Edgar Filing: TETON PETROLEUM CO

form-10ksb_123103

WASHINGTON, DC
FORM 10-KSB/A

[X] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003.

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: 303.542.1878

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 $11,437,802

The aggregate market value of the common stock held by non-affiliates of the
issuer, 8,579,894 shares of common stock, as of March 25, 2004, was
approximately $33,804,782, based on the closing bid of $3.94 for the issuer's
common stock as reported on the American Stock Exchange. 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, 2004, the issuer had 8,584,068 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE - NONE

Transitional Small Business Disclosure Format (Check one): YES [ ] NO
[X]

FORM 10-KSB
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003

INDEX

PART I
Item 1. Description of Business
Item 2. Description of Property
Item 3. Legal Proceedings
Item 4. Submission of Matters to a Vote of Security Holders

PART II

Item 5. Market for the Registrant's Common Equity and
Related Stockholder Matters
Item 6. Management's Discussion and Analysis or Plan of Operation
Item 7. Financial Statements
Item 8. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
Item 8A. Controls and Procedures

PART III

Item 9. Directors, Executive Officers, Promoters and Control Persons; Compliance
with Section 16(A) of the Exchange Act.
Item 10. Executive Compensation
Item 11. Security Ownership of Certain Beneficial Owners and Management
Item 12. Certain Relationships and Related Transactions
Item 13. Principal Accountant Fees and Services

PART IV

Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K

SIGNATURES

PART I

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
o uncertainty regarding certain disputed matters with our Russian partner
RussNeft

Summary

Teton Petroleum Company, through its consolidated subsidiary, 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.

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, exclusive of our proportionate share of notes payable owed to
affiliate.

During 2003, Teton's Goloil affiliate drilled seven new wells, bringing the
total number of wells that are capable of producing to 21 and completing its
drilling program for the year. Of the 21 wells, one is awaiting completion, and
four are off-line pending upgrades to the gathering system. Consequently, as of
the end of December, there were 16 producing wells. During the month of
December, the Goloil license produced an average of 7,164 barrels of oil per
day, of which 1,791 was net to Teton. Goloil management expects to complete the
above-mentioned gathering system upgrade during the first half of 2004, at which
time it also expects to commence the operation of its co-generation plant, which
has been delayed by permitting issues.

In September 2003, OAO NK RussNeft, a Russian independent oil producer became
Teton's partner in Goloil, by acquiring Mediterranean Overseas Trust and its
affiliates and all other Goloil shareholders. RussNeft succeeds Mediterranean
Overseas Trust as Manager of Goloil, but at this point continues to operate
through MOT. It is Teton's view that the agreements with MOT governing Goloil's
operations remain in effect until new agreements, now being negotiated, are in
place. Please refer to the Management Discussion and Analysis for an extensive
discussion on various disputes with RussNeft.

In 2003, Teton raised net proceeds of $10,251,924 from the issuance of preferred
and common stock. At the end of 2003, Teton had no outstanding debt obligations,
exclusive of our proportionate share of notes payable owed to affiliate, Goloil.

Item 1. DESCRIPTION OF BUSINESS.

Structure of Teton

Through our wholly-owned subsidiary, Goltech Petroleum LLC, we own 35.295% of
the Russian Joint Stock Company Goloil ("Goloil"). Mediterranean Overseas Trust
(together with its affiliates, including McGrady, Fenlex, Petromed, and
Energosoyuz-A ("ESA"), (collectively "MOT")) owns 35.295% of Goloil and serves
as Manager of Goloil. InvestPetrol, another Russian Joint Stock Company, owns
the remainder (29.41%) of Goloil. In September of this year, Goloil and its
affiliates, along with InvestPetrol were acquired by OAO NK RussNeft, a Russian
independent oil producer. RussNeft succeeds McGrady as Manager of Goloil, but at
this point continues to operate through McGrady. Consequently, our discussions
pertaining to Teton's structure and operations of the Goloil License will
continue to refer to McGrady (and affiliates) as Goloil's Manager and the
operator of the Goloil License.

