors as Indirect
a Group- (a)(b)(c)(d)(e)(f)
(seven persons)
(a) Included in the 299,234 shares listed for Jeffrey P. Vickers are
134,634 shares owned directly by him, 2,500 in a self-directed
individual retirement account, 70,000 shares held jointly with his
wife, Nancy J. Vickers, 25,500 shares held directly by his wife,
1,300 shares in his wife's self-directed individual retirement
account, and an aggregate 30,300 shares held by him as custodian
for his three minor children. Also included are 35,000 shares
which may be purchased by Mr. Vickers under presently exercisable
stock options granted pursuant to the Company's 1993 Employees'
Incentive Stock Option Plan.
(b) Indicated amount include 55,000 shares held by R. C. Vickers,
34,000 shares held by his wife, Patricia Vickers and 100,267 shares
held by Vickers Foundation of which Mr. and Mrs. Vickers share
voting and investment powers. Mr. and Mrs. Vickers each disclaim
any power to vote or to direct the investment of the other's direct
shares. Also included are 2,500 shares which may be purchased by
Mr. Vickers under presently exercisable stock options granted
pursuant to the Company's 1993 Employees' Incentive Stock Option
Plan.
(c) Less than 1%.
(d) Included in the 14,950 are 5,000 shares which may be purchased by
Ms. Kruse under presently exercisable stock options granted
pursuant to the Company's 1993 Employees' Incentive Stock Option
Plan.
(e) Included in the 11,000 are 5,000 shares which may be purchased by
Mr. Neubauer under presently exercisable stock options granted
pursuant to the Company's 1993 Employees' Incentive Stock Option
Plan.
(f) Mr. Hoffelt has sole voting and investment power over 11,500 of
shares and has shared voting and investment powers over the
remaining 27,500.
The following table sets forth information concerning persons
known to the Company to be the beneficial owners of more than 5% of the
Company's outstanding common stock as of March 1, 1996.
Amount of
Class of Name and Shares and Nature of Percent
Securities Address of Person Beneficial Ownership of Class
Common Stock, Mountain States 687,600-Direct(a) 16.9%
$.01 par value Resources, Inc.
CBM Building
Box 250
Cut Bank, MT 59427
Common Stock, Jeffrey P. Vickers 299,234-Direct and 7.4%
$.01 par value 723 West 14th St. Indirect(b)
Williston, ND 58801
Common Stock, Paul Krile 207,500-Direct(c) 5.1%
$.01 par value P. O. Box 329
Sioux Rapids, IA 50585
(a) This information was obtained from previous Securities and Exchange
Commission filings. Mountain States Resources, Inc. may be deemed
to share voting and investment powers over the above shares with
MSR Exploration, Ltd., the Canadian parent company of Mountain
States Resources, Inc. The Company has been informed that these
shares were sold several months ago to Joseph Montalban, former
President of Mountain States Resources, Inc. However, the Company
has not received a Form 3 or a Schedule 13D required to be filed
under the Securities Exchange Act of 1934 relating to this sale.
Joseph Montalban is the father of Patrick Montalban, a director of
the Company.
(b) See footnote (a) of the immediately preceding table.
(c) This information was obtained from a Securities and Exchange
Commission filing.
No arrangements are known by the Company which could, at a
subsequent date, result in a change in control of the Company.
Other than as set forth above in footnote (a), the Company is
not aware of any officer, director or holder of greater than 10% of the
Company's common stock who has failed to file the required SEC Forms 3,
4 or 5 on a timely basis for 1995.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
There are no transactions or series of similar transactions
since the beginning of the Company's last fiscal year or any currently
proposed transaction or series of similar transactions to which the
Company was or is to be a party, and which the amount involved exceeds
$10,000 and in which any director, executive officer, principal
shareholder or any member of their immediate family had or will have a
direct or indirect material interest.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Documents filed as Part of this Report
(1) Financial Statements and Schedules See "Index to
Consolidated Financial Statements and Supplementary
Data" on next page. There are no financial
statement schedules filed herewith.
(2) Disclosures About Oil and Gas Producing Activities -
Unaudited See "Index to Consolidated Financial
Statements and Supplementary Data" on next page.
(3) Exhibits See "Exhibit Index" on page 50.
(a) Exhibits
Exhibit 27. Financial Data Schedule
(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 26
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated balance sheets 27
Consolidated statements of operations 28
Consolidated statements of stockholders' equity 29
Consolidated statements of cash flows 30 - 31
Notes to consolidated financial statements 32 - 44
UNAUDITED SUPPLEMENTARY INFORMATION - Disclosures about
oil and gas producing activities 45 - 48
WILLIAMS, RICHEY & CO.
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, 1995 and
1994, and the related consolidated statements of operations,
stockholders' equity, and cash flows for the years ended December
31, 1995, 1994 and 1993. 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,
1995 and 1994, and the results of its operations and its cash flows
for the years ended December 31, 1995, 1994 and 1993, in conformity
with generally accepted accounting principles.
