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, 1996.
Transition Report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the transition period from ________ to ________.
Commission File Number - 0-8041
GeoResources, Inc.
(Exact name of Registrant as specified in its charter)
Colorado 84-0505444
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
1407 West Dakota Parkway, Suite 1-B 58801
Williston, North Dakota (Zip Code)
(Address of Principal executive offices)
(Registrant's telephone number including area code) (701) 572-2020
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $0.01
_____________________________
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes __X__ No _____
_____________________________
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. __X__
____________________________
The aggregate market value of the Common Stock (the only class of voting stock)
held by nonaffiliates of the Registrant as of March 24, 1997, was approximately
$8,402,428 (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, 1997: 4,060,714
______________________________________
Documents incorporated by reference - none
_______________________________________________________________________________
PART I.
ITEM 1. BUSINESS
General Development of Business
GeoResources, Inc. (the "Registrant" or the "Company") is a natural
resources company engaged principally in the following two business segments:
1) oil and gas exploration, development and production; and 2) mining of
leonardite (oxidized lignite coal) and manufacturing of leonardite based
products which are sold primarily as oil and gas drilling mud additives. The
Registrant was incorporated under Colorado law in 1958 and was originally
engaged in uranium mining. The Registrant built its first leonardite
processing plant in 1964 in Williston, North Dakota, and began participating
in oil and gas exploration and production in 1969. In 1982, the Registrant
completed construction of a larger leonardite processing plant in Williston
that is in use today. Financial information about the Registrant's two
industry segments is presented in Note B to the Financial Statements in Item
8 of this report.
Information contained in this Form 10-K contains forward-looking state-
ments within the meaning of the Private Securities Litigation Reform Act of
1995, which can be identified by the use of words such as "may," "will,"
"expect," "anticipate," "estimate" or "continue," or variations thereon or
comparable terminology. In addition, all statements other than statements of
historical facts that address activities, events or developments that the
Company expects, believes or anticipates, will or may occur in the future, and
other such matters, are forward-looking statements.
The future results of the Company may vary materially from those
anticipated by management, and may be affected by various trends and factors
which are beyond the control of the Company. These risks include the
competitive environment in which the Company operates, changing oil and gas
prices, the demand for oil, gas and leonardite, availability of drilling rigs,
dependence upon key management personnel and other risks described herein.
Oil and Gas Exploration, Development and Production
The Registrant's oil and gas exploration and production efforts are
concentrated on oil properties in the North Dakota and Montana portions of the
Williston Basin. The Registrant typically generates prospects for its own
exploitation, but when a prospect is deemed to have substantial risk or cost,
the Registrant may attempt to raise all or a portion of the funds necessary
for exploration or development through farmouts, joint ventures, or other
similar types of cost-sharing arrangements. The amount of interest retained by
the Registrant in a cost-sharing arrangement varies widely and depends upon
many factors, including the exploratory costs and the risks involved.
In addition to originating its own prospects, the Registrant
occasionally participates in exploratory and development prospects originated
by other individuals and companies. The Registrant also evaluates interests in
various proved properties to acquire for further operation and/or development.
The Registrant, where possible, supervises drilling and production
activities on new prospects and properties acquired. It does not own or have
any plans to acquire any rotary drilling equipment. Hence, the Registrant uses
independent drilling contractors for the drilling of wells of which it is the
operator. Thus, the Registrant's drilling activities can be subject to delays
caused by shortages of drilling equipment or other factors beyond its control,
including inclement weather.
As of December 31, 1996, the Registrant had developed oil and gas leases
covering approximately 12,114 net acres in Montana and North Dakota, and during
1996 sold an average 463 net equivalent barrels of oil per day from 90 gross
(62.87 net) producing wells located primarily in North Dakota.
The Registrant sells its crude oil to purchasers with facilities located
near the Registrant's wells. The Registrant's gas reserves are also contracted
to purchasers in the area near the Registrant's wells.
Mining and Manufacturing Leonardite Products
The Registrant operates a leonardite mine and processing plant in
Williston, North Dakota. Leonardite is mined from leased reserves and
processed to make a basic product that can be sold as is, or blended with
other substances to make several different dry, free flowing powders
primarily for the oil well drilling mud industry. Leonardite products act as
a dispersant or thinner, and provide filtration control when used as an
additive in drilling muds. Leonardite is also sold by the Registrant for use
in metal working foundries and in agricultural applications.
In 1996, the Company's leonardite products were sold primarily to
drilling mud companies located in coastal areas of the Gulf of Mexico. Demand
for the plant's output is governed mainly by the level of oil and gas drilling
activities, particularly in the gulf coast area, both onshore and offshore.
Drilling activity declined substantially in the mid 1980's and has remained
at relatively low levels for the past several years. The Registrant has no
significant supply contracts with individual customers.
Status of Products, Services or Industry Segments in Development
The Company owns 80% of the stock of Belmont Natural Resource Company,
Inc. (BNRC), a Washington corporation formed for the purpose of exploiting
natural gas opportunities in the Pacific Northwest. BNRC owns oil and gas
leases covering 6,713 gross acres (6,479 net) on a gas prospect located in the
State of Washington. Activities in 1996 consisted of a small amount of
geological field work in an effort to further define the prospect. The
Company does not expect to devote any substantial resources to this project
in 1997.
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 1997.
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 1996, Registrant sold its crude oil to 19 purchasers. Koch Oil
Company, Citation Oil & Gas Corp., and Rigel, Inc. were the major customers,
accounting for approximately 83%, 5%, and 2%, respectively, of the Registrant's
oil and gas revenue in 1996, which was approximately 65%, 4%, and 1%,
respectively, of the Registrant's total operating revenue. Management believes
there are other crude oil purchasers to whom the Company would be able to sell
its oil if it lost any of its current customers.
In 1996, the Registrant sold leonardite products to 43 customers. The
largest customer in 1996 for leonardite products made purchases that totaled 9%
of the Registrant's mining and manufacturing revenue, which was approximately
2% of the Registrant's total operating revenue.
Backlog Orders, Research and Development
The Registrant does not have any material long-term or short-term
contracts to supply leonardite products. All orders are reasonably expected to
be filled within three weeks of receipt. From time to time, the Registrant
enters into short-term contracts to deliver quantities of oil or gas; however,
no significant backlog exists. The Company's oil and gas division order
contracts and off lease marketing arrangements are typical of those in the
industry with 30 to 90 day cancellation notice provisions and generally do not
require long-term delivery of fixed quantities of oil or gas. The Registrant
has not spent any material time or funds on research and development, and does
not expect to do so in the foreseeable future.
Competition
Oil and Gas
In addition to being highly speculative, the oil and gas business is
intensely competitive among the many independent operators and major oil
companies in the industry. Many competitors possess financial resources and
technical facilities greater than those available to the Registrant and may,
therefore, be able to pay more for desirable properties or to find more
potentially productive prospects. However, management believes the Registrant
has the ability to obtain leasehold interests which will be sufficient to meet
its oil and gas needs in the foreseeable future.
Leonardite Products
Uses and specifications of leonardite-based drilling mud additives are
subject to change if better products are found. The Registrant's products
compete with leonardite and non-leonardite products used as additives in
numerous types of drilling mud. In addition, leonardite deposits are available
in other areas within the United States and competitors may be able to enter
the leonardite business with relative ease. At the present time, similar
products are marketed by other companies who mine, process and market
leonardite products. Competition lies primarily in delivery time, trans-
portation costs, quality of the product, performance of the product when used
in drilling mud and access to high-quality leonardite.
Environmental Regulations
All of the Registrant's operations are generally subject to federal,
state or local environmental regulations. The Registrant's oil and gas
business segment is affected particularly by those environmental regulations
concerned with the disposal of produced oilfield brines and other oil-related
wastes. The Registrant's leonardite mining and processing segment is also
subject to numerous state and federal environmental regulations, particularly
those concerned with air contaminant emission levels of the Company's
processing plant, and mine permit and reclamation regulations pertaining to
surface mining at the Company's leonardite mine. The Company believes that
maintenance of acceptable air contaminant emission levels at its processing
plant could become more costly in the future if plant production increases
substantially above 1996 levels. Management believes significantly higher
plant utilization would increase emission levels and could make it necessary
to replace or upgrade air quality control equipment. Future environmental
compliance costs that might be required to upgrade the equipment are not
known at this time.
Foreign Operations and Export Sales
The Registrant has no production facilities or operations in foreign
countries and has no direct export sales. Some of the Company's leonardite
products are sold to distributors in the United States who in turn export these
products.
Employees
As of March 15, 1997, the Registrant had 13 full-time employees.
ITEM 2. PROPERTIES
The Registrant's properties consist of four main categories: office,
leonardite plant and mine, oil and gas, and a nonproducing silver property.
Certain of these properties are mortgaged to the Company's bank. See Note 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
unaffiliated businesses.
Leonardite Plant and Mine
The site of the Registrant's leonardite plant covers approximately nine
acres located one mile east of Williston in Williams County, North Dakota.
This site and an additional 20 acres of undeveloped property are owned by the
Company. The plant has approximately 11,500 square feet of floor area
consisting of warehousing and processing space. Therein is equipment able to
process and ship approximately 3,000 tons of leonardite products per month.
Finished product leonardite sales for the past three years are shown below.