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. InvestPetrol is currently not
funding any of this development. Based on the current structuring of Goloil and
the development agreements with Teton and MOT, and until Goltech and McGrady
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 ESA). 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 McGrady 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 was
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. As part of these
agreements, 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 December, 2003, the wells on our license area were producing 7,164 barrels
per day (1,791 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.

During 2003, Teton's Goloil affiliate drilled seven new wells, bringing the
total number of wells that are capable of producing to 21 and completing its
drilling program for the year. Of the 21 wells, one is awaiting completion, and
four are off-line pending upgrades to the gathering system. Consequently, as of
the end of December, there were 16 producing wells. During the month of
December, the Goloil license produced an average of 7,164 barrels of oil per
day, of which 1,791 was net to Teton. Goloil management expects to complete the
above-mentioned gathering system upgrade during first half of 2004, at which
time it also expects to commence the operation of its co-generation plant, which
has been delayed by permitting issues. Pursuant to the MOT agreements, MOT is
entitled to a production payment in kind. See "MOT Agreements", above. The
production payment is projected to be completed in June, 2007, based on revised
leases negotiated in late 2002.

Teton previously paid processing and transportation fees to a third party to
process and place its oil in the Trans-Siberia pipeline. Construction of a
processing facility on the license area was completed early in 2003.
Consequently we no longer incur the third-party processing charge.

Teton's share of the oil production is sold in Poland, Germany, Byelorussia,
Ukraine and Russia. Sales in Poland, Germany, Ukraine and Byelorussia 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 Transneft, the government owned
pipeline monopoly, up to a maximum of 35% of Goloil's oil production may be sold
outside of the Commonwealth of Independent States (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 four fiscal
years. Additional oil and gas disclosure can be found in Note 12 of the
Financial Statements.

PRODUCTION DATA

Year Ended December 31 2003 2002 2001 2000
--------- ------- ------ -----

Total Gross Oil Production, barrels 2,528,260 1,884,933 425,459 178,331
========= ======= ====== =====

Total Gross Gas Production, MCF - - - -
========= ======= ====== =====

Net Oil Production, barrel(1) 632,065 471,233 94,879 142,664
========= ======= ====== =====

Net Gas Production, MCF - - -
========= ======= ====== =====

Average Oil Sales Price, $/Bbl (2) $18.11 $15.38 $16.43 $11.00
========= ======= ====== =====

Average Gas Sales Price, S/MCF - - - -
========= ======= ====== =====

Average Production Cost per Barrel (3) $10.75(4) $9.96(4) $11.22 $10.00
========= ======= ====== =====

Gross Productive Wells Oil 21.0 13.0 7.0 3.0
========= ======= ====== =====

Gas - - - -
========= ======= ====== =====

Net Productive Wells
Oil 10.5 6.5 3.5 1.5
========= ======= ====== =====

Gas - - - -
========= ======= ====== =====

Total 10.5 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 price is a combination of domestic (Russian) and export
price.
(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 would
be $15.51 per barrel in 2002 and $17.45 per barrel in of 2003. 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 four
fiscal years in the Goloil license area:

NET WELLS DRILLED

Year Ended December 31 2003 2002 2001 2000
====================== ==== ==== ==== ====
Gross Net(1) Gross Net(1) Gross Net(1) Gross Net(1)
===== ====== ===== ====== ===== ====== ===== ======
Number of Wells Drilled
Exploratory (Research)
Productive - - - - 1.0 0.5 - -
===== ====== ===== ====== ===== ====== ===== ======

Dry - - - - - - - -
===== ====== ===== ====== ===== ====== ===== ======

Total - - - - 1.0 0.5 - -
===== ====== ===== ====== ===== ====== ===== ======

Development
Productive 7.0 3.5 6.0 3.0 3.0 1.5 2.0 1.0
===== ====== ===== ====== ===== ====== ===== ======

Dry - - - - - - - -
===== ====== ===== ====== ===== ====== ===== ======

Total 7.0 3.5 6.0 3.0 3.0 1.5 2.0 1.0
===== ====== ===== ====== ===== ====== ===== ======

(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.

