form-10k_123102
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC
FORM 10-KSB
[X] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002.
Commission File No. 000-31170
TETON PETROLEUM COMPANY
(Name of small business issuer in its charter)
DELAWARE 1482290
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
1600 Broadway, Suite 2400
Denver, Co. 80202 - 4921
(Address of principal executive offices)
Issuer's telephone number: 970.870.1417
Securities registered pursuant to Section 12(b) of the Exchange Act: None
Securities registered pursuant to Section 12(g) of the Exchange Act:
Common Stock
(Title of Class)
Check whether the issuer (1) filed all reports required to be filed by Section
13 or 15(d) of the Exchange Act 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 [
]
Check if disclosure of delinquent filers in response to Item 405 of Regulation
S-B is not contained in this form, and no disclosure will 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-KSB or any amendment to
this Form 10-KSB. [ X ]
The issuer's revenue for its most recent fiscal year was $6,923,320.
The aggregate market value of the common stock held by non-affiliates of the
issuer, 64,272,101 shares of common stock, as of March 24, 2003, was
approximately $23,330,772, based on the closing bid of $.363 for the issuer's
common stock as reported on the OTC Bulletin Board. Shares of common stock held
by each director, each officer named in Item 9, and each person who owns 10% or
more of the outstanding common stock have been excluded from this calculation in
that such persons may be deemed to be affiliates. The determination of affiliate
status is not necessarily conclusive.
As of March 25, 2003, the issuer had 75,942,909 shares of common stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE - NONE
Transitional Small Business Disclosure Format (Check one): YES [ ] NO[X]
PART I
Teton Petroleum Company, through its consolidated subsidiaries, is engaged
in oil and gas exploration, development, and production in Western Siberia,
Russia.
In 2001, four wells were drilled and completed on the license area. This
brought the total number of producing wells on the license area to 7. At the end
of 2001, the field was producing approximately 2,500 barrels of oil per day, 625
barrels of oil per day net to Teton. The construction of a 40-kilometer
(25-mile) pipeline was also completed. The pipeline enables us to transport and
produce oil on a year-round basis. In 2002, 6 additional wells were drilled and
completed on the license area. This brought the total number of producing wells
on the license area to 13. As of March 2003, the field was producing
approximately 7,000 barrels of oil per day, 1750 barrels per day net to Teton.
Teton reorganized its structure in 2002. After MOT withdrew from Goltech
Petroleum, LLC, Teton became the sole owner of Goltech. Goltech owns 35.295% of
the shares of Goloil. Goloil holds the oil and gas license. In this report, "We"
or "Teton" may include activities conducted by Teton, Goltech, and/or Goloil.
In 2002, Teton raised net proceeds of $4,143,643 from the issuance of
convertible debt, which was converted into common stock and warrants on
September 1, 2002, and $3,333,460 from the sales of common stock under private
placement offerings. Thus, at the end of 2002, Teton had no outstanding debt
obligations.
On March 19, 2003, the shareholders at the annual meeting of shareholders
took the following actions:
1. Elected H. Howard Cooper, Thomas F. Conroy, Karl F. Arleth, and James
C. Woodcock as directors.
2. Adopted an amendment to Teton's certificate of incorporation
increasing the authorized amount of capital stock from 100,000,000
shares to 275,000,000 shares of which 25,000,000 shares will be blank
check preferred stock.
3. Approved the 2003 Stock Option Plan.
4. Approved a one-for-twelve reverse stock split of our common stock.
5. Ratified the board of directors' selection of Ehrhardt Keefe Steiner &
Hottman PC as the corporation's independent auditors for the fiscal
year ending December 31, 2003.
Caution Concerning Forward-Looking Statements
We have included in this report, statements which are intended as
"forward-looking statements" under the Private Securities Litigation Reform Act
of 1995. These include statements that are not simply a statement of historical
fact but describe what we "believe," "anticipate," or "expect" will occur. We
caution you not to place undue reliance on the forward-looking statements made
in this report. Although we believe these statements are reasonable, there are
many factors, which may affect our expectation of our operations. These factors
include, among other things, the following:
o general economic conditions
o the market price of oil
o our ability to service our existing indebtedness
o our ability to raise additional capital, obtain debt financing, or
generate sufficient revenues to fund our operating and development
plan
o our success in completing development and exploration activities
o political stability in Russia
o changes in Russian law, currency regulations, and taxation
o our present company structure
o our accumulated deficit
o other factors discussed elsewhere in this document
Item 1. DESCRIPTION OF BUSINESS.
Structure of Teton.
Through our wholly-owned subsidiary, Goltech Petroleum LLC, we own 35.295%
of Goloil. Mediterranean Overseas Trust (together with its affiliates, including
McGrady, Fenlex, Petromed, and Energosoyuz, ("MOT")) owns 35.295% of Goloil and
serves as Manager of Goloil. InvestPetrol, a Russian Joint Stock Company, owns
the remainder (29.41%) of Goloil.
Goloil holds the license to produce oil and gas in Western Siberia. MOT and
Teton (via Goltech) are obligated to each fund 50% of the Capital Expenditures
of Goloil under their Memorandum of Understanding. Invest Petro is not funding
any of this development. Based on the current structuring of Goloil and the
development agreements with Teton and MOT, until Goltech and MOT each has been
repaid its investments in Goloil, each receives a proportion of the production
and revenues from Goloil (after the production payment to MOT) equal to the
proportion of its investment to the total investments in Goloil. Since it is
expected that this will continue for the foreseeable future, when we describe
"net" amounts to Teton, these calculations are based on Teton's right (through
its ownership of Goltech) to receive 50% of the production and revenues from
Goloil (after the production payment to MOT). The agreements affecting the
Goloil license are discussed below under "MOT Agreements."
Goltech Petroleum LLC is a limited liability company organized under the
laws of Texas. For tax purposes it is treated as a partnership. We are the sole
manager of Goltech and have complete authority to manage its business. Petromed
(MOT) withdrew as a member and manager of Goltech in 2002. In connection with
its withdrawal, Petromed received a distribution consisting of Goloil shares and
return of its original $1 million contribution.
Goloil is a closed joint stock company organized under the laws of Russia.
Russian joint stock companies are corporate entities with limited liability
similar to corporations formed under United States laws. Shareholders of Russian
joint stock companies generally are not liable for debts and obligations of the
company. However, shareholders of a bankrupt joint stock company may be held
liable for debts and obligations of the bankrupt company if they have exercised
their authority to undertake an action knowing that bankruptcy would be a
possible result of their actions. Any transfer of shares by a shareholder to a
third party is subject to a right of first refusal by the other shareholders.
Under Russian law, a simple majority of voting shares is sufficient to
control adoption of most resolutions. Resolutions concerning amendment of the
company charter, reorganizations (including mergers) liquidation, any increase
in authorized shares, or certain "large" transactions require the approval of
the shareholders holding 75% of the outstanding shares.
A Russian joint stock company has no obligation to pay dividends to the
holders of common shares. Any dividends paid to shareholders must be recommended
by the board of directors and then approved by a majority vote at the general
meeting of shareholders. The Memorandum of Understanding between MOT and Teton
(the controlling shareholders) provides that any excess cash will be used to pay
back investments on a quarterly basis.
Teton History.
Teton was formed by the November 1998 merger of EQ Resources Ltd. and
American Tyumen Exploration Company. EQ was incorporated in Ontario, Canada, on
November 13, 1962, under the name Mangesite Mines Limited. Its name was changed
to EQ Resources Ltd. in August 1989. EQ was domesticated in Delaware immediately
prior to the merger. In the merger, EQ, the survivor corporation, was renamed
Teton Petroleum Company.
At the time of the merger, Teton's holdings consisted of licenses for the
exploration of gold in Ghana, licenses for oil and gas in Dagestan, Russia, and
the Goloil license. Following the merger, we decided to focus our efforts and
resources on development of the Goloil license. We disposed of our interest in
the Ghana gold licenses. We also wrote down the value of the Dagestan licenses
to zero on our financial statements in 1998, and disposed of our subsidiary
Teton Oil, Inc. which held the Dagestan licenses effective May 24, 2001. In our
opinion, political instability in the Dagestan region made operations in
Dagestan too risky. Due to inactivity most of our Dagestan licenses had
terminated prior to our disposition of Teton Oil, Inc.
MOT Agreements.
In June 2000, Teton, Goltech and Fenlex Nominee Services Limited, as sole
trustee of the Mediterranean Overseas Trust, a trust organized under the laws of
Malta entered into a Master Agreement. The Master Agreement contemplated the
following transactions:
(a) Purchase of 50% of the interest in Goltech in exchange for $1,000,000.
(b) Additional investment by MOT, of up to $5,600,000, through an oilfield
development and leasing arrangement, paid on an as needed basis to
cover certain costs related to the pipeline, processing facility, and
drilling of five additional wells.
(c) Payment of leasing fees and repayment of amounts advanced by MOT
through a production payment in the form of crude oil.
(d) Additional work, as agreed to by the parties.
The purchase of 50% of the interests in Goltech was completed in August
2000. See, also " - Structure of Teton."
As contemplated in the Master Agreement, Goloil and MOT (through
Energosoyuz) entered into an oilfield development agreement and a lease
agreement. These agreements provided, among other things, for the drilling and
operation of five additional wells on the Goloil license lands and for
Energosoyuz to fund up to $5,600,000 to cover certain costs related to
development of a pipeline and processing facility and the drilling of five
additional wells.
The wells and facilities constructed by Energosoyuz pursuant to the
oilfield development agreement are leased to Goloil for a seven-year production
payment. The production payment is equal to 50% of the crude oil produced by the
new and existing Goloil wells. The production payment period will be extended if
the production payment falls below an average of 80,000 tons (583,200 barrels)
of oil per year or if the market price of Ural Oil Blend falls below a weighted
average of $17 per barrel, for oil sold outside of Russia, over the seven year
period.
At March 2002, the full $5,600,000 contemplated in the MOT agreements was
invested by MOT. The pipeline and four of the wells were completed in 2001. The
fifth well was completed in early 2002. Construction of a processing plant is
also in progress and should be completed in 2003.
After the production payment is paid in full, the MOT agreements provide that
one of the following shall occur:
1. Energosoyuz will merge into Goltech.
2. 100% of the capital stock of Energosoyuz will be transferred to
Goltech.
3. The outstanding capital stock of Energosoyuz will be distributed
equally between Teton and MOT or its nominee.
4. Any other action agreed to by the parties resulting in a division of
the revenues of Energosoyuz between Teton and MOT or its nominees in
proportion to their respective ownership in Goltech.
In late 2002, MOT elected to withdraw from Goltech in exchange for its 50%
of the shares in Goloil held by Goltech. This has been accomplished under a
Memorandum of Understanding and withdrawal agreement. A new management agreement
for Goloil is the process of being completed and finalized consistent with the
intent of the MOU. As part of these negotiations, the production payment
agreement was clarified to state a fixed term of 7 years from inception (July 1,
2000) and that all oil received under the agreement would be sold as Russian
domestic oil, thus allowing about 90% of the remainder to be sold in the export
markets currently.
Production and Distribution.
A glossary of certain oil and gas terms used in this report is found at
"DESCRIPTION OF PROPERTY--Glossary of Geologic Terms."
As of March 25, 2003, the wells on our license area were producing approximately
7,000 barrels per day (1,750 barrels net to Teton). Completion of a 40-kilometer
(25-mile) pipeline on June 4, 2001 has enabled oil to be pumped from these wells
all year long. Prior to completion of the pipeline, no oil was produced during
certain times of the year because of transportation difficulties. At December
31, 2001, seven wells were completed on our license area. At December 31, 2002,
13 wells were completed on our license area. For 2003, 5 additional wells are
planned to be drilled and completed.
Pursuant to the MOT agreements, MOT is entitled to a production payment in kind.
See " - MOT Agreements." The production payment is projected to be completed in
June, 2007, based on revised leases negotiated in late 2002.
Teton also pays processing and transportation fees to a third party to process
and place its oil in the Trans-Siberia pipeline. The current charge for the
processing and transportation is 2.5% of our daily production. Construction of a
processing facility on the license area is in progress. When completed we will
no longer incur the third-party processing charge. We expect the processing
facility will be completed in the second quarter of 2003.
Teton's share of the oil production is sold in Poland, Germany, Belorussia,
Ukraine and Russia. Sales in Poland, Germany, Ukraine and Belorussia are in
United States dollars. Oil sold in Russia is in rubles. Pursuant to the terms of
the Goloil license and pipeline quotas issued by Trans-Neft, the government
owned pipeline monopoly, up to a maximum of 35% of Goloil's oil production may
be sold outside of the CIS and an additional 10% can be sold to other CIS
states. Currently, MOT is required to sell the oil it receives as a production
payment into the Russian domestic market. Thus, until the production payment is
paid in full, we are able to sell 90% of our share of the production outside of
Russia. Currently there are no long-term contracts for the sale of our oil. We
currently are not dependent on any principal customer.
The chart below sets forth certain production data for the last three fiscal
years. Additional oil and gas disclosure can be found in Note 12 of the
Financial Statements.
PRODUCTION DATA
Year Ended December 31 2002 2001 2000
Total Gross Oil Production,
barrels ........................ 1,884,933 425,459 178,331
Total Gross Gas Production, MCF . 0 0 0
Net Oil Production, barrel(1) ... 471,233 94,879 142,664
Net Gas Production, MCF ......... 0 0 0
Average Oil Sales Price,
S/Bbl(2) ....................... $15.38 $16.43 $11.00
Average Gas Sales Price, S/MCF .. 0.00 0.00 0.00
Average Production Cost per
Barrel (3) ..................... $9.96(4) $11.22 $10.00
Gross Productive Wells ..........