As discussed in Note A, the Company changed its method of
accounting for income taxes during 1993.
/s/ Williams, Richey & Co.
Denver, Colorado
February 16, 1996
A PROFESSIONAL CORPORATION OF CERTIFIED PUBLIC ACCOUNTANTS AND CONSULTANTS
950 SOUTH CHERRY STREET; SUITE 918; DENVER, CO 80222
PHONE 303/759-3773; FAX 303/759-1168
GEORESOURCES, INC., AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1995 AND 1994
ASSETS
CURRENT ASSETS: 1995 1994
Cash and equivalents $ 392,078 $ 222,677
Trade receivables, net 590,330 493,595
Inventories 285,018 246,467
Prepaid expenses 17,460 17,273
Investments 10,119 20,972
Total current assets 1,295,005 1,000,984
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, using the
full cost method of accounting:
Properties being depleted 15,272,170 14,105,349
Properties not being depleted 88,759 134,330
Leonardite plant and equipment 3,199,797 3,173,533
Other 672,546 669,308
19,233,272 18,082,520
Less accumulated depreciation, depletion
and valuation allowance (14,045,602) (13,444,512)
Net property, plant and equipment 5,187,670 4,638,008
OTHER ASSETS:
Mortgage loans receivable, related party 103,321 103,321
Other 104,289 54,041
207,610 157,362
$ 6,690,285 $ 5,796,354
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 856,823 $ 663,487
Current maturities of long-term debt 511,594 385,219
Accrued expenses 98,537 39,064
Total current liabilities 1,466,954 1,087,770
LONG-TERM DEBT, less current maturities 958,330 787,035
DEFERRED INCOME TAXES 151,000 123,000
COMMITMENTS AND CONTINGENCIES (NOTES H AND I)
STOCKHOLDERS' EQUITY:
Common stock, par value $.01 per share;
authorized 10,000,000 shares; issued
and outstanding, 4,035,714 and
4,023,214 shares, respectively 40,357 40,232
Additional paid-in capital 803,807 792,369
Retained earnings 3,269,837 2,965,948
Total stockholders' equity 4,114,001 3,798,549
$ 6,690,285 $ 5,796,354
The accompanying notes are an integral part of these consolidated
financial statements.
GEORESOURCES, INC., AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
1995 1994 1993
OPERATING REVENUE:
Oil and gas sales $ 2,184,458 $ 1,688,559 $ 1,693,147
Leonardite sales 703,944 757,534 682,003
2,888,402 2,446,093 2,375,150
OPERATING COSTS AND EXPENSES:
Oil and gas production 950,116 968,977 875,367
Cost of leonardite sold 559,659 585,217 542,199
Depreciation and depletion 601,814 470,075 622,504
Write-down of oil and gas properties -- -- 1,415,000
Selling, general and administrative 341,008 308,380 308,125
2,452,597 2,332,649 3,763,195
Operating income (loss) 435,805 113,444 (1,388,045)
OTHER INCOME (EXPENSE):
Interest expense (128,689) (103,328) (93,392)
Interest income 10,808 15,741 8,601
Other income and losses, net 13,965 22,266 15,146
(103,916) (65,321) (69,645)
Income (loss) before income taxes
and cumulative effect of a change
in accounting principle 331,889 48,123 (1,457,690)
INCOME TAX EXPENSE 28,000 7,982 196,400
Income (loss) before cumulative
effect of a change in
accounting principle 303,889 40,141 (1,654,090)
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING FOR INCOME TAXES -- -- 577,000
Net income (loss) $ 303,889 $ 40,141 $(1,077,090)
EARNINGS PER SHARE:
Income (loss) from continuing
operations $ .08 $ .01 $ (.41)
Cumulative effect of change in
accounting principle -- -- .14
Net income (loss) $ .08 $ .01 $ (.27)
Weighted average number of shares
outstanding 4,025,234 4,023,214 3,990,614
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, 1995, 1994 AND 1993
Additional
Common Stock Paid-in
Shares Amount Capital
Balance, December 31, 1992 3,961,714 $ 39,617 $ 747,080
Exercise of stock options 10,000 100 7,700
Issuance of common stock
in exchange for vacation
compensation 31,500 315 23,310
Treasury stock purchases -- -- --
Treasury stock contributed
to profit sharing plan -- -- (1,146)
Exchange of common
stock for interest in
subsidiary 20,000 200 15,425
Net loss -- -- --
Balance, December 31, 1993 4,023,214 40,232 792,369
Net income -- -- --
Balance, December 31, 1994 4,023,214 40,232 792,369
Issuance of common stock
as compensation 12,500 125 11,438
Net income -- -- --
Balance, December 31, 1995 4,035,714 $ 40,357 $ 803,807
The accompanying notes are an integral part of these consolidated
financial statements.