As of March 25, 2004 Teton has completed and submitted to TDA its feasibility
study of the Eguryak license area pipeline project in 2004. 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 are to 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.

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. Starting from 1/1/2004 VAT was reduced to 18%. 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 11.50) 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 5.1) per horsepower;

(vii)Oil export duty, currently in the amount of USD 33.9 per ton of crude oil
being exported, increasing to USD 35.2 in 2004;

(viii) Regional property tax payable annually at 2.2% of the value of net 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 eight full time and two part time employees. We also utilize
the services of independent contractors on an as-needed basis. Teton also
employees three people in its Moscow representative office. 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 Oil and Gas 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 a good area 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

Important Note on Reserve Calculations:

o 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.

o 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.

o The Company has not filed reserve estimates with any federal agency.

Our estimated proved oil reserves and present value of the estimated future net
revenues attributable to such reserves have been updated for this filing with an
effective date of January 1, 2004. They are based on a report issued by the
independent consulting firm of Gustavson Associates, Inc. ("Gustavson") located
in Boulder, Colorado. The report was updated to take into account production
data obtained during 2003 on some of our wells, particularly those producing
from the Jurassic formation.

Reference is made to MANAGEMENT DISCUSSION AND ANALYSIS and to note 10 to the
financial statements for a full discussion of the dispute with RussNeft. As the
outcome of this dispute cannot be predicted at this time, the Company has
instructed Gustavson to prepare two separate proved oil reserve cases: the "Base
Case SEC reserves and Cash Flow Projections" and the Alternate case. The Base
Case assumes that the Company is not successful in it's dispute with RussNeft,
accordingly, the price received for oil is set at 2,400 rubles per ton ($11 per
barrel) and the production payment is deducted assuming 19 million rubles per
month. The Alternate case assumes that the Company is successful in the dispute
and that RussNeft and Goloil would honor all preexisting agreements. In the Base
Case, future cash flows are substantially less than in the Alternate case,
however oil reserves quantities are greater as a result of payout being delayed
and how the production payment is being calculated. In order to avoid misleading
statement readers, Management has elected to report the lower, alternate case
reserves, in both tables below.

As of January 1, 2004, our proved reserves are estimated at 8.262 million
barrels, net to Teton, after deducting quantities required to be delivered under
the production payment as summarized below:

Base Case SEC Reserves and Cash Flow Projections

Before Russian Profits Tax After Russian Profits Tax
-------------------------- -----------------------------

Total Present Value Total Present Value
Net Undiscounted Discounted Undiscounted Discounted
Reserves, Cash Flow, @10% Cash Flow, @10%,
Reserve thousand thousand thousand thousand thousand
Category barrels US$ US$ US$ US$
----------- --------- ------------ ------------ ------------- --------------

PDP 957 $1,330.6 $1,280.0 $1,087.9 $1,037.2
PDNP 2,859 $7,892.6 $5,621.6 $6,031.9 $4,239.5
Total Proved
Developed 3,816 $9,232.2 $6,901.6 $7,119.8 $5,276.8
PUD 4,445 $11,697.9 $4,813.4 $6,207.2 $1,195.0
Total Proved 8,262 $20,921.2 $11,715.0 $13,327.0 $6,471.7

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.

The price of oil used for this analysis was 2400 rubles per ton (about $11 per
bbl), net of transportation, marketing and export duties, as Goloil realized as
of year-end 2003. As discussed in the Business section of this filing, McGrady
and its affiliates were sold in September 2003 to OAO NK RussNeft, a Russian
independent oil producer. Commencing October 1, RussNeft began selling Goloil's
production to a related party for a fixed price of 2,400 rubles per ton (roughly
$11 per barrel), a price substantially below the blended market price Goloil
formerly received selling its production into the export, near abroad and
domestic markets. Since this pricing arrangement prevailed through the end of
the fourth quarter of 2003 and beyond, the Company has used the price of 2,400
Rubles per ton in its reserve report with the effect of significantly reducing
the present value of its reserves effective January 1, 2004.