Oil ............................. 13 7 3
Gas ............................. 0 0 0
- - -
Total ................. 13 7 3
Net Productive Wells(2)
Oil ............................. 6.5 3.5 1.5
Gas ............................. 0 0 0
--------- ------- ------
Total ................. 6.5 3.5 1.5
-----------
(1) Net production and net well count is based on Teton's effective net
interest as of the end of each year. Prior to August 2000 and after
November, 2002, Teton owned 100% of the interests in Goltech.
(2) Average oil sales prices is a combination of domestic (Russian) and export
price. As a result of the MOU signed December 1, 2002 and the increase in
end of period oil prices, the current average price received by the company
is $22.84 as of December 31, 2002.
(3) Excludes production payment to MOT.
(4) If the cost of the production payment, which requires Teton to cover all
lifting and G&A costs, is included, the cost per barrel net to Teton is
$15.51 per barrel. See also "MANAGEMENT'S DISCUSSION AND ANALYSIS - Results
of Operations."
The following chart sets forth the number of productive wells and dry
exploratory and productive wells drilled and completed during the last three
fiscal years in the Goloil license area:
NET WELLS DRILLED
Year Ended December 31 2002 2001 2000
-------------- ------------- --------------
Gross Net(1) Gross Net(1) Gross Net(1)
-------------- ------------- --------------
Number of Wells Drilled
Exploratory (Research)
Productive 0 0 1 .5 0 0
Dry 0 0 0 0 0 0
-------------- ------------- --------------
Total 0 0 1 .5 0 0
Development
Productive 6 3 3 1.5 2 1
Dry 0 0 0 0 0 0
-------------- ------------- --------------
Total 6 3 3 1.5 2 1
============== ============= ==============
----------
(1) Net well count is based on Teton's effective net interest as of the end of
each year. Prior to August 2000, Teton owned 100% of the interests in
Goltech. Subsequent to August 2000 our interest was reduced to 50%. In
November, 2002, it again became 100%.
United States Trade and Development Agency (TDA) Grants.
In October 2001, Teton finished its study of the feasibility of oil exploration
in the Novo-Aganskoye, Galinovaya and East Galinovaya license area of Siberia
pursuant to an agreement with Varioganneft JSC. The study was funded by a
$250,000 grant from the TDA. In 2001, we received a final payment of $37,500
from the TDA for the study. Currently, we do not expect to make any investments
in the Novo-Aganskoye, Galinovaya and East Galinovaya license area. Thus, we do
not expect to incur any obligation to repay the amounts paid by the TDA in
connection with this study.
Teton expects to complete its feasibility study of the Eguryak license area
pipeline project in 2003. This study is also funded through a $300,000 grant
from the TDA. Teton has received $255,000 of the grant amount. The balance of
the grant funds will be paid upon completion of the study. Teton may be required
to repay the TDA the grant amount if Teton makes certain investments in the
Eguryak license area prior to December 31, 2005.
Competition.
We compete in a highly competitive industry. We encounter competition in all of
our operations, including property acquisition, and equipment and labor required
to operate and to develop our properties. Teton competes with other major oil
companies, independent oil companies, and individual producers and operators.
Many competitors have financial and other resources substantially greater than
ours.
Regulations Governing Russian Joint Stock Companies.
Russian joint stock companies are corporate entities with limited liability
similar to corporations formed under United States laws. Shareholders of Russian
joint stock companies generally are not liable for debts and obligations of the
company. However, shareholders of a bankrupt joint stock company may be held
liable for debts and obligations of the bankrupt company if they have exercised
their authority to undertake an action knowing that bankruptcy would be the
result of their actions. In closed joint stock companies, i.e. companies with a
limited number of shareholders, such as Goloil, any transfer of shares by a
shareholder to a third party is subject to the pre-emptive right of the other
shareholders to acquire such shares at the price offered to a third party.
Under Russian law, a simple majority of voting shares is sufficient to control
adoption of most resolutions. Resolutions concerning amendment of the company
charter, reorganizations (including mergers), liquidation, any increase in
authorized shares, or certain "large" transactions require the approval of the
shareholders holding 75% of the outstanding shares.
A Russian joint stock company has no obligation to pay dividends to the holders
of common shares. Any dividends paid to shareholders must be recommended by the
board of directors and then approved by a majority vote at the general meeting
of shareholders. Dividends may be paid every quarter of a year. The Memorandum
of Understanding between MOT and Teton (the controlling shareholders) provides
that any excess cash will be used to pay back investments on a quarterly basis.
Environmental Regulation.
The government of the Russian Federations, Ministry of Natural Resources, and
other agencies establish special rules, restrictions and standards for
enterprises conducting activities affecting the environment. The general
principle of Russian environmental law is that any environmental damage must be
fully compensated. Under certain circumstances, top officers of the entity
causing substantial environmental damage may be subject to criminal liability.
The law of the Russian Federation on subsoil requires that all users of subsoil
ensure safety of works related to the use of subsoil and comply with existing
rules and standards of environment protection. Failure to comply with such rules
and standards may result in termination or withdrawal of the Goloil license.
Goloil Taxation.
As a Russian resident entity, Goloil is subject to all applicable Russian taxes,
many of which currently impose a significant burden on profits. The most
significant Russian taxes and duties affecting Goloil include:
(i) 20% value added tax (established pursuant to Chapter 21 of the Tax
Code of Russia), applicable only to domestic sale of goods in Russia
and the Ukraine. No value added tax is payable on goods exported to
the West from Russia;
(ii) 20 to 24% profit tax which includes 6% federal profit tax, 12 to 16%
regional profit tax and 2% local tax (in accordance with Chapter 25 of
the Tax Code of Russia). Russian law allows the carry forward and use
of losses, subject to limitations;
(iii)Income tax on dividends payable to Goloil's shareholders. The tax
must be withheld by Goloil from the amount distributed to each
shareholder. The current rate of tax on dividends payable to corporate
foreign shareholders is 15%. However, dividends payable to Goltech, a
United States resident company, are subject to regulations contained
in the United States - Russia tax treaty which limits the tax on
dividends payable to Goltech to 5% (as long as Goltech holds more than
a 10% interest in Goloil);
(iv) Tax on production of minerals applicable to all subsoil users
producing minerals, including crude oil. For the period ending on
December 31, 2004, the tax is temporarily established at 340 rubles
(ca. USD 10.83) per metric ton produced by the taxpayer multiplied by
a factor (F) calculated pursuant to the formula:
F = (U-8) x R/252
where:
U - means the average market price of Urals blend crude oil (in
dollars per barrel) during the relevant tax period;
R - means the average ruble for dollar exchange rate quoted by
the Central Bank of Russia for the relevant tax period.
After expiration of the temporary tax rate period, the tax will apply
at the rate of 16.5% of the value of the oil produced by the taxpayer;
(v) Unified social tax (established pursuant to Chapter 24 of the Tax Code
of Russia) at the rate of up to 35.6% of the payroll;
(vi) Transport tax (established pursuant to Chapter 28 of the Tax Code of
Russia) payable by owners of motor vehicles at the rate established by
regional authorities based on the type and capacity of the vehicle.
The maximum amount of tax payable by an owner of a motor car per year
is RUR 150 (ca. USD 4.78) per horsepower;
(vii)Oil export duty, currently in the amount of USD 25.9 per ton of crude
oil being exported;
(viii) Regional property tax payable annually at 2% of the value of assets
of the entity.
The Russian tax system currently is undergoing a major reorganization. New tax
laws including those setting forth rules for application of the value-added tax,
profit tax, and tax on the production of minerals were enacted within the last
four years. The cost of legal and accounting advice to keep up with changes in
the Russian tax laws may be significant and penalties for violations, even
inadvertent ones, may be steep. If revisions impose confiscatory taxes, our
profitability will be adversely affected.
Employees.
Teton currently has four full time and four part time employee. We also utilize
the services of independent contractors on an as-needed basis. Goloil currently
employs approximately 100 employees in Western Siberia and Moscow. Goloil also
uses independent contractors on as needed basis.
Item 2. DESCRIPTION OF PROPERTY.
Glossary of Geological Terms.
Barrel: Equal to 42 U.S. gallons.
Basin: A depressed sediment-filled area, roughly circular or elliptical in
shape, sometimes very elongated. Regarded as good areas to explore for oil and
gas.
Field: A geographic region situated over one or more subsurface oil and gas
reservoirs encompassing at least the outermost boundaries of all oil and gas
accumulations known to be within those reservoirs vertically projected to the
land surface.
License: Formal or legal permission to explore for oil and gas in a specified
area.
Productive: Able to produce oil and/or gas.
Proved reserves: Estimated quantities of crude oil, condensate, natural gas, and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be commercially recoverable in the future from known
reservoirs under existing conditions using established operating procedures and
under current governmental regulations.
Proved undeveloped reserves: Economically recoverable reserves estimated to
exist in proved reservoirs, which will be recovered from wells, drilled in the
future.
Reserves: The estimated value of oil, gas and/or condensate, which is
economically recoverable.
Tons: A ton of oil is equal to 7.29 barrels of oil.
Goloil License.
The Goloil license encompasses 187 square kilometers (78 square miles) in the
south central portion of the west Siberian basin. It is located approximately 10
miles to the north and west of Samotlor, Russia's largest oil field. Three
producing fields are located within the license area: Golevaya, Eguryak, and
South Eguryak. The Goloil license expires in 2022, and may be extended upon
compliance with the specified program of operations and undertaking of
additional operations after the end of its term. The Goloil license may be
terminated prior to its term if Goloil fails to comply with the requirements of
the license. We believe that we are currently in compliance with all material
terms of the Goloil license.
Proved Reserves and Present Value Information.
Our estimated proved oil reserves and present value of the estimated future net
revenues attributable to such reserves as of January 1, 2003, are based upon a
report, as supplemented, issued by the independent consulting firm of Gustavson
Associates, Inc. ("Gustavson"), located in Boulder, Colorado. In June 2001,
based on a supplemental letter issued by Gustavson, our proved reserve estimate
was reduced by 37.3 million barrels gross (12.4 million barrels net to Teton).
In the supplemental letter, Gustavson noted that questions had been raised
concerning the sufficiency and completeness of the data used to establish
certain reserves recoverable by secondary recovery methods were "proved." Thus,
Gustavson withdrew those reserves from the proved category. Subsequently, a
water flood feasibility study was conducted by Gustavson. Based on that study,
our estimated proved reserves were increased by 57.5 million barrels gross (33.6
million barrels net to Teton). Finally, an update to the study using data from
recently drilled wells and other sources, reduced the reserve estimate to a
proved amount of 39,6 million barrels gross, 19.8 million net to Teton. These
reserve estimates include reserve quantities which are required to be delivered
under the production payment and total 13.0 million gross barrels and 6.5
million net barrels, respectively. This update also determined that
waterflooding techniques would not be needed for recovery in most areas of the
field, thereby reducing the future projected recovery costs substantially. In
addition fewer wells would be required to be drilled reducing future development
costs, and accordingly as a result net development costs to Teton have been
reduced from $91.2 million to $20.05 million.
The Securities and Exchange Commission requires that estimates of reserves,
estimates of future net revenues and the present value of estimated future net
revenues be based on the assumption that oil and gas prices will remain at
current levels (except for gas prices determined by fixed contracts), and that
production costs will not escalate in future periods. All such estimates have
been adjusted for the anticipated costs of developing proved undeveloped
reserves.
Reserve calculations require estimation of future net recoverable reserves of
oil and gas and the timing and amount of future net revenues to be received
therefrom. Such estimates are based on numerous factors, many of which are
variable and uncertain. Accordingly, it is common for the actual production and
revenues later received to vary materially from earlier estimates. Estimates
made from the first few years of production from a property are not likely to be
as reliable as later estimates based on longer production history. Hence,
reserve estimates and estimates of future net revenues from production may vary
from year to year.
The Company has not filed reserve estimates with any federal agency.
As of January 1, 2003, our proved reserves are estimated at 19.8 million
barrels, net to Teton, including quantities required to be delivered under the
production payment as summarized below:
Before Profits Tax (2) After Profits Tax (2)
----------------------------------- ----------------------------
Case Net Total Present Value Total Present Value
Reserves, Undiscounted Discounted Undiscounted Discounted
Billion Cash flow, million @10%, million Cash Flow @10%, million
barrels(1) US$ US$ million US$ US$
--------------- ------------------ ------------- ------------ --------------
Proved 3.8 $11.61 $10.03 $9.91 $8.66
Developed
Producing
Proved 3.3 $11.82 $7.31 $9.01 $5.59
Developed
Non-Producing
Proved 12.7 $37.83 $16.69 $29.15 $12.57
Undeveloped
Total Proved 19.8 $61.26 $34.03 $48.07 $26.81
(1) Quantities presented include 2.0 million PDP, 2.5 million PDNP, for a total
of 6.5 million barrels (which includes the 2.0 million for PDP and 2.5
million for PDNP) required to be delivered under a production payment for
proved developed producing, proved developed non-producing, and total
proved reserves, respectively.
(2) Cash flow amounts assume 50% economics net to Teton without payout. Teton's
net share is 50% before payout and 35.295% after payout.
Reserve estimates were decreased in the current projections based upon
assumptions revised for additional data derived from production and other data
from the additional wells producing in 2002. While the reserve estimates have
decreased, this additional data also decreased estimated costs of recovery and
other capital investments as less wells will be needed and certain portions of
the field will not require water flood techniques to be used.