Finished Average
Products Sales Price
Year (Tons) Per Ton
1996 8,909 $ 94.49
1995 7,528 $ 93.51
1994 8,141 $ 93.05
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 16,520 gross
acres (12,114 net acres) as of March 15, 1997, 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**
1996 166,810 13,167 169,005 $17.67 $ 1.29 $ 6.40
1995 151,467 13,061 153,644 $14.24 $ 0.98 $ 6.18
1994 138,552 9,191 140,084 $12.08 $ 1.19 $ 6.92
_____________________________
*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, 1996, the Registrant's total gross and net produc-
tive wells were as follows:
Productive Wells*
Oil Gas
Gross Wells Net Wells Gross Wells Net Wells
96 66.80 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, 1997, 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 9,160 7,632 17,379 17,307 26,539 24,939
North Dakota 7,360 4,482 30,014 10,788 37,374 15,270
Washington 0 0 5,370 5,183 5,370 5,183
ALL STATES 16,520 12,114 52,763 33,278 69,283 45,392
_____________________________
*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
1996 0.00 0.08 0.67 0.00 0.75
1995 0.00 0.00 1.34 0.00 1.34
1994 0.00 0.00 2.00 0.00 2.00
Present Activities
From January 1, 1997 to March 15, 1997, 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, 1996 have been filed with any federal authority or agency.
Other than the estimates of reserves at December 31, 1995, filed with the
Securities and Exchange Commission, the Registrant did not file reserve reports
with any other federal agencies within the past 12 months.
Silver Property
The Registrant owns seven patented mining claims and 15 unpatented
mining claims in Pinal County, Arizona. These claims, known as the Reymert
Silver Property, have produced silver sporadically since the 1880's. The
property's last ore production was in 1989 under a lease arrangement. In 1993,
the Registrant entered into a License Agreement with another company to allow
commercial rock production from the patented claims. The Registrant receives
a royalty of $2 per ton for rock severed from the property. No commercial
rock production occurred in 1996. No mining activities are presently being
conducted on this property. Management has no plans to devote significant
financial resources to this property in 1997; however, it continues to
investigate ways to further exploit the property.
ITEM 3. LEGAL PROCEEDINGS
On May 12, 1989, the Company filed an action in Burleigh County District
Court, North Dakota, against MDU Resources Group, Inc., a Delaware corporation,
and Williston Basin Interstate Pipeline Company, a Delaware corporation. The
Complaint related to, among other things, breaches of a take or pay natural gas
contract and attempts by the defendants to coerce the Company into modifying
the contract. The defendants answered the Complaint on June 1, 1989. After-
wards, no further materials were filed with the court, but the Company
believed that the case remained pending. Earlier this year, the Company
contacted the attorney who filed the action to assess the status and request
further prosecution of the case. After several months of inaction regarding
the case, the Company contacted the court in September 1996, and was informed
by the court that the case had been dismissed in 1991. On January 15, 1997,
the Company refiled its action against MDU Resources Group, Inc. Management
believes that the Registrant should prevail in its claim, although the extent
of any award cannot be predicted at this time.
Other than the foregoing legal proceedings, 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 1996, 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 Lowest Highest
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
1996 1st Quarter $1.25 $1.63
2nd Quarter $1.44 $2.06
3rd Quarter $1.38 $1.88
4th Quarter $1.50 $4.38
As of March 15, 1997, there were approximately 1,300 holders of record
of the Registrant's Common Stock. Management believes that there are also
approximately 750 additional beneficial owners of common stock held in "street
name".
The Registrant has never declared or paid a cash dividend on its Common
Stock nor does it anticipate that dividends will be paid in the near future.
Further, certain of the Company's financing agreements restrict the payment of
cash dividends. See Note E to the Financial Statements for further information.
ITEM 6. SELECTED FINANCIAL DATA
1996 1995 1994 1993 1992
Operating
Revenue $ 3,806,790 $ 2,874,001 $ 2,442,850 $ 2,375,150 $ 2,498,230
Income (Loss)
Before Cumula-
tive Effect
of Accounting
Change $ 733,726 $ 303,889 $ 40,141 $(1,654,090) $ 104,420
Net Income $ 733,726 $ 303,889 $ 40,141 $(1,077,090) $ 104,420
(Loss)
Income (Loss)
Per Share From
Continuing
Operations $ .18 $ .08 $ .01 $ (.41) $ .03
Net Income
(Loss)
Per Share $ .18 $ .08 $ .01 $ (.27) $ .03
AT YEAR END:
Total Assets $ 7,909,965 $ 6,690,285 $ 5,796,354 $ 5,856,396 $ 7,325,479
Long-term
Debt $ 998,097 $ 958,330 $ 787,035 $ 1,019,792 $ 1,129,897
Working
Capital $ 205,463 $ (171,949) $ (86,786) $ 149,646 $ 261,251
(Deficit)
Stockholders'
Equity $ 4,873,927 $ 4,114,001 $ 3,798,549 $ 3,758,408 $ 4,789,594
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.
BUSINESS ENVIRONMENT AND RISK FACTORS
The following discussion should be read in conjunction with the
Company's consolidated financial statements and related notes included else-
where herein. The Company's future operating results may be affected by
various trends and factors which are beyond the Company's control. These
include, among other factors, the competitive environment in which the
Company operates, oil and gas prices, demand for oil, gas and leonardite,
availability of drilling rigs, dependence upon key management personnel, and
other uncertain business conditions that may affect the Company's business.
With the exception of historical information, the matters discussed
below under the headings "Results of Operations" and "Liquidity and Capital
Resources" may include forward-looking statements that involve risks and
uncertainties. The Company cautions the reader that a number of important
factors discussed herein, and in other reports filed with the Securities and
Exchange Commission, could affect the Company's actual results and cause actual
results to differ materially from those discussed in forward-looking statements.
RESULTS OF OPERATIONS
Comparison of 1996 to 1995 Revenue and Gross Margin
Oil and gas sales were $2,965,000 in 1996 compared to $2,170,000 in
1995, an increase of $795,000 or 37%. This increase in revenue was due to a
24% increase in average oil prices and a 10% increase in the volume of oil and
gas sold. The 1996 average oil price was $17.67 compared to an average of
$14.24 in 1995. The Company periodically uses various New York Mercantile
Exchange (NYMEX) crude oil and energy products contracts and options to hedge
the risks of oil price declines. See Note J to the Financial Statements for
further information. The volume of oil and gas sold in 1996 increased to
169,000 BOE (Barrels of Oil Equivalent) from 154,000 BOE in 1995. The higher
1996 average oil price resulted from substantially higher world oil markets
that existed during 1996. The higher 1996 production volumes resulted entirely
from production contributed by the Company's Oscar Fossum H2 horizontal well
(.67 net) that began production in December 1995.
Oil and gas production costs were $1,082,000 in 1996 compared to
$950,000 in 1995, an increase of 14%. This $132,000 increase was caused by a
$46,000 increase in production taxes resulting from higher oil prices, a
$44,000 increase related to increased workover activity and a $42,000 increase
in winter-related costs including snow removal and increased prices of propane
fuel for oil treating facilities. Production costs on a per equivalent barrel
basis however, remained relatively stable averaging $6.40 for 1996 compared to
$6.18 for 1995. The stability in per barrel costs was due to increased
production which spread the costs over more barrels. Gross margin for 1996 oil
and gas operations before deductions for depletion and selling, general and
administrative expenses was $1,883,000, or 63% of revenue, compared to
$1,220,000, or 56% of revenue, for 1995. The increase in 1996 gross margin was
primarily due to higher 1996 oil prices previously discussed.
Leonardite product sales were $842,000 in 1996 compared to $704,000 in
1995, an increase of $138,000, or 20%. This increase was primarily due to an
18% increase in products sold resulting from increased demand for drilling mud
additives associated with increased oil and gas drilling in the United States.
Production sold in 1996 was 8,909 tons at an average price of $94.49, compared
to 7,528 tons at an average price of $93.51 for 1995. Variations in the
average per ton prices were normal fluctuations associated with the ratio of
basic products and specialty products sold during 1996 and 1995.
Cost of leonardite sold was $667,000 in 1996 compared to $560,000 in
1995, an increase of $108,000 or 19%. This increase resulted from the 18%
increase in 1996 production. Production costs per ton were $74.92 and $74.34
for 1996 and 1995, respectively. Costs per ton were essentially stable for
1996 compared to 1995 and varied only slightly due to the ratio of basic
products and specialty products processed in 1995 and 1996.
Gross margin for 1996 leonardite operations before deductions for
depreciation and selling, general and administrative expenses was $174,000, or
21% of revenue, compared to $144,000, or 20% of revenue, for 1995. The
increase in 1996 gross margin was primarily due to the higher product sales
previously discussed.
Comparison of 1996 to 1995 Consolidated Analysis
Total revenue for 1996 increased $933,000, or 32%, to $3,807,000 from
$2,874,000 in 1995. This increase was due to the higher oil and gas production
and prices and increased leonardite product sales previously discussed.
Total operating costs for 1996 increased $471,000 or 19%, to $2,923,000
compared to $2,453,000 in 1995. These increased costs resulted from the higher
oil and gas and leonardite production cost previously discussed coupled with
higher depreciation, depletion and amortization (DD&A) and selling, general and
administrative (SG&A) expenses. SG&A expenses were higher due to increased
costs for corporate publicity, shareholder communications and general increases
in office activity. SG&A expenses also increased due to the Company's
contribution to its employees' profit sharing plan that was $25,000 higher than
the prior year and a non-cash expense incurred in 1996 related to a one time
stock grant upon the retirement of an employee. DD&A expenses were higher due
to higher oil production levels that increased oil depletion expense.