GEORESOURCES, INC., AND SUBSIDIARY
STATEMENTS OF STOCKHOLDERS' EQUITY (Continued)
YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
Retained Treasury Stock
Earnings Shares Amount Total
Balance, December 31, 1992 $ 4,002,897 -- $ -- $4,789,594
Exercise of stock options -- -- -- 7,800
Issuance of common stock
in exchange for vacation
compensation -- -- -- 23,625
Treasury stock purchases -- 35,000 (25,208) (25,208)
Treasury stock contributed
to profit sharing plan -- (35,000) 25,208 24,062
Exchange of common
stock for interest in
subsidiary -- -- -- 15,625
Net loss (1,077,090) -- -- (1,077,090)
Balance, December 31, 1993 2,925,807 -- -- 3,758,408
Net income 40,141 -- -- 40,141
Balance, December 31, 1994 2,965,948 -- -- 3,798,549
Issuance of common stock
as compensation -- -- -- 11,563
Net income 303,889 -- -- 303,889
Balance, December 31, 1995 $ 3,269,837 -- $ -- $4,114,001
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, 1995, 1994 AND 1993
1995 1994 1993
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 303,889 $ 40,141 $(1,077,090)
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation, depletion and
valuation allowance 601,814 470,075 2,037,504
Deferred income taxes 28,000 7,982 (383,982)
Other 13,889 5,717 6,782
Changes in assets and liabilities:
Decrease (increase) in:
Trade receivables (96,735) (124,445) 63,195
Inventories (38,551) 81,299 (58,149)
Prepaid expenses and other 10,666 11,650 (23,406)
Income tax receivable -- 18,000 (18,000)
Increase (decrease) in:
Accounts payable (78,831) 135,428 (48,557)
Accrued expenses 59,473 12,089 (11,193)
Net cash provided by operating
activities 803,614 657,936 487,104
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition of subsidiary -- -- (9,984)
Additions to property, plant and equipment (899,677) (646,571) (395,367)
Purchase of investments and mortgage loans
receivable -- (18,943) (103,487)
Proceeds from sale of property and equipment 20,234 143,385 --
Other (47,215) (19,047) --
Net cash used in investing activities (926,658) (541,176) (508,838)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term borrowings 665,000 100,000 263,292
Principal payments on long-term debt (367,330) (319,215) (317,920)
Debt issue costs (5,225) -- --
Purchase of treasury stock -- -- (25,208)
Issuance of common stock -- -- 7,800
Net cash provided by (used in)
financing activities 292,445 (219,215) (72,036)
NET INCREASE (DECREASE) IN CASH
AND EQUIVALENTS 169,401 (102,455) (93,770)
CASH AND EQUIVALENTS, beginning of year 222,677 325,132 418,902
CASH AND EQUIVALENTS, end of year $ 392,078 $ 222,677 $ 325,132
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, 1995, 1994 AND 1993
1995 1994 1993
SUPPLEMENTAL DISCLOSURE OF
CASH FLOW INFORMATION
Cash paid (received) for:
Interest $ 127,990 $ 102,258 $ 93,622
Income taxes 336 (483) 3,382
NONCASH INVESTING AND FINANCING ACTIVITIES
During 1995, the Company issued as compensation 12,500 shares of
common stock valued at $11,563.
During 1994, the Company forgave approximately $24,500 of
accounts receivable as partial consideration of the purchase
price of various oil and gas assets.
During 1993, the Company issued 31,500 shares of common stock
valued at $23,625 in exchange for accrued vacation compensation
payable to officers of the Company.
The Company contributed 35,000 shares of treasury common stock
valued at $24,062 to the profit sharing plan during 1993.
During 1993, the Company acquired a 59% interest in Belmont
Natural Resource Company, Inc., of which 21% was acquired when
the Company issued 20,000 shares of its common stock valued at
$15,625 in exchange for 70,000 shares of Belmont Natural Resource
Company, Inc.
The accompanying notes are an integral part of these consolidated
financial statements.
A. SIGNIFICANT ACCOUNTING POLICIES:
Operations and Principles of Consolidation
The accompanying consolidated financial statements include the
accounts of both GeoResources, Inc., and its subsidiary, Belmont
Natural Resource Company, Inc. All material intercompany
transactions and balances between the entities have been
eliminated.
GeoResources, Inc. (the "Company") is primarily involved in oil
and gas exploration 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. Belmont Natural
Resource Company, Inc., ("BNRC") was incorporated in 1991 to
exploit natural gas opportunities in the Pacific Northwest.
The Company acquired its initial interest in BNRC effective on
July 30, 1993, for $9,984 cash and 20,000 shares of
GeoResources, Inc. common stock valued at $15,625. The
acquisition was accounted for as a purchase and BNRC's results
of operations from July 30, 1993 to December 31, 1993, and for
the years ended December 31, 1995 and 1994, are included in the
accompanying statements of operations. Since the initial
acquisition, the Company has provided additional funding to BNRC
of approximately $108,000. As a result, the Company has earned
additional shares of BNRC stock and as of December 31, 1995,
owns 78% of the stock of BNRC. The Company has the right, but
is not obligated, to acquire additional shares of BNRC stock, up
to a maximum ownership of 82%, by providing additional funding
to BNRC of approximately $52,000.