The results are net to Teton and include the impact of the production payments
due MOT, and financing and debt repayment. The present value of estimated future
net revenues as of January 1, 2003, has not been adjusted for income taxes.
Teton is not currently incurring any repatriation tax liability due to the
structuring of capital input as a loan. Management believes that future
repatriation tax liabilities will not be incurred if profits from this project
are invested in other projects within Russia. If Teton does not incur
repatriation tax liability for the life of this project, the undiscounted total
before and after tax cash flow, after production payments would be $61.26 and
$48.07 million or, discounted at 10%, $34.03 and $26.81 million, for total
proved reserves.
There can be no assurance that the reserves described herein will ultimately be
produced or that the proved undeveloped reserves described herein will be
developed within the periods anticipated. Recovery of undeveloped reserves
requires significant capital expenditures and successful drilling operation. The
cash flows summarized herein should not be construed as representative of the
fair market value of the reserves. Actual results are likely to differ greatly
from the results estimated.
Capital expenditures required to achieve the above cash flows are estimated at
$20.06 million net to Teton for development of proved reserves. Based on our
reserve analysis, we expect that cash flow from operations will fully cover both
operating expenses and capital investment starting in 2005.
Our current agreement with MOT requires MOT and Teton to each fund half of the
capital expenditures required for development. In the event we are unable to
fund our portion of the capital expenditures and MOT proceeds with the planned
development, our share of the oil production will be decreased. The reverse is
also true.
Until cash flow from operations is sufficient to fund operating expenses and
capital investment, Teton must raise additional capital or obtain debt financing
to fund its portion of capital expenditures or its interest in the oil
production will be reduced. There can be no assurance that Teton will be
successful in raising such additional funds.
The following table sets forth the total gross and net developed acres and total
gross and net underdeveloped acres subject to the Goloil License as of December
31, 2002:
DEVELOPED AND UNDEVELOPED ACREAGE:
Eguryak License Area:
Total Developed Acres
Gross 1,236
Net 618
Total Proved Undeveloped Acres
Gross 2,000
Net 1,000
Total Other Undeveloped Acres
Gross 5,778
Net 2,889
Teton Offices.
Our offices are located in Denver, Colorado. We lease our offices from an
unaffiliated third party.
Item 3. LEGAL PROCEEDINGS.
Teton currently is not a party to any material legal proceedings.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matters were submitted to a vote of our security holders during the fourth
quarter of 2002.
PART II
Item 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDERS MATTERS.
Market for Common Stock.
Teton's common stock has been quoted on the OTC Bulletin Board under the symbol
"TTPT" since November 27, 2001. Prior to that and until our voluntary delisting
in January 2002, our common stock was also listed on the Canadian Venture
Exchange under the symbol "YTY.U." Beginning November 30, 2001, our common stock
is also listed for trading on the Frankfort Stock Exchange (Germany) under the
symbol "TP9."
The following table sets forth, on a per share basis, the range of high and low
bid information for the common stock on the OTC Bulletin Board for the last
quarter of 2001 and first quarter of 2002, and on the Canadian Venture Exchange
for the last two fiscal years:
OTC BULLETIN BOARD
2001 PERIOD HIGH LOW
----------- ---- ---
Fourth Quarter $.50 $.17
2002 PERIOD
-----------
First Quarter $.67 $.18
Second Quarter $.65 $.36
Third Quarter $.60 $.27
Fourth Quarter $.42 $.21
2003 PERIOD
-----------
First Quarter $.46 $.28
The quotations reflect interdealer prices without retail markup, markdown, or a
commission, and may not necessarily represent actual transactions.
Holders. As of March 25, 2003, there were approximately 247 holders of record of
Teton's common stock.
Dividends. Teton has not paid any dividends on its common stock since inception.
Teton does not anticipate declaration or payment of any dividends at any time in
the foreseeable future.
Item 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION.
Critical Accounting Policies
We have identified the policies below as critical to our business
operations and the understanding of our results of operations. The impact and
any associated risks related to these policies on our business operations is
discussed throughout Management's Discussion and Analysis of Financial Condition
and Results of Operations where such policies affect our reported and expected
financial results.
In the ordinary course of business, we have made a number of estimates and
assumptions relating to the reporting of results of operations and financial
condition in the preparation of our financial statements in conformity with
accounting principles generally accepted in the United States. Actual results
could differ significantly from those estimates under different assumptions and
conditions. We believe that the following discussion addresses our most critical
accounting policies, which are those that are most important to the portrayal of
our financial condition and results of operations and require our most
difficult, subjective, and complex judgments, often as a result of the need to
make estimates about the effect of matters that are inherently uncertain.
Pro-rata Consolidation.
We use the pro-rata consolidation method to reflect the financial position and
results of operations of our now 100% owned subsidiary Goltech Petroleum, LLC
(Goltech) that owns 35.295% of the outstanding stock of Goloil. In the fourth
quarter of 2002, the other 50% owner of Goltech (MOT) withdrew from Goltech in
exchange for its 50% Interest in Goltech's investment in Goloil (35.295% of the
stock of Goloil).
Teton and MOT's agreement with Goloil is that they will receive all of their
investment back plus interest from the profits of Goloil before the other
shareholder, Invest Petrol, can receive any distributions. Invest Petrol and its
predecessor shareowners have not contributed any funds to the development of
Goloil's license and its current equity in Goloil is negative, so Teton (via
Goltech) and MOT have each been absorbing 50% of Goloil losses. Invest Petrol
will have no interest in Goloil's losses or profits for the foreseeable future.
Goloil holds a license to develop oil & gas reserves in Western Siberia and
constitutes the only significant asset we hold. Under the pro-rata consolidation
method we include the assets, liabilities, revenues and expenses of the
consolidated accounts of Goltech. The intercompany balances of Goloil, Goltech
and Teton do not fully eliminate under the pro-rata consolidation method, and
the remaining receivable on Teton's accounts has been included as a component of
oil and gas properties, as this balance will only be repaid through net cash
flow generated from oil and gas properties.
Recoverability of Oil & Gas Properties.
The recoverability of our investment in oil and gas properties is reviewed
annually and based on the net discounted cash flows to be obtained from our
share of the production of oil and gas by Goloil using assumptions similar to
those in the reserve study prepared by an independent petroleum engineer. The
reserve study is subject to inherent limitations and uncertainties and is
prepared using economics for the Company's 100% interest in Goltech, LLC, which
includes the Company's share of a 35.295% interest in Goloil. If the average
cost of oil production sold, the costs to produce and transport the oil for sale
or further development capital expenditures change adversely to the Company,
such changes could cause a material write down of our investment in such
properties or abandonment altogether of our continued efforts to develop and
produce those oil and gas reserves. Management believes that the economic
conditions will remain favorable to the Company for the oil and gas prices it
receives from production and the costs we incur for producing, transporting and
continued license development capital expenditures, and it will recover all such
investments in its oil and gas properties.
Oil and Gas Reserves and Supplemental Information.
The information regarding the Company's share of oil and gas reserves, the
changes thereto and the resulting net cash flows are all dependent upon
assumptions used in preparing the Company's annual reserve study. A qualified
independent petroleum engineer in accordance with standards of applicable
regulatory agencies and the Securities and Exchange Commission definitions,
prepares the Company's reserve study. That reserve study is prepared using
economics for the Company's 100% interest in Goltech, LLC, which includes the
Company's 35.295% interest in Goloil. Such reserves and resultant net cash flows
are subject to the inherent limitations in those estimates that include the cost
of oil and gas production, costs related to future capital expenditures, the
price per barrel of oil sales, the Company's share of those reserves, the taxing
structure of the Russian Federation and other factors. Changes in one or all of
these items could cause a material change in the reserve estimates and the net
cash flows from the sale of production generated from those reserves. Management
believes that the current assumptions used in preparation of the reserve study
are reasonable.
Results of Operations.
Comparison of Year Ended December 31, 2002 to December 31, 2001.
We had revenues from oil and gas production of $6,923,320 for the twelve months
ended December 31, 2002 as compared to $1,625,352 for the twelve months ended
December 31, 2001. Revenues were increased by a significant increase in
production throughout 2002 as new wells came on line. "Net to Teton" production
at December 31, 2002 was approximately 1,750 barrels per day. This production
increase was partially offset by a reduction in the price per barrel received as
explained further below.
Under a production payment agreement entered into to finance the completion of 5
wells in 2001 and 2002, the completion of a pipeline to the Trans Neft pipeline,
and the construction of a DNS plant (scheduled for completion in 2003), 50% of
the oil produced on the license through June 30, 2007 is paid to the financing
entity, which is an affiliate of MOT. The pipeline was completed in June 2001,
allowing Goloil to transport oil 12 months a year, rather than the previous 7 or
8 months per year, because of adverse weather conditions.
Effective December 1, 2002, as well as prior to April 1, 2002, all oil
transferred under the agreement is counted as Russian domestic sales, therefore
the full Goloil export quota can be used for the remaining production. This
results currently in approximately 90% of Teton's net production being exported.
Between April 1 and December 1, the production payment participated
proportionately in export as well as domestic sales.
The Production changes resulted in net barrels of approximately 450,000 to Teton
in 2002 compared to net barrels of approximately 95,000 in 2001. The average
price per barrel we received decreased in 2002 to approximately $15.38 from
$16.43 in 2001. Because the production payment was participating in export sales
for a portion of the year, the "net to Teton" sales in 2002 contained a larger
portion of Russian domestic sales than in 2001. In addition, Russian domestic
prices, particularly in the winter when ports are closed and tanker exports are
precluded, were lower than in 2001. Higher export prices partially offset this
difference. As a result of signing the MOU on December 1, 2002 and higher
current oil prices, the Company was receiving an average price per barrel at
year-end of approximately $22.84. The Company is optimistic that the oil prices
received in 2003 will continue to remain higher than in the prior year.
Cost of oil and gas production before Depreciation, Depletion and Amortization
increased to $2,741,303 for the twelve months ended December 31, 2002 from
$1,068,250 or the twelve months ended December 31, 2001. The increase of
$1,673,053 relates to substantial increases in volume produced to include oil
produced under the production payments to MOT made for leasing new wells and the
pipeline, offset by improved efficiencies from higher production and lower
transportation costs in 2002.
Taxes other than income taxes, which includes VAT, excise, mining and other
applicable taxes increased by $3,042,201 in 2002 to $3,537,990 from $495,789 in
2001. The increase is a result of a substantial increase in the mining
(extraction) tax, which is indexed to the World price of Oil regardless of where
the oil is actually sold. The increase in mining tax totaled approximately
$2,430,000. The remaining increase is due to increased sales resulting in
increased VAT in 2002.
The economics of the cost to produce an average barrel of oil, including taxes,
decreased in 2002 from approximately $10.18 to $9.96. However, as a result of
the production payment required with the Company covering all lifting costs and
extraction taxes, the cost per barrel net to the Company was approximately
$15.51 per barrel as the Company had fewer barrels net to cover these costs.
A breakdown of costs and expenses per bbl. is as follows:
2002 2001
----------------------- ----------------------
Cost Category
Before Net of Before Net of
Production Production Production Production
Payment Payment Payment Payment
----------- ----------- ----------- ----------
Controllable Costs:
Lifting Costs $1.62 $3.24 $2.75 5.50
Goloil General & Administrative 0.73 1.46 1.62 3.24
----------- ----------- ----------- ----------
Total Controllable Costs $2.35 $4.70 $4.37 $8.74
Non-Controllable Costs:
Mining & Misc. Taxes 3.20 6.40 1.91 3.82
Value Added Tax (VAT) 0.80 0.80 0.53 0.53
Transportation, Duties etc. 3.61 3.61 3.37 3.37
----------- ----------- ----------- ----------
TOTAL Costs $9.96 $15.51 $10.18 $16.46
=========== =========== =========== ==========
Controllable costs, i.e. Lifting Costs and G&A Costs, have declined dramatically
on a "per barrel" basis as a result of the higher levels of production and the
efficiencies gained from that.
Taxes have risen, however, principally because of a new formula for the Mining
or Extraction tax, which is indexed to the World Price of Oil, regardless of
where the oil is sold. In December, this resulted in a per barrel mining tax
that exceeded the per barrel receipts of sales in the Russian domestic market.
The disparity between world prices and prices in the domestic market has been
unusually large in 2002.
Currently, because of the renegotiated production payment, Teton's share of
Goloil production may be sold 90% in the export market and 10% in the Russian
domestic market, under a government agency (TransNeft) allotment, which the
agency can change. Domestic oil sells at a lower price, but does not incur
transportation costs and other costs and taxes related to export. This resulted
in a December average selling price of $22.84 per barrel. Having the revised
Production Payment in force for the full year 2003 will have the effect of
raising the average price per barrel received without any increase in per barrel
costs.
General and administrative expenses of $5,333,726 were incurred for the twelve
months ended December 31, 2002 as compared to $1,521,970 for the twelve months
ended December 31, 2001. The increase in general and administrative expenses of
$3,811,756 reflects a significant increase in travel, consulting, legal, and
accounting expenses in 2002. Increased capital raising required additional "road
show" activities, public forum presentations, and increases in the number of
individuals participating in these activities. This was reflected in increases
in consulting fees, travel costs and legal fees. The addition of a COO, CFO, and
a Russian accounting consultant increased consulting fees and travel costs. The
restructuring of Goltech and the renegotiation of the production payment and
related agreements also increased legal fees and travel costs. Goloil general
and administrative expenses increased in 2002 by approximately $288,000 from
2001 due to the expanded operations. We expect that these expenses will return
to a level of under $2,000,000 annually in 2003.