Higher 1996 total revenue, and to a lesser extent higher total operating
costs, resulted in operating income of $883,000 for 1996. Nonoperating
expenses decreased $25,000 from $90,000 in 1995 to $64,000 in 1996, yielding
an income before taxes of $819,000 in 1996 compared to $332,000 in 1995.
Income tax expense in 1996 was $86,000 compared to $28,000 in 1995. The
expense amount for each year is reflective of the net changes in the Company's
deferred tax assets and deferred tax liabilities under the provisions of SFAS
No. 109 and include only a small amount of income taxes currently paid. See
Notes A and F to the Financial Statements for further information.
Net income for 1996 was $734,000 or 18 cents per share compared to a net
income of $304,000 or 8 cents per share in 1995.
Comparison of 1995 to 1994 Revenue and Gross Margin
Oil and gas sales were $2,170,000 in 1995 compared to $1,685,000 in
1994, an increase of $485,000 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 $14.24 compared
to an average of $12.08 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.
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 $1,220,000 or 56% of revenue, compared to $716,000 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 $431,000 or 18% to $2,874,000 from
$2,443,000 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 $311,000 or
282% to $421,000 compared to $110,000 in 1994. Nonoperating expense for 1995
increased $27,000 or 44% to $90,000 compared to $62,000 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.
LIQUIDITY AND CAPITAL RESOURCES AT YEAR END 1996.
At December 31, 1996, the Company had current assets of $2,018,000
compared to current liabilities of $1,813,000 for a current ratio of 1.11 to 1
and working capital of $205,000. This compares to a current ratio of .88 to 1
at December 31, 1995 and a negative working capital of $172,000. The $377,000
change in working capital was primarily due to cash flow provided by the Oscar
Fossum H2 "flush" oil production accompanied by the 24% higher oil prices.
During the year ended December 31, 1996, the Company generated cash
flows from operating activities of $1,150,000 which is $346,000 greater than
the amount generated during 1995. This increase was due to increased
production and higher oil prices. Management believes that cash flows from
operations for 1997 should increase above 1996 levels particularly if the
Company continues successful horizontal development of certain of its
properties. During the fourth quarter of 1996, the Company drilled one
horizontal well (1 gross, .67 net) in one of its existing fields. The Oscar
Fossum H3 was drilled and completed successfully, and was put on production
in December 1996. The Company anticipates that cash flows from operations
and the remaining $425,000 available under an existing $1,000,000 line of
credit will be sufficient to meet its short-term cash requirements.
During 1996, the Company's investing activities totaled $596,000 which
was primarily for additions to property, plant and equipment. The $583,000
cash portion of additions to property and equipment consists of the
approximate amounts as follows: exploration and development costs of
$463,000 that included the paid portion of costs for drilling and completing
the Oscar Fossum H2 horizontal oil well; proved property acquisition costs of
$43,000 that included the cost of acquiring interests in several producing
wells; unproved property costs of $21,000 primarily for oil and gas lease
costs; delay rental costs of $27,000; and improvements to the Company's
leonardite plant of $29,000. Over and above the additions to property and
equipment, the Company also used $13,000 to fund oil and gas leasehold
purchases in the State of Washington. During 1996, the Company's financing
activities also utilized $514,000 of cash for principal payments required
under long-term debt agreements.
The sources of cash in 1996 for the investing and financing activities
discussed above were the cash flows provided by operating activities and
$325,000 of borrowings on the Company's 1995 revolving line of credit.
During fiscal 1997, the Company estimates it will incur development
costs of $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
1997, depending upon the availability of drilling rigs and the outlook for oil
and gas prices. Other planned expenditures for 1997 consist of delay rentals
and other exploration costs of approximately $100,000. Capital expected to be
used for 1997 principal payments required under existing debt agreements totals
$283,000.
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, and, if
necessary, possible forward sales of oil reserves or additional debt or equity
financing.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See "Index to Consolidated Financial Statements and Supplementary Data"
on page 25.
ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following sets forth certain information concerning each director
and executive officer of the Company:
Position(s) with Period of Service as
Name and Age the Company a Director or Officer
Jeffrey P. Vickers President and Since 1982
Age: 44 Director
Thomas F. Neubauer Vice President Since June, 1992
Age: 62 of Leonardite
Operations
Cathy Kruse Secretary, Since October, 1981;
Age: 42 Treasurer and October, 1981 to May,
Director 1985 and since June, 1990;
since June, 1996
H. Dennis Hoffelt Director From 1967 through June,
Age: 56 1986; and since June, 1987
Joseph V. Montalban Director Since June, 1996
Age: 73
All of the directors' terms expire at the next annual meeting of
shareholders or when their successors have been elected and qualified. The
executive officers of the Company serve at the discretion of the Board of
Directors.
Jeffrey P. Vickers received a Bachelor of Science degree in Geological
Engineering with a Petroleum Engineering option from the University of North
Dakota in 1978. Prior to obtaining his degree, Mr. Vickers served two years
overseas with the U.S. Army. In 1979, Mr. Vickers joined Amerada Hess
Corporation as an Associate Petroleum Engineer in the Williston Basin. In
1981, Mr. Vickers was employed by the Company as the Drilling and Production
Manager where he was responsible for providing technical assistance and
supervision of drilling and production operations and generated development
drilling programs. He became President of the Company on January 1, 1983.
In June, 1982, Mr. Vickers became a director of the Company.
Thomas F. Neubauer is Vice President of Leonardite Operations and plant
manager of the Company. Mr. Neubauer has been employed by the Company since
July, 1965.
Cathy Kruse is Secretary, Treasurer and business office manager of the
Company. Ms. Kruse graduated from the Atlanta College of Business in 1977 and
was employed as a Legal Assistant for four years prior to her employment with
the Company in May, 1981. In June, 1996, Ms. Kruse became a director of the
Company.
H. Dennis Hoffelt has been President of Triangle Electric Inc.,
Williston, North Dakota, an electrical contracting firm, for over the past five
years. He served as a director of the Company from 1967 through June of 1986
and was elected as a director again in 1987.
Joseph V. Montalban has been a director of the Company since June,
1996. He is a petroleum engineering consultant and was the founder of
Mountain States Resources, Inc. and Monte Grande Exploration Ltd., the
companies that merged to create MSR Exploration Ltd. He held various offices
on the MSR Board until his resignation in 1994. Mr. Montalban is the President
and Chief Executive Officer of Montalban Oil & Gas Operations, Inc.
Cathy Kruse, Secretary and Treasurer of the Company, is the sister-in-
law of Jeffrey P. Vickers. No other family relationship exists between or
among any of the above named persons. There are no arrangements or under-
takings 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 1996 $78,443 -0- -0- N/A -0- N/A $11,766
P. 1995 $74,659 -0- -0- $925 35,000 N/A $8,150
Vickers 1994 $73,929 -0- -0- N/A -0- N/A $2,384
CEO
In the table above, the column titled "Restricted Stock Awards" is
comprised of a 1995 grant of 1,000 shares of common stock from the Registrant
to each full-time employee, including Jeffrey P. Vickers. Restricted Stock
Awards are "restricted securities" as defined in Rule 144 adopted under the
Securities Act of 1933. The column titled "All Other Compensation" is
comprised entirely of profit sharing amounts.
If the Company achieves net income in a fiscal year, the Board of
Directors may determine to contribute an amount based on the Company's profits
to the Employees' Profit Sharing Plan and Trust adopted in December, 1978 (the
"Profit Sharing Plan"). An eligible employee may be allocated from 0% to 15%
of his compensation depending upon the total contribution to the plan. A total
of 20% of the amount allocated to an individual vests after three years of
service, 40% after four years, 60% after five years, 80% after six years and
100% after seven or more years. On retirement, an employee is eligible to
receive the vested amount. On death, 100% of the amount allocated to an
individual is payable to the employee's beneficiary. The Company accrued a
$60,000 contribution for 1996 with contributions for 1995 and 1994 being
$35,000 and $10,000, respectively. As of December 31, 1996, vested amounts in
the Profit Sharing Plan for all officers as a group were approximately $360,000.
Aggregated Option/SAR Exercises in last Fiscal Year
and FY-End Option/SAR Values
Value of
Number of Unexercised
Unexercised In-the-Money
Options/SARs Options/SARs
Shares at FY-End(#) at FY-End($)
Acquired on Value Exercisable/ Exercisable/
Name Exercise(#) Realized($) Unexercisable Unexercisable
Jeffrey P.
Vickers, CEO -0- -0- 35,000/0 $69,125/0
At the 1993 Annual Meeting of Shareholders, the Company's 1993
Employees' Incentive Stock Option Plan (the "Plan") was approved by
shareholders. The purpose of the plan is to enable the Corporation to attract
persons of training, experience and ability to continue as employees, and to
furnish additional incentive to such persons, upon whose initiative and efforts
the successful conduct and development of the business of the Corporation
largely depends, by encouraging such persons to become owners of the common
stock of the Corporation.
The term of the Plan expires February 17, 2003, ten years from the date
the Plan was approved by the Board of Directors. If within the duration of an
option there shall be a corporate merger consolidation, acquisition of assets,
or other reorganization, and if such transaction shall affect the optioned
stock, the optionee shall thereafter be entitled to receive upon exercise of
his option those shares or securities that he would have received had the
option been exercised prior to such transaction and the optionee had been a
stockholder of the Corporation with respect to such shares.