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.
Estimates are used when accounting for the allowance for
doubtful accounts, depreciation, depletion and amortization,
impairment of long-lived assets, income taxes, contingencies,
unaudited oil and gas reserve quantities and the standardized
measure of discounted future net cash flows.
A. SIGNIFICANT ACCOUNTING POLICIES (Continued):
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 options related to crude oil.
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 purchases crude oil options and options
to acquire crude oil futures contracts. The options are used to
hedge a portion of anticipated oil sales during the next year
against the risk of possible decreases of crude oil prices. The
options are accounted for as hedges and, accordingly, gains and
losses are deferred until the anticipated sales occur. At
December 31, 1995 and 1994, the market value of options
outstanding was $2,911 and $15,700, respectively.
Oil and Gas Properties
The Company utilizes the full cost method of accounting for its
oil and gas properties. All costs incurred in the acquisition,
exploration and development of oil and gas properties (including
costs of abandoned leaseholds, delay lease rentals, dry hole
costs, geological and geophysical costs and certain internal
costs associated directly with acquisition, exploration and
development activities) are capitalized. These costs are
subject to a "ceiling" limitation based upon the estimated value
of the Company's properties which is determined in accordance
with rules prescribed by the Securities and Exchange Commission
("SEC").
A. SIGNIFICANT ACCOUNTING POLICIES (Continued):
Oil and Gas Properties (Continued)
In the fourth quarter of 1993, the selling prices of the
Company's oil and gas products declined significantly, reaching
essentially their lowest point of the year on December 31, 1993.
As a result, the net capitalized costs of the Company's oil and
gas properties exceeded their estimated value based upon the
prescribed cost "ceiling" limitation as determined using
December 31, 1993 prices. Consequently, in 1993, the Company
recognized a charge to operations of $1,415,000, or $0.35 per
share, to reduce the net capitalized costs to the cost "ceiling"
amount. During 1995 and 1994, oil selling prices increased
somewhat from their December 31, 1993 levels and, accordingly,
the estimated value of the Company's oil and gas assets also
increased and exceeded net capitalized costs at December 31,
1995 and 1994. However, in accordance with the SEC rules, no
recovery of previously recognized write-downs is permitted.
Depletion of capitalized costs is computed on a country-by-
country basis using a composite unit-of-production method over
the estimated productive life of all the reserves related to the
cost center. The Company presently has only one cost center
since all of its properties are located in the United States.
The Company's oil and gas depreciation, depletion and
amortization rate per equivalent barrel of oil produced was
$3.09, $2.51, and $3.92 for 1995, 1994, and 1993, respectively.
Costs not being depleted at December 31, 1995, consist of the
unevaluated, unimpaired cost of undeveloped oil and gas
properties which were acquired during the following years:
1995 $ 8,375
1994 33,535
1993 16,900
1992 16,735
1991 and prior 13,214
Total $ 88,759
It is expected that evaluation of the above properties will
occur primarily over the next four years.
Gains or losses are not recognized upon the sale or other
disposition of oil and gas properties, except in extraordinary
transactions.
A. SIGNIFICANT ACCOUNTING POLICIES (Continued):
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 is less than the carrying amount of the
asset. No impairment losses have been recognized on long-lived
assets (other than oil and gas properties) for the years ended
December 31, 1995, 1994 and 1993.
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.
Stock-Based Compensation
In 1996, the Company will adopt SFAS No. 123, "Accounting for
Stock-Based Compensation." This standard establishes a fair
value method of accounting for stock-based compensation plans
either through recognition or disclosure. The Company intends
to adopt this standard by disclosing the proforma net income and
earnings per share amounts assuming the fair value method was
adopted January 1, 1995. The adoption of this standard will not
impact the Company's financial position, results of operations
or cash flows.
Income Taxes
Effective January 1, 1993, the Company adopted the provisions of
Statement of Financial Accounting Standards No. 109, Accounting
for Income Taxes (SFAS 109). Previously the provision for
income taxes was accounted for in accordance with SFAS 96. The
cumulative effect of this accounting change was a tax benefit of
$577,000 reflected as income in 1993. There was no effect on
the pre-tax loss from continuing operations.
A. SIGNIFICANT ACCOUNTING POLICIES (Continued):
Income Taxes (Continued)
Under SFAS 109, income taxes are provided for the tax effects of
transactions reported in the financial statements and consist of
taxes currently due plus deferred taxes related primarily to
differences between the financial and tax bases of oil and gas
properties and other property and equipment. The deferred taxes
represent the future tax return consequences of those
differences, which will either be taxable or deductible when the
assets and liabilities are recovered or settled. A valuation
allowance is provided for deferred tax assets not expected to be
realized.