Depreciation, depletion and amortization was $451,930 for the twelve months
ended December 31, 2002 as compared to $45,313 for the twelve months ended
December 31, 2001. The increase in 2002 represents increased capitalized costs
subject to depreciation and depletion, and an increase in amortization arising
from changes in estimated recoverable reserves.
The Company also incurred financing costs of $5,498,106 during the twelve months
ended December 31, 2002 for the amortization of discount related to warrants
issued in connection with certain related party notes payable of $354,000
(non-cash), amortization of the discount on warrants issued with the convertible
debentures and in-the-money conversion feature discounts of $4,558,000
(non-cash) immediately recognized, and $467,000 of expenses paid related to the
10% premium paid in common stock upon the conversion of the debentures on
September 1, 2002. The remainder of these costs were expenses paid related to a
debenture purchase agreement with a potential investor that was not consummated.
While the stock to which the conversion rights and warrants apply is restricted
stock, the valuation with respect to this stock in calculating the discount was
"as if" the stock was immediately salable. The effect of this is to make the
amount of discount and its related amortization higher than it would otherwise
have been. Management believes these costs will not be indicative of future
operations and will manage future capital raising programs to minimize or
eliminate these costs.
Other income increased for the twelve months ended December 31, 2002 by $42,370,
principally from interest on Goloil notes.
Interest expense for the twelve months ended December 31, 2002 was $385,939 as
compared to $161,019 for the twelve months ended December 31, 2001. The increase
of $224,920 reflects cash and non-cash interest costs on the convertible debt
outstanding for a portion of the year.
Of our net loss of $10.97 million, we incurred significant non-cash charges
totaling approximately $6.95 million, including 452,000 for depreciation,
depletion and amortization, $1.1 million in equity compensation charges issued
for services provided and $5.4 million for financing charges associated with our
convertible debentures issued. These charges accounted for $.18 per share of our
$.29 per share loss.
Liquidity and Capital Resources.
The Company has cash balances of $712,013 at December 31, 2002, with positive
working capital of $176,042.
The Company received substantial subscriptions for Common Stock under its
private placement offering in 2002. Through March 25, 2003, $1,939,610 has been
received under these subscriptions. This amount has been recorded as
Subscriptions Receivable at December 31, 2002.
Cash used from operations totaled $5,168,785, including non-cash adjustments to
our net loss of 10,973,923 for 452,000 of depreciation, depletion and
amortization, $1.1 million in equity compensation charges issued for services
provided and $5.4 million for financing charges associated with our convertible
debentures issued.
The Company used $3,222,349 of cash in investing activities, which was all
invested in oil and gas property and equipment.
The Company had cash provided by financing activities of $9,061,418 which
included $4,143,643 net proceeds from issuance of Convertible Debt, which was
called on September 1, 2002 in exchange for Common Stock and Warrents,
$3,333,460 net proceeds received from the sales of common stock under private
placement offerings and, as part of the effects of the pro-rata consolidation of
Goloil, advances from MOT to Goloil of $2,178,525. Teton is not a guarantor to
MOT on the advances to Goloil, should Goloil not be able to repay them. Net
reductions in Notes Payable of $594,210 also occured.
Our current agreement with MOT requires MOT and Teton to each fund half of the
capital expenditures required for development. In the event we are unable to
fund our portion of the capital expenditures and MOT proceeds with the planned
development, our share of the oil production will be decreased. The reverse is
also true.
Capital expenditures (our 50%) required to achieve the cash flows projected in
our reserve report are now estimated at a total of $20.05 million net to Teton
over the next 20 years for development of proved reserves, versus the prior
estimate of $91.2 million net to Teton over 20 years. Based on our reserve
analysis, we expect that cash flow to Teton from operations will fully cover
both operating expenses and capital investment starting in 2005.
In 2003, we expect to invest approximately $6.5 million in capital expenditures.
We anticipate that there will be sufficient operating revenue to fund a small
percentage of the capital expenditures. Teton has funded approximately $3
million of this amount at March 31, 2003. Teton must raise additional capital or
obtain debt financing to fund the balance of the expected capital expenditures.
There can be no guarantee that Teton will be successful in raising these funds.
If we are unable to fund our proportionate share of capital expenditures, MOT
may fund our shortfall, in which event, our interest in production will be
reduced.
Item 7. FINANCIAL STATEMENTS.
TETON PETROLEUM COMPANY
Consolidated Financial Statements
and
Independent Auditors' Report
December 31, 2002
TETON PETROLEUM COMPANY
Table of Contents
Independent Auditors' Report
Consolidated Financial Statements
Consolidated Balance Sheet
Consolidated Statements of Operations and Comprehensive Loss
Consolidated Statements of Changes in Stockholders' (Deficit) Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders
Teton Petroleum Company
Denver, Colorado
We have audited the accompanying consolidated balance sheet of Teton Petroleum
Company as of December 31, 2002, and the related consolidated statements of
operations and comprehensive loss, changes in stockholders' (deficit) equity and
cash flows for the years ended December 31, 2002 and 2001. These consolidated
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the consolidated
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the consolidated financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall consolidated 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 Teton Petroleum
Company as of December 31, 2002, and the results of their operations and their
cash flows for the years ended December 31, 2002 and 2001 in conformity with
accounting principles generally accepted in the United States of America.
/s/Ehrhardt Keefe Steiner & Hottman PC
Ehrhardt Keefe Steiner & Hottman PC
March 28, 2003
Denver, Colorado
TETON PETROLEUM COMPANY
Consolidated Balance Sheet
December 31, 2002
Assets
Current assets
Cash ........................................................ $ 712,013
Proportionate share of accounts receivable .................. 642,525
Proportionate share of accounts receivable (other) .......... 913,583
Stock subscriptions receivable (paid in 2003) ............... 1,939,610
Proportionate share of inventory ............................ 502,989
Prepaid expenses and other assets ........................... 91,446
------------
Total current assets ...................................... 4,802,166
------------
Non-current assets
Oil and gas properties, net (successful efforts) ............ 4,896,308
Fixed assets, net ........................................... 313,921
------------
Total non-current assets .................................. 5,210,229
------------
Total assets ................................................... $ 10,012,395
============
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable and accrued liabilities .................... $ 650,356
Proportionate share of accounts payable and accrued
liabilities ................................................ 1,534,344
Current portion of proportionate share of notes
payable owed to affiliate .................................. 2,441,424
------------
Total current liabilities ................................. 4,626,124
------------
Non-current liabilities
Proportionate share of notes payable advances owed
to affiliate ............................................... 507,001
------------
Total non-current liabilities ............................. 507,001
------------
Total liabilities ......................................... 5,133,125
------------
Commitments and contingencies
Stockholders' equity
Common stock, $.001 par value, 100,000,000 shares
authorized, 75,474,241 and 28,488,557 shares issued
and outstanding at December 31, 2002 and 2001 .............. 75,474
Additional paid-in capital .................................. 26,096,030
Accumulated deficit ......................................... (22,022,734)
Foreign currency translation adjustment ..................... 730,500
------------
Total stockholders' equity ................................ 4,879,270
------------
Total liabilities and stockholders' equity ..................... $ 10,012,395
============
See notes to consolidated financial statements.
TETON PETROLEUM COMPANY
Consolidated Statements of Operations and Comprehensive Loss
For the Years Ended
December 31,
---------------------------
2002 2001
------------ ------------
Sales .......................................... $ 6,923,320 $ 1,625,352
Cost of sales and expenses
Oil and gas production ...................... 2,741,303 1,068,250
Taxes other than income taxes ............... 3,537,990 495,789
General and administrative .................. 5,333,726 1,521,970
Depreciation, depletion and amortization .... 451,930 45,313
------------ ------------
Total cost of sales and expenses .......... 12,064,949 3,131,322
------------ ------------
Loss from operations ........................... (5,141,629) (1,505,970)
------------ ------------
Other income (expense)
Other income ................................ 51,751 9,381
Interest expense ............................ (385,939) (161,019)
Financing charges ........................... (5,498,106) --
------------ ------------
Total other income (expense) ............. (5,832,294) (151,638)
------------ ------------
Net loss ....................................... (10,973,923) (1,657,608)
Other comprehensive loss, net of tax
Effect of exchange rates .................... (140,773) (84,041)
============ ============
Comprehensive loss ............................. $(11,114,696) $ (1,741,649)
=========== ============
Basic and diluted weighted average common shares
outstanding .................................. 37,262,817 26,927,259
============ ============
Basic and diluted loss per common share ........ $ (0.29) $ (0.06)
============ ============
See notes to consolidated financial statements.
TETON PETROLEUM COMPANY
Consolidated Statements of Changes in Stockholders' (Deficit) Equity
For the Years Ended December 31, 2002 and 2001
Foreign
Common Stock Additional Currency Total
-------------------------- Paid-in Translation Accumulated Stockholders'
Shares Amount Capital Adjustment Deficit Equity
----------- ------------ ------------ ------------ ------------ ------------
Balance - December 31, 2000 ................. 24,977,341 $ 24,977 $ 8,469,221 $ 955,314 $ (9,391,203) $ 58,309
Common stock issued for cash ................ 3,466,772 3,467 1,294,806 -- -- 1,298,273
Common stock and warrants issued for services 44,444 44 32,581 -- -- 32,625
Compensation for variable plan warrants ..... -- -- (30,000) -- -- (30,000)
Net loss .................................... -- -- -- -- (1,657,608) (1,657,608)
Foreign currency translation adjustment ..... -- -- -- (84,041) -- (84,041)
----------- ------------ ------------ ------------ ------------ ------------
Balance - December 31, 2001 ................. 28,488,557 28,488 9,766,608 871,273 (11,048,811) (382,442)
Common stock issued for cash ................ 14,684,845 14,685 3,318,775 -- -- 3,333,460
Common stock subscriptions paid in 2003 ..... 8,544,534 8,545 1,931,065 -- -- 1,939,610
Common stock and warrants issued for services 2,654,376 2,654 834,472 -- -- 837,126
Common stock issued for conversion of
convertible debentures ..................... 21,101,929 21,102 5,333,887 -- -- 5,354,989
Warrants issued and in-the-money conversion
feature on convertible debentures .......... -- -- 4,557,845 -- -- 4,557,845
Warrants issued with notes payable .......... -- -- 150,016 -- -- 150,016
Warrants issued in connection with extensions
on notes payable ........................... -- -- 203,362 -- -- 203,362
Net loss .................................... -- -- -- -- (10,973,923) (10,973,923)
Foreign currency translation adjustment ..... -- -- -- (140,773) -- (140,773)
----------- ------------ ------------ ------------ ------------ ------------
Balance - December 31, 2002 ................. 75,474,241 $ 75,474 $ 26,096,030 $ 730,500 $(22,022,734) $ 4,879,270
=========== ============ ============ ============ ============ ============
See notes to consolidated financial statements.
TETON PETROLEUM COMPANY
Consolidated Statements of Cash Flows
For the Years Ended
December 31,
----------------------------
2002 2001
------------ ------------
Cash flows from operating activities
Net loss ............................................ $(10,973,923) $ (1,657,608)
------------ ------------
Adjustments to reconcile net loss to net cash used in
operating activities
Depreciation, depletion, and amortization .......... 451,930 45,313
Stock based compensation for variable plan warrants -- (30,000)
Stock and stock options issued for services and
interest ......................................... -- 32,625
Warrants issued for notes payable extensions ....... 46,582 --
Stock and warrants issued for services ............. 837,126 --
Debentures issued for services ..................... 267,500 --
Amortization of debenture and note payable discounts 5,331,412 --
Changes in assets and liabilities
Accounts receivable .............................. (1,048,608) (331,225)
Prepaid expenses and other assets ................ (57,446) (18,063)
Inventory ........................................ (313,489) (134,456)
Accounts payable and accrued liabilities ......... 290,131 540,854
------------ ------------
5,805,138 105,048
------------ ------------
Net cash used in operating activities ........... (5,168,785) (1,552,560)
------------ ------------
Cash flows from investing activities
Oil and gas properties and equipment expenditures ... (3,222,349) (322,398)
------------ ------------
Net cash used in investing activities ........... (3,222,349) (322,398)
------------ ------------
Cash flows from financing activities
Net proceeds from (payments on) advances owed to
affiliates under notes payable ..................... 2,178,525 (150,100)
Proceeds from issuance of convertible debentures .... 4,143,643 --
Issuance of common stock ............................ -- 1,298,273
Proceeds from notes payable ......................... 300,000 637,000
Payments on notes payable ........................... (894,210) (167,790)
Issuance of common stock ............................ 3,333,460 --
------------ ------------
Net cash provided by financing activities ....... 9,061,418 1,617,383
------------ ------------
Effect of exchange rates .............................. (140,773) (31,806)
------------ ------------
Net increase (decrease) in cash ....................... 529,511 (289,381)
Cash - beginning of year .............................. 182,502 471,883
------------ ------------
Cash - end of year .................................... $ 712,013 $ 182,502
============ ============
Supplemental disclosure of cash flow information
Cash paid for: Interest
----------
2002 $ 120,008
2001 $ 28,123
Supplemental disclosure of non-cash activity:
During 2002, the Company had the following transactions:
In exchange for the extension of principal payments on four notes
payable, the Company modified expiration dates of certain warrants
previously held by the note holders and issued an additional 125,000
such warrants. The fair value of the modification of the warrants
totaled $46,582 and has been recorded as financing costs.