The Plan is administered by the Board of Directors. The exercise price
of the common stock offered to eligible participants under the Plan by grant of
an option to purchase common stock may not be less than the fair market value
of the common stock at the date of grant; provided, however, that the exercise
price shall not be less than 110% of the fair market value of the common stock
on the date of grant in the event an optionee owns 10% or more of the common
stock of the Corporation. A total of 300,000 shares have been reserved for
issuance pursuant to options to be granted under the Plan. Of the 300,000
reserved shares, there are 95,000 shares which are subject to outstanding
options issued pursuant to the plan
Directors' Compensation
The officers of the Company who are also directors receive no additional
compensation for attendance at Board meetings. Directors other than Rollin C.
Vickers (who retired from the Board on December 31, 1996), Jeffrey P. Vickers
and Cathy Kruse, were paid $150 per Board meeting attended during 1996.
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 15, 1997.
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 303,934-Direct and 7.5%
$.01 par value Indirect(a)
Common Stock, Paul A. Krile 207,500-Direct(b) 5.1%
$.01 par value
Common Stock, Cathy Kruse 9,950-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, Joseph V. Montalban 546,800-Direct(g) 13.5%
$.01 par value
Common Stock, Officers and 1,118,184-Direct and 27.5%
$.01 par value Directors as Indirect
a Group- (a)(b)(c)(d)(e)(f)(g)
(six persons)
(a) Included in the 303,934 shares listed for Jeffrey P. Vickers are 139,634
shares owned directly by him, 2,500 in a self-directed individual
retirement account, 70,000 shares held jointly with his wife, Nancy J.
Vickers, 25,500 shares held directly by his wife, 1,300 shares in his
wife's self-directed individual retirement account, and an aggregate
30,000 shares held by him as custodian for his three minor children. Also
included are 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) Mr. Krile has sole voting and investment powers over these shares.
(c) Less than 1%.
(d) Included in the 9,950 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.
(g) Mr. Montalban has sole voting and investment powers over these shares.
The following table sets forth information concerning persons known to
the Company to be the beneficial owners of more than 5% of the Company's
outstanding common stock as of March 15, 1997.
Amount of
Class of Name and Shares and Nature of Percent
Securities Address of Person Beneficial Ownership of Class
Common Stock, Joseph V. Montalban 546,800-Direct(a) 13.5%
$.01 par value Montalban Oil & Gas
Operations, Inc.
Box 200
Cut Bank, MT 59247
Common Stock, Jeffrey P. Vickers 303,934-Direct and 7.5%
$.01 par value 1814 14th Ave. W. Indirect(b)
Williston, ND 58801
Common Stock, Paul Krile 207,500-Direct(a) 5.1%
$.01 par value P. O. Box 329
Sioux Rapids, IA 50585
_____________________________
(a) This information was obtained from a Securities and Exchange Commission
filing.
(b) See footnote (a) of the immediately preceding table.
No arrangements are known by the Company which could, at a subsequent
date, result in a change in control of the Company.
The Company is not aware of any officer, director or holder of greater
than 10% of the Company's common stock who has failed to file the required SEC
Forms 3, 4 or 5 on a timely basis for 1996.
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 51.
(b) Reports on Form 8-K
None.
(c) Exhibits required by Item 601 of Regulation S-K
See (a)(3) above.
(d) Financial Statement Schedules required by Regulation S-X
See (a)(1) above.
GEORESOURCES, INC., AND SUBSIDIARY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
Page
REPORT OF INDEPENDENT AUDITORS ON THE
CONSOLIDATED FINANCIAL STATEMENTS 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 - 45
UNAUDITED SUPPLEMENTARY INFORMATION - Disclosures about
oil and gas producing activities 46 - 49
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, 1996 and 1995, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
the years ended December 31, 1996, 1995 and 1994. 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, 1996 and 1995, and the results of its
operations and its cash flows for the years ended December 31, 1996, 1995 and
1994, in conformity with generally accepted accounting principles.
/s/ Williams, Richey & Co.
Denver, Colorado
February 14, 1997
A PROFESSIONAL CORPORATION OF CERTIFIED PUBLIC ACCOUNTANTS AND CONSULTANTS
950 SOUTH CHERRY STREET; SUITE 918; DENVER, CO 80222;
303/759-3773; FAX 303/759-1168
GEORESOURCES, INC., AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1996 AND 1995
ASSETS
CURRENT ASSETS: 1996 1995
Cash and equivalents $ 754,888 $ 392,078
Trade receivables, net 936,045 590,330
Inventories 251,499 285,018
Prepaid expenses 18,201 17,460
Investments 57,771 10,119
Total current assets 2,018,404 1,295,005
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, using the
full cost method of accounting:
Properties being amortized 16,450,061 15,272,170
Properties not subject to amortization 18,199 88,759
Leonardite plant and equipment 3,216,597 3,199,797
Other 693,641 672,546
20,378,498 19,233,272
Less accumulated depreciation, depletion,
amortization and impairment (14,708,047) (14,045,602)
Net property, plant and equipment 5,670,451 5,187,670
OTHER ASSETS:
Mortgage loans receivable, related party 103,321 103,321
Other 117,789 104,289
Total other assets 221,110 207,610
TOTAL ASSETS $ 7,909,965 $ 6,690,285
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 1,343,677 $ 856,823
Current maturities of long-term debt 283,200 511,594
Accrued expenses 186,064 98,537
Total current liabilities 1,812,941 1,466,954
LONG-TERM DEBT, less current maturities 998,097 958,330
DEFERRED INCOME TAXES 225,000 151,000
CONTINGENCIES (NOTE H)
STOCKHOLDERS' EQUITY:
Common stock, par value $.01 per share;
authorized 10,000,000 shares; issued
and outstanding, 4,060,714 and
4,035,714 shares, respectively 40,607 40,357
Additional paid-in capital 829,757 803,807
Retained earnings 4,003,563 3,269,837
Total stockholders' equity 4,873,927 4,114,001
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 7,909,965 $ 6,690,285
The accompanying notes are an integral part of these
consolidated financial statements
GEORESOURCES, INC., AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
1996 1995 1994
OPERATING REVENUE:
Oil and gas sales $ 2,964,939 $ 2,170,057 $ 1,685,316
Leonardite sales 841,851 703,944 757,534
3,806,790 2,874,001 2,442,850
OPERATING COSTS AND EXPENSES:
Oil and gas production 1,082,324 950,116 968,977
Cost of leonardite sold 667,437 559,659 585,217
Depreciation, depletion
and amortization 674,805 601,814 470,075
Selling, general and
administrative 498,882 341,008 308,380
2,923,448 2,452,597 2,332,649
Operating income 883,342 421,404 110,201
OTHER INCOME (EXPENSE):
Interest expense (113,384) (128,689) (103,328)
Interest income 18,287 10,808 15,741
Other income and losses, net 31,050 28,366 25,509
(64,047) (89,515) (62,078)
Income before income taxes 819,295 331,889 48,123
INCOME TAX EXPENSE 85,569 28,000 7,982
Net income $ 733,726 $ 303,889 $ 40,141
EARNINGS PER SHARE $ .18 $ .08 $ .01
Weighted average number of
shares outstanding 4,056,274 4,025,234 4,023,214
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, 1996, 1995 AND 1994
Additional
Common Stock Paid-in Retained
Shares Amount Capital Earnings Total
Balance, December 31, 1993 4,023,214 $40,232 $792,369 $2,925,807 $3,758,408
Net income -- -- -- 40,141 40,141
Balance, December 31, 1994 4,023,214 40,232 792,369 2,965,948 3,798,549
Issuance of common stock
as compensation 12,500 125 11,438 -- 11,563
Net income -- -- -- 303,889 303,889
Balance, December 31, 1995 4,035,714 40,357 803,807 3,269,837 4,114,001
Issuance of common stock
as compensation 25,000 250 25,950 -- 26,200
Net income -- -- -- 733,726 733,726
Balance, December 31, 1996 4,060,714 $40,607 $829,757 $4,003,563 $4,873,927
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, 1996, 1995 AND 1994
1996 1995 1994
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 733,726 $ 303,889 $ 40,141
Adjustments to reconcile net
income to net cash provided
by operating activities:
Depreciation, depletion and
amortization 674,805 601,814 470,075
Deferred income taxes 74,000 28,000 7,982
Issuance of common stock
as compensation 26,200 11,563 --
Other 2,192 2,326 2,357
Changes in assets and liabilities:
Decrease (increase) in:
Trade receivables (345,715) (96,735) (124,445)
Inventories 33,519 (38,551) 81,299
Prepaid expenses and other (741) (187) 29,650
Investments (47,652) 10,853 3,360
Increase (decrease) in:
Accounts payable (87,604) (78,831) 135,428
Accrued expenses 87,527 59,473 12,089
Net cash provided by
operating activities 1,150,257 803,614 657,936
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, plant and
equipment (583,128) (899,677) (646,571)
Purchase of investments and mortgage
loans receivable -- -- (18,943)
Proceeds from sale of property
and equipment -- 20,234 143,385
Other (12,756) (47,215) (19,047)
Net cash used in
investing activities (595,884) (926,658) (541,176)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term borrowings 325,000 665,000 100,000
Principal payments on long-term debt (513,627) (367,330) (319,215)
Debt issue costs (2,936) (5,225) --
Net cash provided by (used in)
financing activities (191,563) 292,445 (219,215)
NET INCREASE (DECREASE) IN CASH
AND EQUIVALENTS 362,810 169,401 (102,455)
CASH AND EQUIVALENTS, beginning of year 392,078 222,677 325,132
CASH AND EQUIVALENTS, end of year $ 754,888 $ 392,078 $ 222,677
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, 1996, 1995 AND 1994
1996 1995 1994
SUPPLEMENTAL DISCLOSURE OF
CASH FLOW INFORMATION
Cash paid (received) for:
Interest $ 114,850 $ 127,990 $ 102,258
Income taxes 1,569 336 (483)
NONCASH INVESTING AND FINANCING ACTIVITIES
During 1994, the Company forgave approximately $24,500 of accounts receivable
as partial consideration of the purchase price of various oil and gas assets.