The Company and BNRC file separate income tax returns with
income tax provision and liability computed on a separate return
basis.
Net Income Per Share of Common Stock
Net income per share has been computed based on the weighted
average number of common shares outstanding. The assumed
exercise of stock options is not included because the effect
would not be significant.
B. INDUSTRY SEGMENTS AND MAJOR CUSTOMER:
Segment information
The Company conducts all of its operations within the United
States, which consist principally of oil and gas exploration and
production and the mining and processing of leonardite. There
are no sales or other transactions between these two business
segments. Presented below is information concerning the
Company's business segments for the years ended December 31,
1995, 1994 and 1993:
1995 1994 1993
Revenue:
Oil and gas $ 2,184,458 $ 1,688,559 $ 1,693,147
Leonardite 703,944 757,534 682,003
$ 2,888,402 $ 2,446,093 $ 2,375,150
B. INDUSTRY SEGMENTS AND MAJOR CUSTOMER (Continued):
Segment information (Continued)
1995 1994 1993
Operating income:
Oil and gas $ 758,866 $ 367,669 $(1,104,005)
Leonardite 10,657 46,041 14,655
General corporate activities (333,718) (300,266) (298,695)
$ 435,805 $ 113,444 $(1,388,045)
Depreciation and depletion:
Oil and gas $ 475,476 $ 351,913 $ 506,785
Leonardite 111,958 105,590 103,403
General corporate activities 14,380 12,572 12,316
$ 601,814 $ 470,075 $ 622,504
Identifiable assets, net:
Oil and gas $ 4,110,608 $ 3,335,013 $ 3,208,824
Leonardite 1,552,442 1,600,094 1,669,223
General corporate activities 1,027,235 861,247 978,349
$ 6,690,285 $ 5,796,354 $ 5,856,396
Capital expenditures incurred:
Oil and gas $ 1,162,393 $ 634,914 $ 476,927
Leonardite 26,264 17,199 17,755
General corporate activities 4,095 11,011 2,918
$ 1,192,752 $ 663,124 $ 497,600
Major Customer and Concentrations of Credit Risk
Sales to a major oil and gas customer were 53%, 46% and 43% of
total revenue for the years ended December 31, 1995, 1994 and
1993, respectively.
A substantial majority of the oil and gas accounts receivable
at December 31, 1995 and 1994 were due from this major
customer.
The Company has one bank account with a balance of
approximately $252,000 and $138,000, at December 31, 1995 and
1994, respectively. This account is federally-insured for
balances up to $100,000.
C. TRADE RECEIVABLES AND INVENTORIES:
Trade receivables at December 31, 1995 and 1994 are comprised of
the following:
1995 1994
Oil and gas purchasers $ 426,463 $ 332,699
Leonardite customers 175,283 172,312
601,746 505,011
Less allowance for
doubtful accounts (11,416) (11,416)
$ 590,330 $ 493,595
As of December 31, 1995 and 1994, inventories by major classes
are comprised of the following:
1995 1994
Crude oil $ 21,222 $ 22,123
Leonardite inventories:
Finished products 73,937 50,189
Raw materials 111,342 115,661
Materials and supplies 78,517 58,494
Total leonardite inventories 263,796 224,344
$ 285,018 $ 246,467
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 15% per annum with principal due January 1996.
Presently, the Company has reduced this interest rate to 8% and
intends to extend the principal due date until the residence is
sold. The Company received interest income from these loans of
$8,100, $8,775 and none, for the years ended December 31, 1995,
1994 and 1993, respectively.
E. LONG-TERM DEBT:
Long-term debt at December 31, 1995 and 1994 consists of the
following loans which are all with one bank:
1995 1994
Bank, prime plus 1% (9.5% total rate at
December 31, 1995), due in monthly
installments of $18,750 plus interest,
due January 1997, collateralized by oil
and gas properties $ 225,000 $ 450,000
Bank, prime plus 1% (9.5% total rate at
December 31, 1995), due in monthly
installments of $7,600 plus interest,
due January 1997, collateralized by
leonardite plant and equipment 272,497 363,697
Bank, prime plus 1% (9.5% total rate at
December 31, 1995), due in monthly
installments of $16,000 plus interest,
due September 1999, collateralized by
oil and gas properties 717,000 350,000
Bank, $1,000,000 revolving line of credit,
interest payable monthly at prime plus 1%,
not to exceed 10.5% (9.5% total rate at
December 31, 1995), expires September 1, 1998.