A note payable of $250,000 was converted into a convertible debenture
with 1,000,000 warrants also being issued under the same terms of the
Company's private placement offering of convertible debentures.
19,774,572 warrants were issued with convertible debentures valued at
$811,559 were initially recorded as a discount on the debentures. At
December 31, 2002, the full amount of the discount had been amortized
as financing costs.
In-the-money conversion features on convertible debt valued at
$3,746,285 were recognized as financing costs.
The Company issued 1,724,138 warrants in connection with related party
notes payable of $450,000 and $50,000. The warrants were valued at
$156,781 and recorded as financing costs.
$267,500 of convertible debentures with 1,070,000 warrants valued at
$14,250 for a total amount of $281,750 were issued for consulting
services.
500,000 warrants issued with a note payable valued at $150,016 were
initially recorded as a discount on the note payable. At December 31,
2002 the full discount had been amortized and recorded as financing
costs.
$4,661,143 of debentures and accrued interest of $227,075 were
converted into 21,101,929 shares of stock with $466,771 being paid as
a premium at conversion and recorded as financing costs.
2,654,376 shares of stock were issued to consultants for services
valued at $607,790.
1,600,000 warrants were issued to consultants for services valued at
$215,086.
Approximately $1,142,000 of capital expenditures for oil and gas
properties were included in accounts payable at December 31, 2002.
During the fourth quarter of 2002, the Company received $1,939,610 of
stock subscriptions receivable for 8,544,534 shares of stock. The cash
for these subscriptions were paid during the first quarter of 2003.
During 2001, the Company had the following transactions:
44,444 shares of common stock valued at $16,667 were issued in
exchange for consulting services.
100,000 stock warrants valued at $15,958 were issued in exchange for
consulting services.
The Company assigned a $1,050,000 note payable to Goloil, which was
then repaid from advances received under notes payable owed to
affiliate. The Company recorded the net reduction of debt of $525,000
($1,050,000 note payable less 50% share of the $1,050,000 advances
from affiliate) as a reduction to oil and gas properties.
See notes to consolidated financial statements.
TETON PETROLEUM COMPANY
Notes to Consolidated Financial Statements
Note 1 - Description of Business and Summary of Significant Accounting Policies
Teton Petroleum Company (the Company) is an oil and gas exploration and
production company whose current focus is on the Russian Federation. Since the
Company's operations are solely focused in the Russian Federation it is subject
to certain risks not typically associated with companies in North America,
including, but not limited to, fluctuations in currency exchange rates, the
imposition of exchange control regulations, the possibility of expropriation
decree, undeveloped business practices and laws, and less liquid capital
markets.
The exploration and development of oil and gas reserves involves significant
financial risks. The ability of the Company to meet its obligations and
commitments under the terms and conditions of its licensing agreements and carry
out its planned exploration activities is dependent upon continued financial
support from its stockholders, the ability to develop economically recoverable
reserves, and its ability to obtain necessary financing to complete development
of the reserves.
Should the Company's licenses be revoked as a result of changes in legislation,
title disputes or failure to comply with license agreements, there would be a
material write-down of the oil and gas properties. The accompanying consolidated
financial statements do not reflect any adjustments that may be required due to
these uncertainties.
The United States dollar is the principal currency of the Company's business
and, accordingly, these consolidated financial statements are expressed in
United States dollars.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Teton
Petroleum Company and its wholly owned subsidiary, Goltech Petroleum, LLC
("Goltech"). All intercompany accounts and transactions have been eliminated in
consolidation.
Previously the Company owned a 50% interest in Goltech which had a 70.59%
interest in ZAO Goloil. Accordingly ZAO Goloil was consolidated into Goltech and
we reflected our 50% share of Goltech. As of December 31, 2002, the other 50%
member of Goltech relinquished their ownership interest in exchange for a
35.295% direct ownership interest in ZAO Goloil. The audited financial
statements as of December 31, 2002 and 2001, as is customary in the oil and gas
industry, reflect a pro-rata consolidation of the Company's interest in ZAO
Goloil (a Russian Company) through its wholly owned subsidiary Goltech.
Management believes this to be the most meaningful presentation as the Company's
only significant asset is its investment in Goltech Petroleum, LLC. The Company
is required to provide 50% of the capital expenditure requirements and is
entitled to a 50% operating interest until repayment of its investment occurs.
Under the pro-rata consolidation method the Company includes its pro-rata share
of the assets (50%), liabilities (50%), revenues (50%) and expenses (50%) of the
accounts of Goloil until repayment (payout) of our current and any future loans
to Goloil occurs. The intercompany balances of Goltech and Teton do not fully
eliminate under the pro-rata consolidation method, and the remaining receivable
on Teton's accounts has been included as a component of oil and gas properties,
as this balance will only be repaid through net cash flow generated from oil and
gas properties.
Use of Estimates
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities, disclosures 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.
Oil and Gas Properties
The Company uses the successful efforts method of accounting for oil and gas
producing activities. Costs to acquire mineral interests in oil and gas
properties, to drill and equip exploratory wells that find proved reserves, and
to drill and equip development wells are capitalized. Costs to drill exploratory
wells that do not find proved reserves, geological and geophysical costs, and
costs of carrying and retaining unproved properties are expensed. The Company
also evaluates costs capitalized for exploratory wells, and if proved reserves
cannot be determined within one year from drilling exploration wells, those
costs are written-off and recorded as an expense.
Unproved oil and gas properties that are individually significant are
periodically assessed for impairment of value, and a loss is recognized at the
time of impairment by providing an impairment allowance. Other unproved
properties are amortized based on the Company's experience of successful
drilling and average holding period. Capitalized costs of producing oil and gas
properties, after considering estimated dismantlement and abandonment costs and
estimated salvage values, are depreciated and depleted by the unit-of-production
method. Support equipment and other property and equipment are depreciated over
their estimated useful lives. Currently the Company holds no unproved
properties.
On the sale or retirement of a complete unit of a proved property, the cost and
related accumulated depreciation, depletion, and amortization are eliminated
from the property accounts, and the resulting gain or loss is recognized. On the
retirement or sale of a partial unit of proved property, the cost is charged to
accumulated depreciation, depletion, and amortization with a resulting gain or
loss recognized in income based on the amount of proceeds.
On the sale of an entire interest in an unproved property for cash or cash
equivalent, gain or loss on the sale is recognized, taking into consideration
the amount of any recorded impairment if the property had been assessed
individually. If a partial interest in an unproved property is sold, the amount
received is treated as a reduction of the cost of the interest retained.
All of the Company's oil and gas assets are held in one cost center located in
Siberia, Russia. The Russian Federation (RF) has performed substantial
exploration efforts on properties on which the Company has received successful
tenders for future exploration and development. As a result, those areas
accepted under tender by the RF are known to contain proved reserves and the
Company's efforts are focused on further development of such reserves.
Capitalized oil and gas property costs are depleted and depreciated using the
units of production method based on estimated proved gross oil reserves as
determined by an independent engineer. Significant development projects are
excluded from the depletion calculation prior to assessment of the existence of
proven reserves that are ready for commercial production. The Company did not
have any significant development projects which have been excluded from
depletion at Decemb er 31, 2002.
The net carrying value of the Company's oil and gas properties is limited to an
estimated net recoverable amount. The net recoverable amount is based on
undiscounted future net revenues and is determined by applying factors based on
historical experience and other data such as primary lease terms of properties
and average holding periods. If it is determined that the net recoverable value
is less than the net carrying value of the oil and gas properties, any
impairment is charged to operations.
Inventories
Inventory includes extracted oil physically in the pipeline prior to delivery
for sale and oil held by third parties valued at the cost of development.
Inventory also includes various supplies and spare parts and is valued at cost
using the weighted average method.
Property and Equipment
Property and equipment is stated at cost. Depreciation is provided utilizing the
straight-line method over the estimated useful lives for owned assets, ranging
from 5 to 27 years.
Feasibility Study TDA Grants
Grants that are received for use on oil and gas properties are recorded as an
offset to expenditures incurred under the grants.
One such study was completed in 2001. In the event that the project is
implemented and a substantial economic benefit is reaped, funds previously
advanced by the TDA may be required to be reimbursed. GNG may be required to
reimburse the TDA in the form of a success fee if certain events occur by
December 31, 2003, which include: taking an equity position in the project,
financing development of the license area, or obtaining external financing for
development of the license area.
The Company has also received a $300,000 grant from the TDA for a feasibility
study for field development and pipeline construction. The Company expects
completion of the study in 2003 and has received $255,000 as of December 31,
2002 under the grant. In the event that the project is implemented and a
substantial economic benefit is reaped, funds previously advanced by the TDA may
be required to be reimbursed. The Company may be required to reimburse the TDA
in the form of a success fee if certain events occur based substantially on the
results of the study by December 31, 2005, which include: taking an equity
position in the project, financing development of the license area or obtaining
external financing for development of the license area.
For the years ended December 31, 2002 and 2001 the Company received $0 and
$37,500 under TDA grants, respectively.
Minority Interest
As the share of minority interest losses exceeds the minority's investment, the
Company has recorded 100% of current losses.
Foreign Currency Translation
All assets and liabilities of the Company's subsidiary are translated into U.S.
dollars using the prevailing exchange rates as of the balance sheet date. Income
and expenses are translated using the weighted average exchange rates for the
period. Stockholders' investments are translated at the historical exchange
rates prevailing at the time of such investments. Any gains or losses from
foreign currency translation are included as a separate component of
stockholders' equity. The prevailing exchange rates at December 31, 2002 and
2001 were approximately 1 U.S. dollar to 31.78 and 30.52, Russian rubles,
respectively.
Basic Loss Per Share
The Company applies the provisions of Statement of Financial Accounting Standard
No. 128, "Earnings Per Share" (FAS 128). All dilutive potential common shares
have an antidilutive effect on diluted per share amounts and therefore have been
excluded in determining net loss per share. The Company's basic and diluted loss
per share are equivalent and accordingly only basic loss per share has been
presented.
Fair Value of Financial Instruments
The carrying amounts of financial instruments including cash, accounts
receivable, sundry receivables, accounts payable and accrued liabilities, and
notes payable and convertible debentures approximated fair value as of December
31, 2002 because of the relatively short maturity of these instruments.
The carrying amounts of notes payable and debt issued approximate fair value as
of December 31, 2002 because interest rates on these instruments approximate
market interest rates. The Company has no derivative financial instruments.
The Company is exposed to foreign currency risks to the extent that transactions
and balances are denominated in currencies other than the United States dollar.
This risk could be significant for those transactions and balances denominated
in rubles, as the ruble has experienced significant devaluation in the past.
Reclassifications
Certain amounts in the 2001 consolidated financial statements have been
reclassified to conform to the 2002 presentation.
Recently Issued Accounting Pronouncements
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 requires the fair value of a liability for an asset
retirement obligation to be recognized in the period in which it is incurred if
a reasonable estimate of fair value can be made. The associated asset retirement
costs are capitalized as part of the carrying amount of the long-lived asset.
SFAS No. 143 is effective for years beginning after June 15,2002. The Company
has not yet determined the impact on its consolidated financial statements and
is addressing whether it will be able to make a reasonable estimate of the fair
value of such costs.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets." SFAS 144 requires that those long-lived assets
be measured at the lower of carrying amount or fair value, less cost to sell,
whether reported in continuing operations or in discontinued operations.
Therefore, discontinued operations will no longer be measured at net realizable
value or include amounts for operating losses that have not yet occurred. SFAS
144 is effective for financial statements issued for fiscal years beginning
after December 15, 2001 and, generally, are to be applied prospectively. The
Company believes that the adoption of this statement will have no material
impact on its consolidated financial statements.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities." SFAS No. 146 addresses accounting and
reporting for costs associated with exit or disposal activities and nullifies
Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain
Employee Termination Benefits and Other Costs to Exit an Activity (Including
Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires that a
liability for a cost associated with an exit or disposal activity be recognized
and measured initially at fair value when the liability is incurred. SFAS No.
146 is effective for exit or disposal activities that are initiated after
December 31, 2002, with early application encouraged. The Company believes the
adoption of this statement will have no material impact on its consolidated
financial statements.
In November 2002, the FASB published interpretation No, 45 "Guarantor's
Accounting and Disclosure requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others". The Interpretation expands on the
accounting guidance of Statements No. 5, 57, and 107 and incorporates without
change the provisions of FASB Interpretation No. 34, which is being superseded.
The Interpretation elaborates on the existing disclosure requirements for most
guarantees, including loan guarantees such as standby letters of credit. It also
clarifies that at the time a company issues a guarantee, that company must
recognize an initial liability for the fair value, or market value, of the
obligations it assumes under that guarantee and must disclose that information
in its interim and annual financial statements. The initial recognition and
initial measurement provisions apply on a prospective basis to guarantees issued
or modified after December 31, 2002, regardless of the guarantor's fiscal
year-end. The disclosure requirements in the Interpretation are effective for
financial statements of interim or annual periods ending after December 15,
2002. The Company believes the adoption of this statement will have no material
impact on its consolidated financial statements.
In December 2002, the FASB issued SFAS No. 148 "Accounting for Stock-Based
Compensation- Transition and Disclosure." This statement amends SFAS No. 123,
"Accounting for Stock-Based Compensation" to provide alternative methods of
transition for an entity that voluntarily changes to the fair value method of
accounting for stock-based compensation. In addition, SFAS 148 amends the
disclosure provision of SFAS 123 to require more prominent disclosure about the
effects of an entity's accounting policy decisions with respect to stock-based
employee compensation on reported net income. The effective date for this
Statement is for fiscal years ended after December 15, 2002. The Company
believes the adoption of this statement will have no material impact on its
consolidated financial statements.