The accompanying notes are an integral part of these
consolidated financial statements
GEORESOURCES, INC., AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. SIGNIFICANT ACCOUNTING POLICIES:
Nature of Operations and Principles of Consolidation
The accompanying consolidated financial statements include the accounts of
GeoResources, Inc., and its 80% owned subsidiary, Belmont Natural Resource
Company, Inc. ("BNRC"). All material intercompany transactions and balances
between the entities have been eliminated. The minority interest in BNRC
is not presented, as the amount is immaterial.
GeoResources, Inc. (the "Company") is primarily involved in oil and gas
exploration, development and production in North Dakota and Montana and the
mining of leonardite and manufacturing of leonardite products in North
Dakota to be sold to customers located primarily in the Gulf of Mexico
coastal areas. BNRC was incorporated in 1991 to exploit natural gas
opportunities in the Pacific Northwest. All properties of the Company
and BNRC are located in the United States.
Reclassifications
Certain accounts in the prior-year financial statements have been
reclassified for comparative purposes to conform with the presentation in
the current-year financial statements.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Significant estimates used in preparing these financial statements include
the unaudited quantity of oil and gas reserves which directly effects the
computation of depletion of oil and gas properties. It is at least
reasonably possible that the estimates used will change within the next
year.
Cash Equivalents
For purposes of the statements of cash flows, the Company considers all
highly liquid debt instruments purchased with an original maturity of three
months or less to be cash equivalents.
Inventories
Inventories are stated at the lower of cost (first-in, first-out method) or
market.
Investments
The Company's investments consist of marketable equity securities and
various derivative financial instruments related to crude oil and other
energy products.
Marketable equity securities are stated at market value. Securities
acquired with the intent to resell in order to profit from short-term price
movements are classified as trading account securities and related
unrealized gains and losses are included in other income. Other securities
are classified as assets available-for-sale and related unrealized gains or
losses are recorded as a component of stockholders' equity. The specific
security sold is used to compute realized gains or losses. All of the
Company's securities are classified as trading account securities.
The Company periodically uses various derivative financial instruments
to hedge a portion of future oil sales against the risk of possible
decreases of crude oil prices. These instruments are accounted for as
hedges and, accordingly, gains and losses are deferred and recognized
when the future oil sales occur.
Oil and Gas Properties
The Company utilizes the full cost method of accounting for oil and gas
properties. Accordingly, all costs associated with the acquisition,
exploration and development of oil and gas reserves (including costs of
abandoned leaseholds, delay lease rentals, dry hole costs, geological and
geophysical costs, certain internal costs associated directly with
acquisition, exploration and development activities, and site restoration
and environmental exit costs) are capitalized.
All capitalized costs of oil and gas properties, including the estimated
future costs to develop proved reserves, are amortized on the unit-of-
production method using estimates of proved reserves. Investments in
unproved properties and major development projects are not amortized until
proved reserves associated with the projects can be determined or until
impairment occurs. If the results of an assessment indicate that the
properties are impaired, the amount of the impairment is added to the
capitalized costs to be amortized. The Company's oil and gas depreciation,
depletion and amortization rate per equivalent barrel of oil produced was
$3.27, $3.09, and $2.51 for 1996, 1995, and 1994, respectively.
In addition, the capitalized costs are subject to a "ceiling test," which
basically limits such costs to the aggregate of the "estimated present
value," discounted at a 10-percent interest rate of future net revenues from
proved reserves, based on current economic and operating conditions, plus
the lower of cost or fair market value of unproved properties.
Gains or losses are not recognized upon the sale or other disposition of oil
and gas properties, except in extraordinary transactions.
Costs not being amortized at December 31, 1996, consist of the unevaluated,
unimpaired cost of undeveloped oil and gas properties which were acquired
during the following years:
1996 $ 1,074
1995 875
1994 10,580
1993 and prior 5,670
Total $ 18,199
It is expected that evaluation of the above properties will occur primarily
over the next four years.
Other Property and Equipment
Depreciation of other property and equipment is computed principally on the
straight-line method over the following estimated useful lives:
Buildings 10-25 years
Machinery and equipment 3-10 years
Impairment of Long-Lived Assets
Potential impairment of long-lived assets (other than oil and gas
properties) is reviewed whenever events or changes in circumstances indicate
the carrying amount of the assets may not be recoverable. Impairment is
recognized when the estimated future net cash flows (undiscounted and
without interest charges) from the asset are less than the carrying amount
of the asset. No impairment losses have been recognized on long-lived
assets for the years ended December 31, 1996, 1995 and 1994.
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 October 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 123, Accounting for Stock-Based
Compensation. The Company currently accounts for its stock-based
compensation plans using the accounting prescribed by Accounting Principles
Board Opinion No. 25, Accounting for Stock Issued to Employees. Since the
Company is not required to adopt the fair value based recognition provisions
prescribed under SFAS No. 123, it has elected only to comply with the
disclosure requirements set forth in the Statement, which includes
disclosing pro forma net income as if the fair value based method of
accounting had been applied. (See Note G).
Income Taxes
Provisions for income taxes are based on taxes payable or refundable for the
current year and deferred taxes on temporary differences between the amount
of taxable income and pretax financial income and between the tax bases of
assets and liabilities and their reported amounts in the financial
statements. Deferred tax assets and liabilities are included in the
financial statements at currently enacted income tax rates applicable to the
period in which the deferred tax assets and liabilities are expected to be
realized or settled. A valuation allowance is provided for deferred tax
assets not expected to be realized.
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,
1996, 1995 and 1994:
1996 1995 1994
Revenue:
Oil and gas $2,964,939 $2,170,057 $1,685,316
Leonardite 841,851 703,944 757,534
$3,806,790 $2,874,001 $2,442,850
Operating income:
Oil and gas $1,330,169 $ 744,465 $ 364,426
Leonardite 40,737 10,657 46,041
General corporate activities (487,564) (333,718) (300,266)
$ 883,342 $ 421,404 $ 110,201
Depreciation and depletion:
Oil and gas $ 552,446 $ 475,476 $ 351,913
Leonardite 107,087 111,958 105,590
General corporate activities 15,272 14,380 12,572
$ 674,805 $ 601,814 $ 470,075
Identifiable assets, net:
Oil and gas $5,014,782 $4,110,608 $3,335,013
Leonardite 1,501,054 1,552,442 1,600,094
General corporate activities 1,394,129 1,027,235 861,247
$7,909,965 $6,690,285 $5,796,354
Capital expenditures incurred:
Oil and gas $1,156,842 $1,162,393 $ 634,914
Leonardite 29,160 26,264 17,199
General corporate activities 21,095 4,095 11,011
$1,207,097 $1,192,752 $ 663,124
Major Customer and Concentrations of Credit Risk
Sales to a major oil and gas customer were 65%, 53% and 46% of total
revenue for the years ended December 31, 1996, 1995 and 1994, respectively.
Accounts receivable from this major customer were 38% and 47% of total
accounts receivable at December 31, 1996 and 1995, respectively.
The Company has two bank accounts with balances of approximately $458,000
and $242,000, at December 31, 1996. Each account is federally-insured for
balances up to $100,000.
C. TRADE RECEIVABLES AND INVENTORIES:
Trade receivables at December 31, 1996 and 1995 are comprised of the
following:
1996 1995
Oil and gas purchasers $ 700,833 $ 426,463
Leonardite customers 246,628 175,283
947,461 601,746
Less allowance for
doubtful accounts (11,416) (11,416)
$ 936,045 $ 590,330
As of December 31, 1996 and 1995, inventories by major classes are comprised
of the following:
1996 1995
Crude oil $ 36,022 $ 21,222
Leonardite inventories:
Finished products 52,543 73,937
Raw materials 94,387 111,342
Materials and supplies 68,547 78,517
Total leonardite inventories 215,477 263,796
$ 251,499 $ 285,018
D. MORTGAGE LOANS RECEIVABLE, RELATED PARTY
Mortgage loans receivable, related party represent mortgage loans on the
residence of an officer/shareholder of BNRC purchased from a third party
in November 1993, and are recorded at purchase cost. The mortgages require
monthly payments of interest at 8% per annum with principal due January 14,
1999. The Company received interest income from these loans of $8,100,
$8,100 and $8,775, for the years ended December 31, 1996, 1995 and 1994,
respectively.
E. LONG-TERM DEBT:
Long-term debt at December 31, 1996 and 1995 consists of the following loans
which are all with one bank:
1996 1995
Bank, prime plus 1% (9.25% total rate
at December 31, 1996), due in monthly
installments of $7,600 plus interest,
due December 1998, unsecured $ 181,297 $ 272,497
Bank, prime plus 1% (9.25% total rate
at December 31, 1996), due in monthly
installments of $16,000 plus interest,
due September 1999, collateralized by
oil and gas properties 525,000 717,000
Bank, $1,000,000 revolving line of credit,
interest payable monthly at prime plus 1%,
not to exceed 10.5% (9.25% total rate at
December 31, 1996), 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 575,000 250,000
Two loans, fully repaid as scheduled
during 1996 -- 230,427
Total long-term debt 1,281,297 1,469,924
Less current maturities (283,200) (511,594)
Long-term debt, less current
maturities $ 998,097 $ 958,330
Aggregate maturities required on long-term debt at December 31, 1996, are as
follows:
Year Ending December 31:
1997 $ 283,200
1998 282,097
1999 188,917
2000 143,750
2001 143,750
Remainder 239,583
$1,281,297
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, 1996,
1995 and 1994, are as follows:
1996 1995 1994
Current tax expense $ 11,569 $ -- $ --
Deferred tax expense 232,000 95,000 6,982
Increase (decrease) in deferred
tax assets valuation allowance (158,000) (67,000) 1,000
$ 85,569 $ 28,000 $ 7,982
During 1994, there was no significant change in the Company's total gross
deferred tax assets, the valuation allowance or deferred tax liabilities.