Outstanding balance to be converted on that
date to a 4-year term loan due September 1,
2002. Collateralized by oil and gas
properties 250,000 --
Bank, due in variable monthly installments
including interest at prime plus 1% (9.5%
total rate at December 31, 1995), due May
1997, collateralized by a vehicle 5,427 8,557
Total long-term debt 1,469,924 1,172,254
Less current maturities (511,594) (385,219)
Long-term debt, less current
maturities $ 958,330 $ 787,035
E. LONG-TERM DEBT (Continued):
Aggregate maturities required on long-term debt at December 31,
1995, are as follows:
Year Ending December 31:
1996 $ 511,594
1997 375,330
1998 207,625
1999 203,500
2000 62,500
Remainder 109,375
$1,469,924
The Company's borrowing base for debt secured by oil and gas
properties is limited by the net present value of future oil and
gas production of the properties as determined annually by the
bank.
The Company's long-term debt was obtained pursuant to financing
agreements which include the following covenants: Maintain a
current ratio of not less than 1.25 to 1 exclusive of current
maturities of long-term debt; maintain debt to tangible net
worth of not more than 1.5 to 1; maintain a net worth of at
least $3,500,000; not encumber any of its assets; restricts
borrowings from, and credit extensions to, other parties;
restricts reorganization or mergers in which the Company is not
the surviving corporation; and not pay cash dividends without
the bank's consent.
F. INCOME TAXES:
The components of income tax expense for the years ended
December 31, 1995, 1994 and 1993, are as follows:
1995 1994 1993
Current tax expense $ -- $ -- $ 3,400
Deferred tax expense (benefit) 95,000 6,982 (676,000)
Increase (decrease) in deferred
tax assets valuation allowance (67,000) 1,000 869,000
$ 28,000 $ 7,982 $ 196,400
F. INCOME TAXES (Continued):
During the fourth quarter of 1993, the Company recorded a
deferred tax benefit of $676,000 related to the determination of
(1) an increase in its gross deferred tax assets primarily
caused by additional net operating loss and statutory depletion
carryforwards generated in 1993, and (2) a reduction of its
gross deferred tax liabilities primarily caused by a reduction
in the temporary differences between the financial and tax bases
of oil and gas properties. Also during the fourth quarter of
1993, due to the low oil prices in effect at the time,
management determined that the future realization of an
dditional $869,000 of its deferred tax assets was no longer
assured and, accordingly, increased the valuation allowance by
that amount.
During 1994, there was no significant change in the Company's
total gross deferred tax assets, the valuation allowance or
deferred tax liabilities.
During 1995, the Company recorded a deferred tax expense of
$95,000 related primarily to net income which is not currently
taxable due to the utilization of net operating loss
carryforwards. The Company also decreased the deferred tax
asset valuation allowance by $67,000 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, 1995 and 1994, are as
follows:
1995 1994
Deferred Tax Assets:
Net operating loss carryforward $ 293,000 $ 359,000
Statutory depletion carryforward 928,000 917,000
Investment tax credit carryforward 283,000 307,000
Other 44,000 45,000
1,548,000 1,628,000
Valuation Allowance:
Beginning of year (976,000) (975,000)
(Increase) decrease 67,000 (1,000)
End of year (909,000) (976,000)
Deferred Tax Liabilities:
Accumulated depreciation and
depletion (790,000) (775,000)
Net Deferred Tax Liability, long-term $ (151,000) $ (123,000)
F. INCOME TAXES (Continued):
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, 1995, 1994 and 1993 is as follows:
1995 1994 1993
Income tax expense (benefit)
at statutory rate 35% 35% (34)%
Loss carryover benefits (14) -- (12)
Change in valuation allowance (21) 2 60
Graduated tax rate difference -- (20) --
State income taxes and other 8 -- --
8% 17% 14%
For income tax purposes, the Company has a statutory depletion
carryover of approximately $2,790,000 which, subject to certain
limitations, may be utilized to reduce future taxable income.
This carryforward does not expire. The Company also has net
operating loss carryovers and investment tax credit carryovers
(accounted for using the flow-through method), which, if not
utilized, expire as follows:
Investment
Net operating tax credit
Year of expiration loss carryover carryover
1996 $ -- $ 57,000
1997 -- 181,000
1998-2000 -- 45,000
2001 428,000 --
2003 101,000 --
2008 115,000 --
2009 237,000 --
Total $ 881,000 $ 283,000
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. At December 31,
1995, options are outstanding to purchase 95,000 shares of
common stock at an exercise price of $1.15 per share through
November 3, 2000.
Profit-sharing plan
The Company has an Employee Profit-Sharing Plan covering all
employees who meet the eligibility requirements set forth in the
plan. Contributions to the plan are at the discretion of the
Board of Directors. Profit-sharing plan expense for the years
ended December 31, 1995, 1994 and 1993 was $35,000, $10,000, and
$10,000, 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 the 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, 1995 and 1994:
1995 1994
Building and improvements $ 163,834 $ 163,834
Accumulated depreciation (39,180) (30,989)
$ 124,654 $ 132,845
The Company leases the remainder of the building to other
businesses under cancelable lease agreements. During 1995, 1994
and 1993, the Company received $19,500, $18,300, and $17,700,
respectively, in rental income from the building which is
included in other income in the accompanying statements of
operations.
J. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The carrying value of cash, trade receivables, mortgage loans
receivable, accounts payable, and long-term debt approximate
their fair value at December 31, 1995 and 1994.
K. FOURTH QUARTER ADJUSTMENT:
During the fourth quarter of 1995, the Company recognized
$205,207 of depreciation, depletion and amortization expense.
This was an increase of approximately $75,000 over the estimated
amounts recorded in each of the first three quarters.
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, 1995, 1994 and 1993:
1995 1994 1993
Properties being depleted $15,272,170 $14,105,349 $13,523,330
Unproved properties
not being depleted 88,759 134,330 246,358
Total 15,360,929 14,239,679 13,769,688
Less accumulated depreciation,
depletion and valuation allowance (11,793,289) (11,317,813) (10,965,900)
Net capitalized costs $ 3,567,640 $ 2,921,866 $ 2,803,788
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, 1995, 1994 and 1993:
1995 1994 1993
Property acquisition costs:
Proved $ 189,036 $ 115,193 $ 169,097
Unproved 15,479 40,786 35,710
Exploration costs 115,957 55,635 94,987
Development costs 841,921 423,300 177,133
$ 1,162,393 $ 634,914 $ 476,927
The Company's results of operations from oil and gas producing activities
are presented below for the years ended December 31, 1995, 1994 and 1993.
1995 1994 1993
Oil and gas sales $ 2,184,458 $ 1,688,559 $ 1,693,147
Production costs (950,116) (968,977) (875,367)
Depletion and depreciation (475,476) (351,913) (506,785)
758,866 367,669 310,995
Imputed income tax provision 26,000 -- --
$ 732,866 $ 367,669 $ 310,995
The above imputed income tax provision and results of operations are
determined without regard to the Company's deduction for general and
administrative expenses, interest costs and other items.
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, 1993, than at December 31, 1995
or 1994.
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, 1995, 1994 and 1993:
1995 1994 1993
Oil Gas Oil Gas Oil Gas
(bbl) (mcf) (bbl) (mcf) (bbl) (mcf)
Proved reserves,
beginning of
year 1,642,000 244,000 1,075,000 254,000 1,307,000 244,000
Purchases of
reserves-in-
place 67,000 -- 69,000 -- 31,000 --
Sales of reserves
-in-place -- -- (21,000) -- -- --
Extensions,
discoveries
and other
additions 448,000 1,000 454,000 2,000 -- --
Revisions of
previous
estimates 42,000 34,000 204,000 (3,000) (137,000) 27,000
Production (152,000) (13,000) (139,000) (9,000) (126,000) (17,000)
Proved reserves,
end of year 2,047,000 266,000 1,642,000 244,000 1,075,000 254,000
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)
1995 1,292,000 266,000
1994 1,192,000 244,000
1993 926,000 254,000
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, 1993,
are significantly lower than at December 31, 1995 or 1994. This is primarily
due to the low oil price in effect on December 31, 1993. 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, 1995, 1994 and 1993:
1995 1994 1993
Future cash inflows $ 30,628,000 $ 19,815,000 $ 9,951,000
Future production costs (13,369,000) (9,732,000) (5,562,000)
Future development costs (2,993,000) (1,439,000) (479,000)
Future income tax expense (3,423,000) (1,450,000) (145,000)
Future net cash flows 10,843,000 7,194,000 3,765,000
Less effect of a 10%
discount factor (4,381,000) (2,914,000) (1,397,000)
Standardized measure of
discounted future net
cash flows, end of year $ 6,462,000 $ 4,280,000 $ 2,368,000
The principal sources of change in the standardized measure of discounted
future net cash flows are as follows for the years ended December 31, 1995,
1994 and 1993:
1995 1994 1993
Standardized measure, beginning
of year $ 4,280,000 $ 2,368,000 $ 4,464,000
Sales of oil and gas produced, net
of production costs (1,234,000) (720,000) (818,000)
Net changes in prices and
production costs 2,256,000 1,384,000 (2,739,000)
Purchases of reserves-in-place 436,000 215,000 63,000
Sales of reserves-in-place -- (75,000) --
Extensions, discoveries and other
additions, less related costs 2,203,000 1,624,000 --
Revisions of previous quantity
estimates and other 599,000 946,000 (662,000)
Development costs incurred during
the year and changes in
estimated future development
costs (1,415,000) (936,000) 782,000
Accretion of discount 514,000 246,000 531,000
Net change in income taxes (1,177,000) (772,000) 747,000
Standardized measure, end of year $ 6,462,000 $ 4,280,000 $ 2,368,000
SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
GEORESOURCES, INC. (the "Registrant")
Dated: March 29, 1996 /s/ J. P. Vickers
J. P. Vickers, President
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
(Power of Attorney)
Each person whose signature appears below constitutes and appoints
J. P. VICKERS and DENNIS HOFFELT his true and lawful attorneys-in-fact and
agents, each acting alone, with full power of stead, in any and all
capacities, to sign any or all amendments to this Annual Report on Form 10-K
and to file the same, with all exhibits thereto, and other documents in
connection therewith, with the Securities and Exchange Commission, granting
unto said attorneys-in-fact and agents, each acting alone, full power and
authority to do and perform each and every act and thing requisite and
necessary to be done in and about the premises, as fully to all intents and
purposes as he might or could do in each acting alone, or his substitute or
substitutes, may lawfully do or cause to be done by virtue thereof.