Note 2 - Investments in Goltech Petroleum, LLC
Effective in August 2000, the Company entered into a transaction agreement
selling a 50% equity interest in Goltech in exchange for $1,000,000 cash and a
$5.6 million investment in the license area for drilling additional wells on the
license area, completion of a pipeline and the construction of a processing
facility (the oilfield development program). The $1,000,000 received was also
invested in the license area to complete the oilfield development program. The
party to the agreement obtained the right to name 50% of the board of managers
and became the general manager of Goltech. No gain or loss was recognized on the
transaction as the proceeds were immediately reinvested into the field
development and pipeline completion project. ZAO Goloil was also required to
make a production payment to compensate the other party for its investment in
the license area. The production payment requires ZAO Goloil to deliver 50% of
the production from existing and future wells through July 2007. The other party
is obligated under an agreement to only sell their share of the production in
the Russian domestic market. Effective December 31, 2002, the other party
withdrew as a member of Goltech and in exchange for relinquishment of 50% of its
membership interests in Goltech, it received 35.295% of the ZAO Goloil shares
and the return of its $1,000,000 initial contribution. ZAO Goloil is still
obligated under the production payment.
The other membership holder (affiliate) to Goltech Petroleum, LLC (Goltech) had
invested approximately $ 7,000,000 under the oilfield development agreement
outside of Goltech and Goloil as of December 31, 2002. These costs are reflected
in the accounts of another entity controlled by the affiliate and are not
reflected anywhere in the financial statements of the Company. These
expenditures were used to drill and complete four additional wells and complete
a pipeline on the Company's license area that provides the ability to transport
oil directly through this pipeline year-round to other larger pipelines for
ultimate sale. The Company has compensated the affiliate in the form of a
production payment of approximately 154,000 tons of oil through December 31,
2002. The Company also has the obligation to compensate the affiliate for a
minimum of 560,000 tons averaged of oil over a seven-year period for its
investments under the oilfield development agreement.
Additionally, the affiliate has net direct loans to Goloil of approximately
$6,000,000, which have been used to help fund capital expenditures for
completion of a processing facility and to help fund other related expenses. The
Company has reflected a 50% of these loans in its financial statements under the
pro-rata consolidation method (Note 6).
Note 3 - Property and Equipment
Property and equipment consist of the following at December 31, 2002:
Building ..................... $ 31,627
Vehicles ..................... 154,015
Computers and equipment ...... 57,572
Well and production equipment 83,644
Furniture and fixtures ....... 33,617
---------
360,475
Less: Accumulated depreciation (46,554)
---------
$ 313,921
=========
Note 4 - Oil and Gas Properties
Goloil License
The Company holds a license for the Eguryak license area for exploration and
production of oil and gas through its investment in Goloil (which is held
through its 100% owned subsidiary, Goltech). This license grants Goloil the
exclusive right to explore and develop an area in Siberia covering 187 square
kilometers and includes the Eguriakhskoe, South Eguriakhskoe and Golevoye oil
fields situated in the Nizhnevartovsk Region. The license expires on May 21,
2022, subject to additional extensions as approved by applicable bodies of the
Russian Federation. The license may also be canceled by the Company with a
90-day written notice.
The license requires Goloil to drill a minimum of five wells over four years,
conduct an additional seismic survey aggregating 30 square kilometers and
evaluate geological data from an area covering 187 square kilometers. Goloil was
also required to conduct production tests on six wells between 1997 and 2000. In
addition to performing its duties under the license, Goloil must give preference
to Russian environmental and archeological laws. Currently, the Company has
fulfilled its requirements under the license. Management is continuing to pursue
completion of future required performance criteria and believes that there will
be no adverse effects on the Company's license for failure to comply with the
license rerquirements.
The license requires Goloil to pay all taxes including mining tax, property tax
and certain ecological taxes All geological information obtained at Goloil's
expense will be the property of Goloil, while all geological information
obtained at the expense of the Russian government may be used by Goloil. Oil and
gas produced from the licensed property, subject to certain royalty payments,
will be the property of Goloil.
Capital expenditures for continued development of the license area are estimated
at approximately $20 million net to Teton, with 6.5 million budgeted for 2003 as
Teton's net share. Teton must raise additional equity or debt financing to fund
their portion of these capital expenditures. There can be no assurance that
Teton will be able to raise such financing on terms favorable to the Company or
at all.
DCD Dagestan
In the second quarter of 2001, the Company divested itself of its subsidiary
Teton Oil, Inc., which holds the remaining DCD Dagestan Licenses. The shares of
Teton Oil, Inc. were distributed to two of the Company's stockholders and the
stockholders also assumed any related obligations associated with the licenses.
No gain or loss was recorded on the distribution as the net assets of Teton Oil,
Inc. were written down to zero in 1998.
Note 5 - Notes Payable
During 2002, the March 1, 2002 principal payments on two notes payable totaling
$250,000 to stockholders were extended to April 15, 2002. In exchange for this
extension, the holders were issued 125,000 stock purchase warrants, with an
exercise price of $0.50 that expire February 2004, which have been valued at $
14,469 using the Black Scholes option pricing model with assumptions of
volatility of 100%, risk free rate of 5.5 and no dividend yield. These
extensions were recorded in the first quarter of 2002 as financing costs. These
notes were fully paid off in 2002.
The Company issued 1,724,138 warrants in connection with related party notes
payable of $450,000 and $50,000. The warrants were valued at $156,781 and
recorded as financing costs. Additionally, in the first quarter of 2002, the due
dates of the two notes payable totaling $500,000 were extended by the holders to
April 15, 2002. As consideration for this extension the Company agreed to modify
the expiration dates of certain warrants previously held by the note holders
from October 31, 2002 to January 31, 2003. These extensions were valued based
upon the incremental fair value of the warrants on the date of modification
which totaled approximately $32,000. The values were calculated using the Black
Scholes option-pricing model under the assumptions described in the previous
paragraph, and were recorded in the first quarter of 2002, the quarter the
modifications occurred.
During 2002, the Company paid $200,000 of a $450,000 note payable outstanding at
December 31, 2001. The remaining $250,000 was converted into a convertible
debenture with 1,000,000 warrants also being issued in connection with the
Company's private placement offering of convertible debentures.
The Company also paid off a $50,000 note payable to a stockholder and the
$94,210 note payable to an officer during 2002, which were outstanding at
December 31, 2001.
During 2002, the Company received proceeds of $300,000 on a note payable from a
stockholder. In connection with the note, 500,000 warrants valued at $150,016
were issued and recorded as financing charges. The Company paid off this note in
November 2002. The Company has recorded the value of these warrants using the
Black Scholes option-pricing model using the following assumptions: volatility
of 138%, a risk-free rate of 4.5%, zero dividend payments, and a life of 2
years.
Total expense recorded associated with the above warrant issuances and
modifcations totaled $353, 379 and have been recorded as financing costs during
the year ended December 31, 2002.
Note 6 - Proportionate Share of Liabilities
The proportionate share of accounts payable and accrued liabilities of
$1,534,344 at December 31, 2002 are obligations of Goloil and not Teton
Petroleum nor have they been guaranteed by Teton Petroleum.
The following notes reflect the Company's 50% pro-rata share of notes payable
advances made of Goloil owed to an affiliate. These advances are also
obligations of Goloil at December 31, 2002 and not Teton Petroleum nor have they
been guaranteed by Teton Petroleum.
Pro-rata share of Goloil notes payable owed to an affiliate. The
proceeds were used to pay certain operating expenses and capital
expenditures of Goloil. These notes provide for interest rates of
8%, with quarterly interest payments, maturing through February
2004. These notes are secured by substantially all Goloil assets.
The notes payable will be repaid from cash flow from ZAO Goloil as
available, or entended to future periods............................. $ 2,948,425
-------------
Less: current portion ............................................. (2,441,424)
-------------
$ 507,001
=============
Note 7 - Stockholders' Equity
On January 3, 2001, the Stockholders of the Company approved an increase in the
number of authorized shares of common stock from 50,000,000 to 100,000,000.
On March 19, 2003, the stockholders, increased the authorized common shares from
100,000,000 to 250,000,000 and authorized 25,000,000 of preferred stock
available for future issuance.
Common Shares Issued for Service
During the years ended December 31, 2002 and 2001, 2,654,376 and 44,444 common
shares were issued for consulting services which have been valued at $605,136
and $32,625, respectively.
In connection with a consulting agreement, the Company agreed to issue 88,888
shares of stock during the second quarter of 2002 for services provided in 2001
valued at $23,200. The Company has accrued a liability for this amount at
December 31, 2002.
Convertible Debentures
During 2002, the Company received proceeds of $4,163,143 from the private
placement of convertible debentures. The debentures had a term of three years
from April 1, 2002 and provided for interest at 10% per annum payable annually.
The debentures provided that the holder may convert the debenture and accrued
interest into shares of common stock (a $.25 conversion rate).
The debentures also included warrants to purchase common stock and have an
exercise price of $.50 and a term of two years. Each debenture holder received
one warrant for each $.25 of investment made in debentures.
On September 1, 2002, the Company redeemed all debentures outstanding for shares
of its common stock. The debentures were redeemed at 110% of their face value by
issuing one share of common stock for each $.25 of redemption value, which also
incorporates any accrued interest through September 1, 2002. Financing charges
were recorded for the difference between the cumulative 10% contractual interest
accrued through September 1, 2002 and the 10% premium paid upon redemption,
which totaled $466,771.
As a result of the warrants issued with the debentures and in-the-money
conversion features present at issuance, non-cash financing charges of
$4,714,625 were expensed. While the stock to which the conversion rights and
warrants apply is restricted stock, the valuation with respect to this stock in
calculating the discount was "as if" the stock was immediately salable. The
effect of this is to make the amount of discount and its related amortization
higher than it would otherwise have been. Management believes these costs are
non-recurring and will manage future capital raising programs to minimize or
eliminate these costs.
2002 Private Placement
During 2002, the Company issued 14,684,845 shares of common stock under private
placement offerings receiving proceeds of $3,333,460. In connection with the
private placement offerings, the Company also issued a warrant for each $.25
stock investment. The warrants have a term of two years and an exercise price of
$.50.
At December 31, 2002 the Company had $1,939,610 of subscriptions receivable for
8,544,534 shares of common stock for which the cash was paid in 2003 and has
been included in common stock in the accompanying financial statements.
Common Share Purchase Warrants
During 2002, the Company issued 1,600,000 warrants to consultants for services
valued at $215,086. The Company also issued 7,401,480 to employees and directors
for services performed.
During 2001, the Company issued 3,466,772 warrants in connection with private
placement offerings with an exercise price of $0.41 and expire between May 15,
2006 and August 15, 2006. Also, the Company issued 100,000 warrants to a third
party for consulting services. The warrants have an exercise price of $0.41 and
expire September 9, 2006. The warrants were valued at $15,958 using the Black
Scholes option pricing model with assumption of volatility of 100%, risk free
rate of 5.5 and no dividend yield.
The following table presents the activity for warrants outstanding:
Weighted
Average
Exercise
Shares Price
------------- -------
Outstanding - December 31, 2000 ......................... 3,237,613 $ 0.61
Granted ........................................... 3,566,772 0.22
Forfeited/canceled ................................ (275,213) 0.17
------------- -------
Outstanding - December 31, 2001 ......................... 6,529,172 0.44
Granted ........................................... 48,824,189 0.46
Forfeited/canceled ................................ (300,000) 0.40
------------- -------
Outstanding - December 31, 2002 ......................... 55,053,361 $ 0.46
============= =======
The following table presents the composition of warrants outstanding and
exercisable:
Shares Outstanding
--------------------------
Range of Exercise Prices Number Price* Life*
----------------------------------------- ------------ ------------ ---------
$0.227 - 0.50 54,553,361 $ 0.45 1.67
$0.75 - 1.00 500,000 0.01 0.02
------------ ------------ ---------
Total - December 31, 2002 55,053,361 $ 0.46 1.69
============ ============ =========
* Price and Life reflect the weighted average exercise price and weighted
average remaining contractual life, respectively.
The Company has adopted the disclosure-only provisions of Statement of Financial
Accounting Standards No. 123, "Accounting for Stock-Based Compensation."
Accordingly, no compensation cost has been recognized for the stock option
plans. Had compensation cost for the Company's option plan been determined based
on the fair value at the grant date for awards consistent with the provisions of
SFAS No. 123, the Corporation's net loss and basic loss per common share would
have been changed to the pro forma amounts indicated below:
For the Years Ended
December 31,
--------------------------
2002 2001
------------ ------------
Net loss - as reported ....................... $(10,973,923) $ (1,657,608)
Net loss - pro forma ......................... (11,945,964) (1,657,608)
Basic loss per common share - as reported .... (0.29) (0.06)
Basic loss per common share - pro forma ...... (0.32) (0.06)
The fair value of each warrant grant is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted-average
assumptions used:
For the Years Ended
December 31,
--------------------------
2002 2001
------------ ------------
Approximate risk free rate ................... 4.50% -%
Average expected life ........................ 2 years - years
Dividend yield ............................... -% -%
Volatility ................................... 87.20% -%
Estimated fair value of total options granted. $972,041 $ -
Stock Options
The Company maintains a stock option plan for the issuance of options to
directors, officers, employees and consultants to the Company. The Company has
reserved 1,950,000 shares for issuance under the plan.