During 1996 and 1995, the Company recorded a deferred tax expense of
$232,000 and $95,000, respectively. This related primarily to net income
which was not currently taxable due to the deduction of intangible drilling
costs for tax purposes in 1996 and the utilization of net operating loss
carryforwards in 1995. The Company also decreased the deferred tax asset
valuation allowance by $158,000 and $67,000 during 1996 and 1995,
respectively, primarily based upon the projection of utilizing additional
statutory depletion carryforwards in the future.
The tax effects of significant temporary differences and carryforwards which
give rise to the Company's deferred tax assets and liabilities at December
31, 1996 and 1995, are as follows:
1996 1995
Deferred Tax Assets:
Net operating loss carryforward $ 278,000 $ 293,000
Statutory depletion carryforward 983,000 928,000
Investment tax credit carryforward 226,000 283,000
Other 70,000 44,000
1,557,000 1,548,000
Valuation Allowance:
Beginning of year (909,000) (976,000)
(Increase) decrease 158,000 67,000
End of year (751,000) (909,000)
Deferred Tax Liabilities:
Accumulated depreciation and
depletion (1,031,000) (790,000)
Net Deferred Tax Liability, long-term $ (225,000) $ (151,000)
The provision for income taxes does not bear a normal relationship to pre-
tax earnings. A reconciliation of the U.S. federal income tax rate with the
actual effective rate for the years ended December 31, 1996, 1995 and 1994
is as follows:
1996 1995 1994
Income tax expense at statutory rate 35% 35% 35%
Loss carryover benefits -- (14) --
Change in valuation allowance (20) (21) 2
Graduated tax rate difference (13) -- (20)
State income taxes and other 8 8 --
10% 8% 17%
For income tax purposes, the Company has a statutory depletion carryover of
approximately $3,090,000 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
1997 $ -- $ 181,000
1998-2000 -- 45,000
2001 421,000 --
2003 102,000 --
2008 115,000 --
2009 237,000 --
Total $ 875,000 $ 226,000
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. Since the inception of the plan,
options have been granted (all during 1995) to purchase 95,000 shares of
common stock at an exercise price of $1.15 per share through November 3,
2000. No options were exercised through December 31, 1996.
The Company applies the provisions of APB Opinion 25 in accounting for its
plan. Accordingly, no compensation cost was recognized for the options
granted in 1995. Had compensation cost been determined consistent with the
method of SFAS No. 123, the fair value of the options estimated on the date
of grant would have been $37,050. Accordingly, the Company's 1995 net
income and earnings per share would have been reduced to pro forma amounts
of $269,839 and $.07, respectively. The fair value of the options on the
date of grant is estimated using the Black-Scholes option-pricing model
with the following assumptions: expected volatility of 31%, risk-free
interest rate of 5.77%, expected lives of 4 years and no expected dividends.
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, 1996, 1995 and 1994 was
$60,000, $35,000, 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 an office building, one-third of which it
occupies. The building is included in other property and equipment in the
accompanying balance sheets and consists of the following at December 31,
1996 and 1995:
1996 1995
Building and improvements $ 163,834 $ 163,834
Accumulated depreciation (47,371) (39,180)
$ 116,463 $ 124,654
The Company leases the remainder of the building to unaffiliated businesses
under cancelable lease agreements. During 1996, 1995 and 1994, the Company
received $20,938, $19,500, and $18,300, respectively, in rental income from
the building which is included in other income in the accompanying
statements of operations.
J. FINANCIAL INSTRUMENTS:
The carrying amounts reflected in the consolidated balance sheets for cash
and equivalents approximates their fair value due to the short maturity of
the instruments. The carrying amount of marketable equity securities is
fair value based on quoted market prices. The carrying amount of derivative
financial instruments was $50,450 and $2,911 at December 31, 1996 and 1995,
respectively. The fair value of those instruments, based on quoted market
prices, was $17,450 and $2,911 at December 31, 1996 and 1995, respectively.
The carrying value of mortgage loans receivable approximates fair value
based on discounted future cash flows.
The Company uses derivative financial instruments to manage its crude oil
commodity price risk. They are not used for trading purposes. The Company
has in recent years hedged 5% to 35% of its crude oil sales using various
financial instruments including "put" and "call" options and, to a lesser
extent, actual future contracts on crude oil and energy products that trade
on the New York Mercantile Exchange ("NYMEX"). The variation in the types
of instruments employed results from a strategy designed to provide
primarily short to intermediate term protection (less than one year) from
oil price declines that would occur in a wide range. Generally, the
Company does not hedge against narrow-range oil price movements. Since
these financial instruments correlate to crude oil and energy products
price movements, gains or losses resulting from market changes will be
offset by losses or gains on the Company's crude oil sales. Included in
oil and gas sales are losses from hedging activities totaling $102,656,
$10,401 and $3,243 for the years ended December 31, 1996, 1995 and 1994,
respectively.
At December 31, 1996, the Company's hedging activities consisted of put
options for futures contracts maturing through June 1997 covering 35,000
barrels of crude oil at prices ranging from $20 to $22 per barrel. Deferred
net hedging losses amounted to $33,000 at December 31, 1996.
K. FOURTH QUARTER ADJUSTMENTS:
During the fourth quarter of 1996, the Company made the determination to
deduct for income tax purposes all intangible drilling costs incurred during
1996. Previously, these costs had been capitalized. As a result, deferred
income tax liabilities increased $160,000 and income tax expense increased
$91,569 over the amounts reported at September 30, 1996.
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, 1996, 1995 and 1994:
1996 1995 1994
Proved Properties $ 16,450,061 $ 15,272,170 $ 14,105,349
Unproved properties 18,199 88,759 134,330
Total 16,468,260 15,360,929 14,239,679
Less accumulated depreciation,
depletion, amortization and
impairment (12,345,734) (11,793,289) (11,317,813)
Net capitalized costs $ 4,122,526 $ 3,567,640 $ 2,921,866
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, 1996, 1995 and 1994:
1996 1995 1994
Property acquisition costs:
Proved $ 42,611 $ 189,036 $ 115,193
Unproved 21,027 15,479 40,786
Exploration costs 113,145 115,957 55,635
Development costs 980,059 841,921 423,300
$ 1,156,842 $ 1,162,393 $ 634,914
The Company's results of operations from oil and gas producing activities
(excluding corporate overhead and financing costs) are presented below for the
years ended December 31, 1996, 1995 and 1994.
1996 1995 1994
Oil and gas sales $ 2,964,939 $ 2,170,057 $ 1,685,316
Production costs (1,082,324) (950,116) (968,977)
Depletion, depreciation
and amortization (552,446) (475,476) (351,913)
1,330,169 744,465 364,426
Imputed income tax provision 10,000 26,000 --
$ 1,320,169 $ 718,465 $ 364,426
GEORESOURCES, INC., AND SUBSIDIARY
UNAUDITED SUPPLEMENTARY INFORMATION
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
The reserve information presented below is based upon reports prepared by the
independent petroleum engineering firm of Broschat Engineering and Management
Services. The Company emphasizes that reserve estimates are inherently
imprecise and that estimates of new discoveries are more imprecise than those
of mature producing oil and gas properties. Accordingly, these estimates are
expected to change as future information becomes available.
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under economic and operating conditions existing as of the end of
each respective year. The year-end selling price of oil and gas is one of the
primary factors affecting the determination of proved reserve quantities which
fluctuate directly with that price.
Presented below is a summary of the changes in estimated proved reserves of the
Company, all of which are located in the United States, for the years ended
December 31, 1996, 1995 and 1994:
1996 1995 1994
Oil Gas Oil Gas Oil Gas
(bbl) (mcf) (bbl) (mcf) (bbl) (mcf)
Proved reserves,
beginning of
year 2,047,000 266,000 1,642,000 244,000 1,075,000 254,000
Purchases of
reserves-in-
place 21,000 -- 67,000 -- 69,000 --
Sales of reserves
-in-place -- -- -- -- (21,000) --
Extensions and
discoveries 12,000 3,000 5,000 1,000 317,000 2,000
Improved
recovery 156,000 -- 443,000 -- 137,000 --
Revisions of
previous
estimates 85,000 5,000 42,000 34,000 204,000 (3,000)
Production (167,000) (13,000) (152,000) (13,000) (139,000) (9,000)
Proved reserves,
end of year 2,154,000 261,000 2,047,000 266,000 1,642,000 244,000
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)
1996 1,366,000 261,000
1995 1,292,000 266,000
1994 1,192,000 244,000
Statement of Financial Accounting Standards No. 69 prescribes guidelines for
computing a standardized measure of future net cash flows and changes therein
relating to estimated proved reserves. The Company has followed these
guidelines which are briefly discussed below.