Signatures Title Date
/s/ J. P. Vickers President (principal execu- 3/29/96
J. P. Vickers tive officer) and Director
/s/ R. C. Vickers Chairman of the Board 3/29/96
R. C. Vickers
/s/ Dennis Hoffelt Director 3/29/96
Dennis Hoffelt
/s/ Jeff Greek Director 3/29/96
Jeff Greek
/s/ Patrick M. Montalban Director 3/29/96
Patrick M. Montalban
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 1995 fiscal year.
Page Number
in Sequential
Numbering of all
Form 10-K and
Exhibit Exhibit Pages
3.1 Registrant's Bylaws, as amended, November 30, 1994 *
3.2 Registrant's Articles of Incorporation, as amended to
date, incorporated by reference to Exhibit 3.1 of the
Registrant's Form 10-K for fiscal year, 1983 *
10.1 Mining Lease and Agreement dated April 6, 1988, by and
between Roger C. Ryan, Susan Ryan, Constance Ryan,
Charlotte McConnell and Joseph W. Ryan as Lessors, and
GeoResources, Inc. as Lessee incorporated by reference
to Exhibit 10.4 of Registrant's Form 10-Q for fiscal
quarter ended March 31, 1988 *
10.2 Credit Agreement dated January 24, 1989, by and between
GeoResources, Inc. and Norwest Bank Billings, incorporated
by reference to Exhibit 10.25 of the Registrant's Form
10-K for fiscal year, 1988 *
10.3 Promissory Note dated January 24, 1989, by and between
GeoResources, Inc., as Borrower and Norwest Bank
Billings, incorporated by reference to Exhibit 10.26
of the Registrant's Form 10-K for fiscal year, 1988 *
Page Number
in Sequential
Numbering of all
Form 10-K and
Exhibit Exhibit Pages
10.4 Combination Mortgage, Security Agreement and Fixture
Financing Statement dated January 24, 1989, by and
between GeoResources, Inc., as Mortgagor/Debtor and
Norwest Bank Billings, as Mortgagee/Secured party,
incorporated by reference to Exhibit 10.27 of the
Registrant's Form 10-K for fiscal year, 1988 *
10.5 Mortgage, Security Agreement, Assignment of Production
and Financing Statement dated January 24, 1989, by and
between GeoResources, Inc., as Mortgagor/Debtor and
Norwest Bank Billings, as Mortgagee/Secured party,
incorporated by reference to Exhibit 10.28 of the
Registrant's Form 10-K for fiscal year, 1988 *
10.6 Modification of Note of January 24, 1989, by and between
Norwest Bank Billings and GeoResources, Inc., effective
January 2, 1992, incorporated by reference to Exhibit 10.1
of the Registrant's Form 10-Q for fiscal quarter ended
March 31, 1992 *
10.7 License Agreement dated March 22, 1993, by and between
GeoResources, Inc. and Central Arizona Material Co.,
incorporated by reference to Exhibit 10.1 of the
Registrant's Form 10-Q for fiscal quarter ended
March 31, 1993 *
10.8 Secured Form Loan and Revolving Credit Agreement dated
April 29, 1993, by and between GeoResources, Inc. and
Norwest Bank Billings, incorporated by reference to
Exhibit 10.1 of the Registrant's Form 10-Q for fiscal
quarter ended June 30, 1993 *
10.9 Mortgage, Security Agreement, Assignment of Production
and Financing Statement dated April 29, 1993, by and
between GeoResources, Inc., as Mortgagor and Norwest
Bank Billings, as Mortgagee, incorporated by reference
to Exhibit 10.2 of the Registrant's Form 10-Q for fiscal
quarter ended June 30, 1993 *
10.10 The Registrant's 1993 Employees' Incentive Stock Option
Plan, incorporated by reference as Exhibit A to the
Registrant's definitive Proxy Statement dated May 5, 1993 *
Page Number
in Sequential
Numbering of all
Form 10-K and
Exhibit Exhibit Pages
10.11 Amended and Restated Secured Term Loan and Resolving
Credit Agreement made as of September 1, 1995, by and
between GeoResources, Inc. and Norwest Bank Montana *
10.12 First Amendment of Mortgage, Security Agreement,
Assignment of Production and Financing Statement and
Mortgage - Collateral Real Estate Mortgage dated
September 1, 1995, by and between GeoResources, Inc.
and Norwest Bank Montana *