The following table presents the activity for stock option's outstanding:
Weighted
Average
Exercise
Shares Price
------------ ------------
Outstanding - December 31, 2000 450,000 $ 0.40
Forfeited/canceled (450,000) (0.40)
------------ ------------
Outstanding - December 31, 2001 and 2002 - -
============ ============
Note 8 - Income and Other Taxes
The Company has incurred losses since inception and, as a result of uncertainty
surrounding the use of those net operating loss carryforwards, no provision for
income taxes has been recorded.
The Company has net operating loss carryforwards for U.S. tax purposes of
approximately $8,950,000, which expire between 2012 and 2022, if unused, and
have been fully reserved by a valuation allowance.
Taxes payable are tax liabilities of its Russian subsidiary, Goloil (held
through its wholly owned subsidiary Goltech). Tax payments made by Goloil to the
Russian government include profits tax, value-added tax ("VAT"), payroll taxes
and property taxes.
The Company had no income tax liabilities or expense for the years ended
December 31, 2002 or 2001. ZAO Goloil has net operating loss carryforwards which
are available to offset future taxable income which will expire in 2012. The
foreign income tax carryforwards for Russian tax purposes are limited to a
maximum of 30% of taxable income in any year.
Management believes that it will not be subject to future repatriation tax if
profits from the project are invested in other projects within Russia.
Note 9 - Commitments and Contingencies
Contingencies
There is currently a high level of political and economic instability and
uncertainty in the Russian Federation. As a result of the financial crisis in
August 1998, all financial markets were subject to significant downward
adjustments. The national currency was severely devalued during the crisis and
continued to deteriorate through the end of 1998. The Russian banking system
suffered significant liquidity problems and several large Russian banking
institutions stopped operations and/or experienced significant losses. The
Russian Government defaulted on, and announced a restructuring of, its internal
debt due to a lack of funds and is likely to seek forgiveness and/or
restructuring of its external debt.
The taxation system in Russia is evolving as the central government transforms
itself from a command to a market-oriented economy. There were many new Russian
Federation and Republic taxes and royalty laws and related regulations
introduced over the last few years. Many of these were not clearly written and
their application is subject to the interpretation of the local tax inspectors,
Central Bank officials and the Ministry of Finance. Instances of inconsistent
interpretation between local, regional and federal tax authorities and between
the Central Bank and Ministry of Finance are not unusual. The current regime of
penalties and interest related to reported and discovered violations of Russian
laws, decrees and related regulations are severe. Penalties include confiscation
of the amounts at issue (for tax law violations), as well as fines of up to 40%
of the unpaid taxes. Interest is assessable at rates of up to 0.1% per day. As a
result, penalties and interest can result in amounts that are multiples of any
unreported taxes.
The Company's policy is to accrue contingencies in the accounting period in
which a loss is deemed probable and the amount is reasonably determinable. In
this regard, because of the uncertainties associated with the Russian tax and
legal systems, the ultimate taxes as well as penalties and interest, if any,
assessed may be in excess of the amounts paid to date as of December 31, 2002.
Management believes based upon its best estimates, that the Company has paid or
accrued all taxes that are applicable for the current and prior years, and
compiled with all essential provisions of laws and regulations of the Russian
Federation.
The Company may be subject to loss contingencies pursuant to Russian national
and regional environmental claims that may arise for the past operations of the
related fields, which it operates. As Russian laws and regulations evolve
concerning environmental assessments and cleanups, the Company may incur future
costs, the amount of which is currently indeterminable due to such factors as
the current state of the Russian regulatory process, the ultimate determination
of responsible parties associated with these costs and the Russian government's
assessment of respective parties' ability to pay for those costs related to
environmental reclamation.
The Company's operations and financial position will continue to be affected by
Russian political developments including the application of existing and future
legislation, regulations and claims pertaining to production, imports, exports,
oil and gas regulations and tax regulations. The likelihood of such occurrences
and their effect on the Company could have a significant impact on the Company's
current activity and its overall ability to continue operations. Management does
not believe that these contingencies, as related to its operations, are any more
significant than those of similar enterprises in Russia.
Commitments
The Company has employment agreements with its president and secretary through
May 31, 2005 and December 1, 2002, respectively, which provide for certain
salaries as specified and other related matters and may be terminated by the
written consent of the employees prior to expiration.
Note 10 - Supplemental Oil and Gas Disclosures
The following is a summary of costs incurred in oil and gas producing
activities:
Included below is the Company's investment and activity in oil and gas producing
activities which includes a proportionate share of ZAO Goloil's oil and gas
properties, revenues, and costs.
For the Years Ended
December 31,
--------------------------
2002 2001
------------ ------------
Property acquisition costs ..................... $ - $ -
Development costs .............................. 4,150,742 322,398
------------ ------------
Total ................................... $4,150,742 $ 322,398
============ ============
The following reflects the Company's capitalized costs associated with oil and
gas producing activities:
For the Years Ended
December 31,
--------------------------
2002 2001
------------ ------------
Property acquisition costs ..................... $ 595,558 $ 595,558
Development costs (1) .......................... 4,830,421 679,679
------------ ------------
5,425,979 1,275,237
Accumulated depreciation, depletion,
amortization and valuation allowances ......... (529,671) (106,137)
------------ ------------
Net capitalized costs .......................... $4,896,308 $ 1,169,100
============ ============
(1) 2001 development costs reflect a net reduction of $525,000 to oil and gas
properties for the repayment of debt by an affiliate which has been treated
as a recovery on investment in the property.
Results of Operations from Oil and Gas Producing Activities
Results of operations from oil and gas producing activities (excluding general
and administrative expense, and interest expense) are presented as follows:
For the Years Ended
December 31,
--------------------------
2002 2001
------------ ------------
Oil and gas sales .............................. $6,923,320 $ 1,625,352
Production costs ............................... (2,741,303) (1,068,250)
Taxes other than income taxes .................. (3,537,990) (495,789)
Depletion, depreciation and amortization ....... (451,930) (45,313)
---------------------------
Results of operations from oil and
gas producing activities ...................... $ 192,097 $ 16,000
===========================
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 existing economic and operating conditions. Proved development
oil and gas reserves are those reserves expected to be recovered through
existing wells with existing equipment and operating methods. The reserve data
is based on studies prepared by an independent engineer. All proved reserves of
oil and gas are located in Russia.
The following table presents estimates of the Company's net proved oil and gas
reserves:
For the Years Ended
December 31,
--------------------------
2002 2001 (1)(2)
------------ ------------
Proved reserves (bbls), beginning of period .... 40,174,000 8,500,000
Production ..................................... (950,000) (95,000)
Extention of resevoir .......................... 2,000,000 8,800,000
Revisions of previous estimates ................ (27,960,000) 22,969,000
------------ ------------
Proved reserves (bbls), end of period .......... 13,264,000 40,174,000
============ ============
Proved developed reserves (bbls, beginning
of period ..................................... 5,493,000 1,300,000
============ ============
Proved developed reserves (bbls), end
of period ..................................... 4,567,000 5,493,000
============ ============
(1) Includes approximately a 30% minority interest share of the reserves in
Goloil.
(2) Proved developed reserves have been reduced by 650,000 bbls out of the
total 1,950,000 bbls of Teton's share of the production payment. The
remaining production payment quantity of 1,300,000 barrels of Teton's share
assumes payment from proved undeveloped properties to be developed in the
future.
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
SFAS 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 prices and costs to the estimated quantities of oil and gas
to be produced. Estimated future income taxes are computed using current
statutory income tax rates for those countries where production occurs. 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 for actual revenues to be derived from those
reserves nor their present worth. 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.
The following summary sets forth the Company's future net cash flows relating to
proved oil and gas reserves based on the standardized measure prescribed in
Statement of Financial Accounting Standards No. 69.
For the Years Ended
December 31,
----------------------------
2002 2001 (1)
------------ -------------
Future cash inflows ............................ $230,581,000 $483,405,000
Future production costs ........................ (151,167,000) (272,150,000)
Future development costs ....................... (18,556,000) (45,600,000)
Future income tax expense ...................... (16,365,000) (57,394,000)
------------ -------------
Future net cash flows (undiscounted) ........... 44,493,000 108,261,000
Annual discount of 10% for estimated
timing of cash flows .......................... (19,069,000) (67,899,000)
------------ -------------
Standardized measure of future net
discounted cash flows ......................... $ 25,424,000 $ 40,362,000
============ =============
(1) Includes approximately a 30% minority interest share of the reserves in
Goloil.
Changes in Standardized Measure (Unaudited)
The following are the principal sources of change in the standardized measure of
discounted future net cash flows:
For the Years Ended
December 31,
----------------------------
2002 2001 (1)
------------ -------------
Standardized measure, beginning of period,
December 31, 2001 and 2000 $40,362,000 $ 41,600,000
Net changes in prices and production costs 189,975,000 (33,421,000)
Future development costs 22,344,000 (109,233,000)
Revisions of previous quantity estimates (274,605,000) 102,592,000
Extension of reservoir 19,867,000 39,707,000
Sale of reserves in place - -
Accretion of discount 4,036,000 4,160,000
Changes in income taxes, net 23,445,000 (5,043,000)
------------ -------------
Standardized measure, end of period,
2002, 2002 and 2001 $25,424,000 $ 40,362,000
============ ==============
(1) Includes approximately a 30% minority interest share of the reserves in
Goloil.
Item 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
Item 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(A) OF THE EXCHANGE ACT.
Officers, Directors, and Significant Employees
Directors, executive officers, and significant employees of Teton, their
respective ages and positions with Teton are as follows:
Name Age Position
---- --- --------
H. Howard Cooper 46 Director and President
Igor Effimoff 57 Chief Operating Officer
Thomas F. Conroy 64 Chief Financial Officer and
Secretary and Director
Karl F. Arleth 54 Director
James J. Woodcock 65 Director
Ilia Gurevich 39 Controller
H. HOWARD COOPER, has been our president and chairman of the board of
directors since 1996. Mr. Cooper founded American Tyumen in November 1996. He
served as a director and president of American Tyumen until the merger with EQ.
Since the merger, he has held these same positions with Teton. From 1992 to 1994
Mr. Cooper served with AIG, an insurance group. In 1994, he was a principal with
Central Asian Petroleum, an oil and gas company with its primary operations in
Kazakhstan, located in Denver, Colorado. Mr. Cooper has a bachelor's degree from
the University of Colorado in business and a master's degree from Columbia
University, NYC in international affairs.
IGOR EFFIMOFF. Mr. Effimoff was most recently President of Pennzoil Caspian
Corporation, managing the company's interests in the Caspian Region. This
included the Azerbaijan International Oil Consortium (AIOC), formed to develop
the 4.5 BBO Azeri-Chirag-Guneshli (ACG) Fields. He started his career in 1972 as
a geologist with Shell and since 1981 has worked with several US domestic and
international oil and gas companies in a senior management capacity
THOMAS F. CONROY, has been our chief financial officer since March 2002,
secretary since April 2002, and director since 2002. Mr. Conroy is a Certified
Public Accountant with an MBA from the University of Chicago. Since 2002, Mr.
Conroy has been a principal member of Mann-Conroy-Eisenberg & Assoc. LLC, a life
insurance and reinsurance consulting firm. Since 2001, Mr. Conroy has been a
managing principal of Strategic Reinsurance Consultants International LLC, a
life reinsurance consulting and brokerage firm. Ending in 2001, Mr. Conroy,
spent 27 years with ING and its predecessor organizations, serving in various
financial positions and leading two of its strategic business units as
President. As President of ING Reinsurance, he established their international
presence, setting up facilities in The Netherlands, Bermuda, Ireland and Japan.
He also served as an Officer and Board Member of Security Life of Denver
Insurance Company and its subsidiaries.
KARL F. ARLETH, has been a director since 2002. Mr. Arleth is the Chief
Operating Officer and a Board member of Sefton Resources, Inc. Ending in 1999,
Mr. Arleth spent 21 years with Amoco and BP-Amoco. In 1998 he chaired the Board
of the Azerbaijan International Operating Company (AIOC) for BP-Amoco in Baku,
Azerbaijan. Concurrently in 1997-98, he was also President of Amoco Caspian Sea
Petroleum Ltd. in Azerbaijan and Director of Strategic Planning for Amoco
Corporations Worldwide Exploration and Production Sector in Chicago. From 1992
-- 1996 Mr. Arleth was President of Amoco Poland Ltd. in Warsaw, Poland.
JAMES J. WOODCOCK has been a director since 2002. Since 1981, Mr. Woodcock
has been the owner and CEO of Hy-Bon Engineering Company, based in Midland,
Texas. Hy-Bon is an engineering firm and manufacturer of vapor recovery, gas
boosters, and casing pressure reduction systems for the oil industry. Since
1996, Mr. Woodcock has been a board member of Renovar Energy, a private firm
located in Midland Texas. From 1997 to 2002, Mr. Woodcock was the chairman of
Transrepublic Resources, a private firm located in Midland Texas.
ILIA GUREVICH. Mr. Gurevich attended both University of Saratov and
University Colorado graduating with Masters in Science and Economy of the
Machine Construction Industry and a Masters of Science in Finance respectively.
His US-Russia business relations date back to his work at Technoforce Saratov
where he was responsible for database of oil fields, budgeting, and financial
support for the projects. Most recently, Mr. Gurevich performed security
analysis for mid and large-cap publicly traded companies until he became full
time Controller of Teton.