Future cash inflows and future production and development costs are determined
by applying year-end selling prices and year-end production and development
costs to the estimated quantities of oil and gas to be produced. The
limitations inherent in the reserve quantity estimation process, as discussed
previously, are equally applicable to the standardized measure computations
since these estimates are the basis for the valuation process. Estimated
future income taxes are computed using current statutory income tax rates
including consideration for estimated future statutory depletion, depletion
carryforwards, net operating loss carryforwards, and investment tax credit
carryforwards. The resulting future net cash flows are reduced to present
value amounts by applying a 10% annual discount factor.
The assumptions used to compute the standardized measure are those prescribed
by the Financial Accounting Standards Board and, as such, do not necessarily
reflect the Company's expectations of actual revenues or future net cash flows
to be derived from those reserves nor their present worth.
GEORESOURCES, INC., AND SUBSIDIARY
UNAUDITED SUPPLEMENTARY INFORMATION
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
Presented below is the standardized measure of discounted future net cash flows
as of December 31, 1996, 1995 and 1994:
1996 1995 1994
Future cash inflows $ 46,708,000 $ 30,628,000 $ 19,815,000
Future production costs (17,419,000) (13,369,000) (9,732,000)
Future development costs (3,078,000) (2,993,000) (1,439,000)
Future income tax expense (7,385,000) (3,423,000) (1,450,000)
Future net cash flows 18,826,000 10,843,000 7,194,000
Less effect of a 10%
discount factor (7,380,000) (4,381,000) (2,914,000)
Standardized measure of
discounted future net
cash flows relating to
proved reserves $ 11,446,000 $ 6,462,000 $ 4,280,000
The principal sources of change in the standardized measure of discounted
future net cash flows are as follows for the years ended December 31, 1996,
1995 and 1994:
1996 1995 1994
Standardized measure,
beginning of year $ 6,462,000 $ 4,280,000 $ 2,368,000
Sales of oil and gas
produced, net of
production costs (1,985,000) (1,234,000) (720,000)
Net changes in prices
and production costs 6,452,000 2,256,000 1,384,000
Purchases of reserves-
in-place 121,000 436,000 215,000
Sales of reserves-
in-place -- -- (75,000)
Extensions, discoveries
and other additions,
less related costs 1,369,000 2,203,000 1,624,000
Revisions of previous
quantity estimates
and other 1,209,000 599,000 946,000
Development costs
incurred during the year
and changes in estimated
future development costs (582,000) (1,415,000) (936,000)
Accretion of discount 850,000 514,000 246,000
Net change in income taxes (2,450,000) (1,177,000) (772,000)
Standardized measure,
end of year $ 11,446,000 $ 6,462,000 $ 4,280,000
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 28, 1997 /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- 3/28/97
J. P. Vickers tive officer and principal
financial officer) and Director
/s/ Cathy Kruse Secretary/Treasurer 3/28/97
Cathy Kruse and Director
/s/ Dennis Hoffelt Director 3/28/97
Dennis Hoffelt
Director
Joseph V. Montalban
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
______________________________________
GEORESOURCES, INC.
(Commission File Number: 0-8041)
______________________________________
EXHIBIT INDEX
FOR
Form 10-K for 1996 fiscal year.
______________________________________
Page Number
in Sequential
Numbering of all
Form 10-K and
Exhibit Exhibit Pages
3.1 Registrant's Bylaws, as amended, November
30, 1994 *
3.2 Registrant's Articles of Incorporation, as
amended to date, incorporated by reference to
Exhibit 3.1 of the Registrant's Form 10-K for
fiscal year, 1983 *
10.1 Mining Lease and Agreement dated April 6, 1988,
by and between Roger C. Ryan, Susan Ryan,
Constance Ryan, Charlotte McConnell and Joseph
W. Ryan as Lessors, and GeoResources, Inc. as
Lessee incorporated by reference to Exhibit 10.4
of Registrant's Form 10-Q for fiscal quarter
ended March 31, 1988 *
10.2 Credit Agreement dated January 24, 1989, by and
between GeoResources, Inc. and Norwest Bank
Billings, incorporated by reference to Exhibit
10.25 of the Registrant's Form 10-K for fiscal
year, 1988 *
10.3 Promissory Note dated January 24, 1989, by and
between GeoResources, Inc., as Borrower and
Norwest Bank Billings, incorporated by reference
to Exhibit 10.26 of the Registrant's Form 10-K
for fiscal year, 1988 *
10.4 Combination Mortgage, Security Agreement and
Fixture Financing Statement dated January 24,
1989, by and between GeoResources, Inc., as
Mortgagor/Debtor and Norwest Bank Billings,
as Mortgagee/Secured party, incorporated by
reference to Exhibit 10.27 of the Registrant's
Form 10-K for fiscal year, 1988 *
10.5 Mortgage, Security Agreement, Assignment of
Production and Financing Statement dated
January 24, 1989, by and between GeoResources,
Inc., as Mortgagor/Debtor and Norwest Bank
Billings, as Mortgagee/Secured party,
incorporated by reference to Exhibit 10.28
of the Registrant's Form 10-K for fiscal
year, 1988 *
10.6 Modification of Note of January 24, 1989, by
and between Norwest Bank Billings and
GeoResources, Inc., effective January 2,
1992, incorporated by reference to Exhibit
10.1 of the Registrant's Form 10-Q for fiscal
quarter ended March 31, 1992 *
10.7 License Agreement dated March 22, 1993, by
and between GeoResources, Inc. and Central
Arizona Material Co., incorporated by reference
to Exhibit 10.1 of the Registrant's Form 10-Q
for fiscal quarter ended March 31, 1993 *
10.8 Secured Form Loan and Revolving Credit Agreement
dated April 29, 1993, by and between GeoResources,
Inc. and Norwest Bank Billings, incorporated by
reference to Exhibit 10.1 of the Registrant's Form
10-Q for fiscal quarter ended June 30, 1993 *
10.9 Mortgage, Security Agreement, Assignment of
Production and Financing Statement dated April 29,
1993, by and between GeoResources, Inc., as
Mortgagor and Norwest Bank Billings, as Mortgagee,
incorporated by reference to Exhibit 10.2 of the
Registrant's Form 10-Q for fiscal quarter ended
June 30, 1993 *
10.10 The Registrant's 1993 Employees' Incentive Stock
Option Plan, incorporated by reference as Exhibit
A to the Registrant's definitive Proxy Statement
dated May 5, 1993 *
10.11 Amended and Restated Secured Term Loan and
Revolving Credit Agreement made as of September
1, 1995, by and between GeoResources, Inc. and
Norwest Bank Montana *
10.12 First Amendment of Mortgage, Security Agreement,
Assignment of Production and Financing Statement
and Mortgage - Collateral Real Estate Mortgage
dated September 1, 1995, by and between
GeoResources, Inc. and Norwest Bank Montana *
10.13 Commercial Installment Note with addendum dated
February 1, 1997, by and between GeoResources,
Inc. and Norwest Bank Billings 54
27 Financial Data Schedule 57
NORWEST BANKS Commercial
Installment Note
Borrower's name GeoResources, Inc. Date 02-01-1997
Promise to Pay: For value received, the undersigned Borrower promises to pay
to the order of Norwest Bank Montana, National Association (the "Bank") at
175 North 27th Street, Billings, MT 59117 or such other place
as the Bank or the holder of this promissory note (the "Note") may designate,
the principal sum of One Hundred Sixty-Six Thousand Ninety-Six and 60/100
Dollars ($ 166,096.60 ), together with interest on the unpaid balance in
accordance with the repayment terms set forth below.
Interest: The Borrower will pay interest (calculated on the basis of actual
days elapsed in a 360 day year) on the unpaid principal balance at the
following rate (the "Note Rate"):
___ an annual rate of ____ %.
_X_ an annual rate equal to 1.0000 % above the Base Rate, floating.
___ an annual rate which, for any month hereafter, shall be equal to
_____ % _____ the Base Rate in effect on the last day of the
preceding month, with an initial rate equal to _____%.
___ an annual rate _____.
If this ___ is checked and the Note Rate is variable, the Note Rate shall at
no time be less than an annual rate of _____%, and shall at no time exceed an
annual rate (if one is specified) of _____%. The interest rate on this Note
shall never exceed the maximum rate permitted by law.
"Base Rate" means the rate of interest established by Norwest Bank Minnesota,
National Association from time to time as its "Prime" rate. "Due Date" means
the maturity date on which all unpaid principal and interest is scheduled to
be repaid as stated in the Section entitled "Repayment Terms" or the date of
the acceleration of this Note, whichever is earlier.
Repayment Terms: Unless payable sooner as a result of its acceleration, the
Borrower shall pay this Note as follows:
___ Fixed Installments of Principal and Interest. Principal and interest
shall be paid together in _____consecutive installments of $_____ each, _____
beginning _____, and on the same day of each _____ thereafter until _____,
___ plus irregular installments as follows:
$_____ on _____; $ _____on _____; and
$ _____on _____. On _____, the entire unpaid balance of principal and accrued
but unpaid interest shall be due and payable.
Each installment shall be applied first to accrued interest and the balance to
principal.
_X_ Fixed Principal Payments Plus Interest. Principal only shall be paid:
_X_ in 21 consecutive installments of $ 7,600.00 each, beginning
03-01-1997, and on the same day of each month thereafter until
11-01-1998, plus a final payment on 12-01-1998, when the entire
unpaid balance of principal shall become due and payable.
___ $ _____ on _____; $ _____ on _____;
$ _____ on _____; $ _____ on _____;
$ _____ on _____; $ _____ on _____;
and in addition, interest shall be payable Monthly, beginning
03-01-1997, and on the same day of each subsequent month.
Late Fee: ___ Each time that a scheduled payment is not paid when due or
within _____ days afterwards, the Borrower will pay a late fee equal to ___
$ _____; ___ _____% of the full amount of the late payment; ___ the lesser of
$ _____ or _____ % of the full amount of the late payment.
___ Additional Interest. Each time a scheduled payment is not paid when due
or within _____ days afterwards, the Borrower will pay additional interest
("Additional Interest") which will begin accruing on the next calendar day
on the entire unpaid principal balance at an annual rate of _____ % in excess
of the Note Rate. The Additional Interest will continue to accrue until all
past due payments and any Additional Interest are paid in full. Acceptance
by the Bank of any late fee or Additional Interest shall not constitute a
waiver of any default hereunder.
Prepayment: The Borrower may prepay this Note, at any time, in whole or in
part, _X_ without penalty ___ provided that at the time of prepayment the
Borrower pays a prepayment penalty equal to _____ % of the principal amount
prepaid. Any partial payment shall be applied against the principal portion
of the installments due in inverse order of maturity.
Other Fees: If this _X_ is checked, the undersigned shall pay to the Bank a
nonrefundable: (Mark the applicable fee type(s))
___ commitment fee of (Choose one) ___ $ _____ ___ _____% of the Note
Amount
_X_ facility fee of (Choose one) _X_ $ 300.00 ___ _____ % of the Note
Amount
___ documentation fee of (Choose one) ___ $ _____ ___ _____ % of the
Note Amount
___ application and loan processing fee of (Choose one) ___ $ _____
___ _____% of the Note Amount
"Note Amount" means the principal amount of this Note, at the time this Note
is signed.
THE ATTACHED ADDENDUM IS INCORPORATED HEREIN AND MADE A PART HEREOF.
Additional Terms: The terms set forth on the reverse are incorporated into
and made a part of this Note.
Loan Purpose: The Borrower certifies that the proceeds of this loan will be
used for business or agricultural purposes.
Signatures
/s/ J.P. VICKERS
Name and Title (If applicable) Name and Title (If applicable)
Jeffrey P Vickers, President
Borrower's name
GeoResources, Inc.
Address Name and Title (If applicable)
1407 W Dakota Parkway, Ste 1-B
City, State, Zip code _X_ This Note is given as a
Williston, ND 58802 replacement for, and not in
satisfaction of Note Number
88147, given by the Borrower
and dated 01-24-1989.
Additional Terms
Default and Acceleration: Upon the occurrence of any one or more of the
following events of default, or at any time thereafter unless such default is
cured, the Bank may at its option declare all unpaid principal, accrued
interest, fees and all other amounts payable under this Note to be immediately
due and payable, without notice or demand to the Borrower:
- - Default by the Borrower in the payment when due of any principal, interest
or other amounts due under this Note; or
- - The Borrower fails to perform or observe any term or covenant of this Note
or any related documents or perform any other agreement with the Bank; or
- - The Borrower fails to perform or observe any agreement with any other
creditor that relates to indebtedness or contingent liabilities which would
allow the maturity of such indebtedness or obligation to be accelerated; or
- - The Borrower changes its legal form of organization; or
- - If the holder of this Note at any time, in good faith, believes that the
undersigned will not be able to pay this Note when it is due; or
- - Any representation or warranty made by the Borrower in applying for this
loan is untrue in any material respect; or
- - A garnishment, levy or writ of attachment, or any local, state or federal
notice of tax lien or levy is served upon the Bank for the attachment of
property of the Borrower in the Bank's possession or indebtedness owed to
the Borrower by the Bank.
Automatic Acceleration: If, with or without the Borrower's consent, a
custodian, trustee or receiver is appointed for any of the Borrower's
properties, or if a petition is filed by or against the Borrower under the
United States Bankruptcy Code, or if the Borrower is dissolved or liquidated
(if an entity), or dies (if an individual), the unpaid principal, accrued
interest and all other amounts payable under this Note will automatically
become due and payable without notice or demand.
Waiver of Demand, Presentment, Notice of Dishonor and Protest: Each maker,
accommodation party, endorser or guarantor of this Note, and any other party
liable for its repayment, hereby severally waives demand, presentment, notice
of dishonor and protest.
Amendment or Modification of Terms: Any amendment or modification of this
Note must be in writing and signed by the party against whom enforcement of
such amendment or modification is sought. The Bank may also change any of
the repayment terms of this Note, including extensions of time and renewals,
and release or add any party liable on this Note, or agree to the substitution
or release of any security collateralizing this Note without notifying or
releasing from liability any maker, accommodation party, endorser or guarantor.
The Bank may suspend or waive any rights or remedies that it may have against
any person who may be liable for its repayment.
No Waiver of Defaults or Remedies: No delay on the part of the Bank in the
exercise of any right or remedy shall operate as a waiver thereof. No single
or partial exercise by the Bank of any right or remedy shell preclude any
further exercise of that or any other right or remedy, and no waiver or
indulgence by the Bank of any default shall be effective unless in writing and
signed by the Bank.
Subsequent Holders, Multiple Borrowers, and Governing Law: Any reference to
the Bank in this Note shall be deemed to include any subsequent holder of this
Note. The undersigned Borrower, if more than one, shall be jointly and
severally liable hereunder and the term "Borrower" shall mean any one or more
of them. This Note will be governed by the substantive laws of the state
where the Bank's principal office is located, and any mortgage securing this
Note will be governed by the state where the real property subject to the
Mortgage is located.
Attorneys' Fees: In the event the Bank is required to collect this Note
following its Due Date or the bankruptcy of any maker hereof, the Borrower
will pay to the Bank such further amounts as shall be sufficient to cover the
costs and expenses incurred in collecting this Note and liquidating any
security or guaranties given in support hereof, including reasonable attorneys'
fees and expenses required to take such actions in any court, including any
bankruptcy court.
Financial Reporting: While any amounts are due under this Note, the Borrower
agrees to provide to the Bank annual financial statements and such other
financial information as the Bank may request.
Arbitration
Agreement to Arbitrate: The Bank and Borrower agree to submit to binding
arbitration all claims, disputes and controversies (whether in tort, contract,
or otherwise, except "core proceedings" under the U.S. Bankruptcy Code)
arising between themselves and their respective employees, officers, directors,
attorneys and other agents, which relate in any way without limitation to this
Note, including by way of example but not by way of limitation the negotiation,
collateralization, administration, repayment, modification, default,
termination and enforcement of the loans or credit evidenced by this Note.
Rules Governing Arbitration and Selection of Arbitrator: Arbitration under
this Agreement will be governed by the Federal Arbitration Act and proceed in
the city where the Bank's principal office is located, or such other location
as the Bank and Borrower may agree in accordance with the American Arbitration
Association's commercial arbitration rules ("AAA Rules"). Arbitration will be
conducted before a single neutral arbitrator selected in accordance with AAA
Rules and who shall be an attorney who has practiced commercial law for at
least ten years.
Statutes of Limitation, Procedural Issues, Costs and Fees: The arbitrator
will determine whether an issue is arbitratable and will give effect to
applicable statutes of limitation. Judgment upon the arbitrator's award may
be entered in any court having jurisdiction. The arbitrator has the discretion
to decide, upon documents only or with a hearing, any motion to dismiss for
failure to state a claim or any motion for summery judgment. The arbitrator
will award costs and expenses in accordance with the provisions of this Note.
Discovery: Discovery will be governed by the rules of civil procedure in
effect in the state where the Bank's principal office is located. Discovery
must be completed at least 20 days before the hearing date and within 180 days
of the commencement of arbitration. Each request for an extension and all
other discovery disputes will be determined by the arbitrator upon a showing
that the request is essential for the party's presentation and that no
alternative means for obtaining information are available during the initial
discovery period.
Exceptions to Arbitration: This Agreement does not limit the right of either
party to a) foreclose against real or personal property collateral; b) exercise
self-help remedies such as setoff or repossession; or c) obtain provisional
remedies such as replevin, injuctive relief, attachment or the appointment of
a receiver during the pendency or before or after any arbitration proceeding.
These exceptions do not constitute a waiver of the right or obligation of
either party to submit any dispute to arbitration, including those arising
from the exercise of these remedies.
Page 2 of 2
ADDENDUM TO INSTALLMENT PROMMISSORY NOTE
DATED FEBRUARY 1, 1997
So long as there remains an outstanding balance under this note, GeoResources,
Inc. agrees to:
1. Provide the Bank with an audited financial statement within 120 days
after the end of each fiscal year of GeoResources, Inc.
2. Provide the Bank with a copy of its 10Q report within 45 days after
the end of each fiscal quarter.
3. Provide the Bank with such additional information as the Bank may
from time to time reasonably request.
4. Maintain a Current Ratio at all times of not less than 1.25:1 and
maintain at all times a Debt to Tangible Net Worth ratio of not more
than 1.5:1 as those terms are defined in the Amended And Restated
Secured Term Loan and Revolving Credit Agreement dated 09/01/95.
In addition to the above, GeoResources, Inc. agrees that, without the prior
written consent of the Bank, it will not:
1. Change its name, its fiscal year, or the nature of its business.
2. Reorganize or liquidate or dissolve.
3. Enter into any merger or any consolidation in which it is not the
surviving corporation.
GeoResources, Inc.
By: /s/ J. P. Vickers Its: President
Jeffrey P. Vickers
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