All directors serve as directors for a term of one year or until his successor
is elected and qualified. All officers hold office until the first meeting of
the board of directors after the annual meeting of stockholders next following
his election or until his successor is elected and qualified. A director or
officer may also resign at any time.
COMMITTEES OF THE BOARD OF DIRECTORS
The Board of Directors has a Compensation Committee and an Audit Committee.
The Compensation Committee and Audit Committee consists of two directors, Karl
Arleth and James J. Woodcock. Messrs. Arleth and Woodcock are independent
directors who are not a salaried officers of the Company. Messrs. Arleth and
Woodcock are independent directors based on Rule 4200(a)(15) of the NASD's
listing standards.
The purpose of the Compensation Committee is to review the Company's
compensation of its executives, to make determinations relative thereto and to
submit recommendations to the Board of Directors with respect thereto in order
to ensure that such officers and directors receive adequate and fair
compensation. The Compensation Committee did not meet during the last fiscal
year.
During the fiscal year ending 2003, the Audit Committee will be responsible
for the general oversight of audit, legal compliance and potential conflict of
interest matters, including (a) recommending the engagement and termination of
the independent public accountants to audit the financial statements of the
Company, (b) overseeing the scope of the external audit services, (c) reviewing
adjustments recommended by the independent public accountant and addressing
disagreements between the independent public accountants and management, (d)
reviewing the adequacy of internal controls and management's handling of
identified material inadequacies and reportable conditions in the internal
controls over financial reporting and compliance with laws and regulations, and
(e) supervising the internal audit function, which may include approving the
selection, compensation and termination of internal auditors.
The Audit Committee did not meet during the last fiscal year because it was
approved late in the 2002 year by the Board of Directors and was not formally in
place to perform its functions. However, the responsibilities of the Audit
Committee during 2002 were conducted by the board of directors. Effective as of
February 17, 2003, the Board of Directors adopted a charter for the Audit
Committee detailing its duties and powers. A copy of the Audit Committee charter
is included as Exhibit A to this Form 10KSB.
For the fiscal year ended 2002, the Board of Directors conducted
discussions with management and the independent auditor regarding the
acceptability and the quality of the accounting principles used in the reports
in accordance with Statements on Accounting Standards (SAS) No. 61,. These
discussions included the clarity of the disclosures made therein, the underlying
estimates and assumptions used in the financial reporting and the reasonableness
of the significant judgments and management decisions made in developing the
financial statements. In addition, the board of directors discussed with the
independent auditor the matters in the written disclosures required by
Independence Standards Board Standard No. 1.
For the fiscal year ended 2002, the Board of Directors have also discussed
with management and its independent auditors issues related to the overall scope
and objectives of the audits conducted, the internal controls used by the
Company, and the selection of the Company's independent auditor. Additional
meetings were held with the independent auditor, with financial management
present, to discuss the specific results of audit investigations and
examinations and the auditor's judgments regarding any and all of the above
issues.
Pursuant to the reviews and discussions described above, the Board of
Directors recommended that the audited financial statements be included in the
Annual Report on Form 10-KSB for the fiscal year ended December 31, 2001 and
2000 for filing with the Securities and Exchange Commission.
Code of Ethics
The Company has adopted its Code of Ethics and Business Conduct for
Officers, Directors and Employees that applies to all of the officers, directors
and employees of the Company.
Compliance with Section 16(b) of the Exchange Act
Based solely on our review of Forms 3, 4, and 5, and amendments thereto
which have been furnished to us, we believe that during the year ended December
31, 2002 all of our officers, directors, and beneficial owners of more than 10%
of any class of equity securities, timely filed, reports required by Section
16(a) of the Exchange Act of 1934, as amended.
Item 10. EXECUTIVE COMPENSATION.
The following table sets forth information concerning the compensation received
by Mr. Howard Cooper, the President of Teton, who serves as its chief executive
officer for the last three fiscal years:
Summary Compensation Table
Other
Annual
Name & Compen- Restricted Options LTIP
Principal Salary Bonus sation Stock SARs Payouts All Other
Position Year ($) ($) ($) awards (#)(1) ($) Compensation
------------------------------------------------------------------------------------------
H. Howard 2002 160,000 50,000 0 0 4,500,000 0 0
Cooper, 2001 210,000 0 0 0 0 0 0
President 2000 17,000 0 0 0 1,000,000 0 0
1. In consideration of services rendered, Mr. Cooper received 4,500,000
warrants to purchase shares of our common stock at an exercise price of
$.27 which was the market price of our common stock on the date of the
grant.
Stock Options.
During the year ended December 31, 2002, Mr. Cooper did not exercise any of his
stock options. Based on the average of the high and low bid for our common stock
on December 31, 2002, as of December 31, 2002, Mr. Cooper did not hold any
in-the-money stock options.
Employee Pension, Profit Sharing or Other Retirement Plans.
The Company does not have a defined benefit, pension plan, profit sharing, or
other retirement plan.
Compensation of Directors.
The Company does not pay a director's fee to its directors. In the Company's
sole discretion, the Company may issue stock options or warrants to its
directors.
Employment Contracts.
Teton and Mr. Cooper entered into a new employment agreement, effective May 1,
2002. The employment agreement is for a three year term. Mr. Cooper's initial
salary under the agreement is $13,333 per month. In the board's discretion, he
may receive additional bonus compensation. Mr. Cooper's employment is terminated
immediately upon his death or permanent disability. Teton may also terminate Mr.
Cooper's employment immediately for cause, as defined in the agreement. Mr.
Cooper may terminate his employment immediately for good reason, as defined in
the agreement. Additionally, either Teton or Mr. Cooper may terminate Mr.
Cooper's employment upon 60 days prior written notice to the other. Upon
termination of Mr. Cooper's employment without cause by Teton or for good reason
by Mr. Cooper, Mr. Cooper is entitled to severance pay. The severance pay is
equal to Mr. Cooper's salary for the preceding 24 months. Such severance may be
paid in monthly installments over 24 months from the date of termination. Teton
may discontinue the severance payments if Mr. Cooper violates the
confidentiality, noncompetition, or nonsolicitation provisions of his employment
agreement. After the third year, the agreement is automatically renewed from
year to year, unless it is terminated as provided above.
Mr. Cooper's new agreement replaced the employment agreement dated effective
December 1, 2000 (the "2000 Employment Agreement"). The 2000 Employment
Agreement provided for an initial term of two years and an initial salary of
$17,500 per month. The 2000 Employment Agreement also provided that upon the
termination of Mr. Cooper without his consent, except for terminations related
to a criminal conviction, death, disability, incapacity, bankruptcy, insolvency,
gross negligence, gross dereliction of duty, or gross misconduct, that Mr.
Cooper was entitled to a lump sum payment equal to three months salary, based on
the salary being paid to Mr. Cooper at the date of termination.
Item 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The following tables sets forth, as of March 25, 2003, the number of and
percent of our common stock beneficially owned by (a) all directors and
nominees, naming them, (b) our executive officers, (c) our directors and
executive officers as a group, without naming them, and (d) persons or groups
known by us to own beneficially 5% or more of our common stock:
Name and Address Amount and Nature of Percent
of Beneficial Owner Beneficial Ownership of Class
------------------- -------------------- --------
H. Howard Cooper 7,360,535 (1) 10.6%
2135 Burgess Creek Road
Suite #7
P.O. Box 774327
Steamboat Springs, CO 80477
Thomas F. Conroy 356,110 (2) *
3825 S. Colorado Blvd.
Denver, CO 80110
James J. Woodcock 2,578,224 (3) 3.7%
2404 Commerce Drive
Midland, TX 79702
Karl F. Arleth 1,375,939 (4) 2.0%
P.O. Box 23507
0467 Lariat Loop
Silverthorne, CO 80498
All executive officers and 11,670,808 16.8%
directors as a group (4 persons)
----------
* Less than one percent.
(1) Includes 5,586,250 warrants.
(2) Includes 169,443warrants.
(3) Includes 1,366,667 warrants
(4) Includes 466,667 warrants
Item 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Transactions Involving Mr. Howard Cooper and Ms. Anna Cooper.
Mr. Cooper and Teton have entered into an employment agreement. Mr. Cooper's
employment agreement with Teton is discussed at "EXECUTIVE COMPENSATION -
Employment Contracts."
Ms. Anna R. Cooper, Mr. Cooper's wife, is in the second year of a two year
employment agreement with Teton. The employment agreement provides that Ms.
Cooper's initial salary is $6,500 per month. After the initial term, the
agreement is automatically renewed from year to year, with such changes agreed
by the parties, unless terminated by either party upon 90 days prior notice. The
agreement provides that upon the termination of Ms. Cooper's employment without
her consent, except for terminations related to a criminal conviction, death,
disability, incapacity, bankruptcy, insolvency, gross negligence, gross
dereliction of duty, or gross misconduct, that Ms. Cooper is entitled to a lump
sum payment equal to three months salary, based on the salary being paid to Ms.
Cooper at the date of termination.
Prior to December 1, 2000, Teton had a consulting arrangement with Taimen
Corporation, to provide Teton with consulting and management services. Mr.
Cooper was the director and president of Taimen Corporation. Mr. Cooper and Ms.
Cooper were the sole employees of Taimen. Teton paid Taimen a total of $247,000
during the fiscal year ended December 31, 2000 and a total of $128,560 for the
fiscal year ended December 31, 1999.
In 2001, Mr. Cooper loaned $137,000 to Teton. Such loan, together with interest
at 8.28% per annum was due on February 1, 2002. The due date was subsequent
extended to April 15, 2002, and was paid in full in April 2002.
Management believes that the terms of these transactions with its management
were at least as favorable to the Company as those terms which the Company could
have obtained from unrelated third parties through arms-length negotiations.
Item 13. EXHIBITS AND REPORTS ON FORM 8-K.
Exhibits.
--------
Exhibit No. Description
----------- -----------
3.1.1 Certificate of Incorporation of EQ Resources Ltd incorporated
by reference to Exhibit 2.1.1 of Teton's Form 10-SB, filed July
3, 2001.
3.1.2 Certificate of Domestication of EQ Resources Ltd incorporated
by reference to Exhibit 2.1.2 of Teton's Form 10-SB, filed July
3, 2001.
3.1.3 Articles of Merger of EQ Resources Ltd. and American-Tyumen
Exploration Company incorporated by reference to Exhibit 2.1.3
of Teton's Form 10-SB, filed July 3, 2001.
3.1.4 Certificate of Amendment of Teton Petroleum Company
incorporated by reference to Exhibit 2.1.4 of Teton's Form
10-SB, filed July 3, 2001.
3.1.5 Certificate of Amendment of Teton Petroleum Company
incorporated by reference to Exhibit 2.1.5 of Teton's Form
10-SB, filed July 3, 2001.
3.1.6 Certificate of Amendment of Teton Petroleum Company increasing
the authorized capital stock
3.2 Bylaws, as amended, of Teton Petroleum Company incorporated by
reference to our From 10KSB for the year ended December 31, 2001.
10.1 Employment Agreement, dated May 1, 2002, between Teton
Petroleum Company and H. Howard Cooper incorporated by
reference to our Form 10KSB for the year ended December 31,
2001.
10.2 Memorandum of Understanding dated November 26, 2002
21.1 List of Subsidiaries.
99.1 Certification of the Chief Executive Officer of Teton Petroleum
Company Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002
99.2 Certification of the Chief Financial Officer of Teton Petroleum
Company Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
99.3 Code of Ethics and Business Conduct of Officers, Directors and
Employees of Teton Petroleum Company
99.4 Audit Committee Charter
Reports on Form 8-K.
-------------------
We filed the following reports on Form 8-K during our fourth quarter of 2002:
October 22, 2002, Item 8 - Reporting a change back to a December 31 fiscal
year-end.
December 12, 2002, Item 5 - Reporting proceeds raised on private placement
offering and third quarter results.
ITEM 14. CONTROLS AND PROCEDURES
As of December 31, 2002, an evaluation was performed by our Chief Executive
Officer and Acting Chief Financial Officer, of the effectiveness of the design
and operation of our disclosure controls and procedures. Based on that
evaluation, Our Chief Executive Officer and Chief Financial Officer, concluded
that our disclosure controls and procedures were effective as of December 31,
2002. There have been no significant changes in our internal controls or in
other factors that could significantly affect internal controls subsequent to
December 31, 2002.
SIGNATURES
In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934,
the Registrant duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
TETON PETROLEUM COMPANY, INC.
Date: March 31, 2003 By: /s/ H. Howard Cooper
-----------------------------------------
H. Howard Cooper, President (Chief
Executive Officer) and Director
Date: March 31, 2003 By: /s/ Thomas F. Conroy
-----------------------------------------
Thomas F. Conroy, Chief Financial Officer
(Principal Financial Officer)
Date: March 31, 2003 By: /s/ Karl F. Arleth
-----------------------------------------
Karl F. Arleth, Director
Date: March 31, 203 By: /s/ James J. Woodcock
-----------------------------------
James J. Woodcock, Director
CERTIFICATION
I, Howard Cooper, CEO, certify that:
1. I have reviewed this quarterly report on Form 10-KSB of Teton Petroleum
Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
March 31, 2003
/s/ Howard Cooper
Chief Executive Officer
CERTIFICATION
I, Thomas F. Conroy, CFO, certify that:
1. I have reviewed this quarterly report on Form 10-KSB of Teton Petroleum
Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
March 31, 2003
/s/ Thomas F. Conroy
Chief Financial Officer