Teton has strenuously objected to RussNeft's actions and is continuing to engage
its management in discussions, while retaining counsel with the intention of
vigorously pursuing it rights under previous agreements and as a significant
minority shareholder in Goloil. While counsel has advised the Company that its
position has merit, the outcome of this dispute cannot be predicted at the
current time.

The oil and gas revenues are net to Teton and include the impact of the
production payments paid as flat fee of 19 million rubles per month (including
VAT), and financing and debt repayment. Cash flow amounts assume 50% economics
net to Teton without payout. Teton's net share is 50% before payout and 35.295%
after payout.

The present value of estimated future net revenues as of January 1, 2004, has
been adjusted for Russian profits taxes, but not U.S. 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 $20.92 and $13.32 million or,
discounted at 10%, $11.72 and $6.47 million, for total proved reserves.

Capital expenditures required to achieve the above cash flows will be incurred
over the next three years and are estimated at $14.6 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.

Presented below is the Alternate Case discussed above which assumes that Teton
is successful in its dispute with RussNeft, the resulting economic parameters,
as of January 1, 2004 would be as presented below.

Alternate Case Reserves and Cash Flow Projections

Before Russian Profits Tax After Russian Profits Tax
------------------------ --------------------------
Present Present
Total Value Total Value
Net Undiscounted Discount Undiscounted Discounted
Reserves, Total Cash Flow @10% Cash Flow, @10%
Reserve thousand Well thousand thous. thous. thous.
Category barrels Count US$ US$ US$ US$
--------- ---------- ------ ------------- --------- ------------- -----------

PDP 957 16 $5,791 $5,323 $4,335 $3,936
PDNP 2,859 3 $23,287 $15,052 $16,358 $10,455
Total
Proved
Developed 3,816 19 $29,078 $20,375 $20,693 $14,390
PUD 4,445 21 $27,295 $12,661 $16,894 $6,556
Total 8,262 40 $56,373 $33,036 $37,588 $20,946
Proved

The prices used for this Alternative Case were as of year-end 2003. Goloil
normally sells its oil into three different markets: Europe, where the price is
tied to the Urals Blend benchmark which itself is closely related to the price
for Brent Crude; the domestic Russian market, and to non-Russian FSU markets
such as the Ukraine and Byelorussia, generally referred to as the "near abroad".
Sales in the domestic and near abroad markets are made in batches, when
sufficient quantities of produced oil are available to sell and there are no
spot prices are published that apply to these markets. The markets are
established by individual transactions, for which the buyers and sellers
generally hold the prices confidential.

Consequently, at December 31, 2003 Teton used the Urals Blend benchmark with a
-$2.43 basis adjustment for its export sales, while polling Moscow based oil
trading firms for year-end prices for the domestic and near-abroad markets and
using the lowest price returned in the polls. The prices used were $25.00/barrel
for export, $18.00 per barrel for the near abroad, and $15.00/barrel for the
domestic market. Sales were allocated to the three markets at 35% European, 10%
FSU, and 55% Russia, which is approximately the historic allocation.

The results are net to Teton and include the impact of the production payments
due MOT, and financing and debt repayment. Cash flow amounts assume 50%
economics net to Teton without payout. Teton's net share is 50% before payout
and 35.295% after payout.

The present value of estimated future net revenues as of January 1, 2004, has
been adjusted for Russian profits taxes, but not U.S. 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 $56.37 and $37.59 million or,
discounted at 10%, $33.03 and $20.95 million, for total proved reserves.

Teton's current agreement with MOT requires the two companies 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.

Changes to the Reserve Report from Prior Period

The following table summarizes the changes that took place when the report was
updated:

Reserves and Production, in barrels, Net to Teton

For the Years Ended
December 31,
=========================
2003 2002
========== ==========

Proved reserves (bbls), beginning of period ......... 13,264,000 40,174,000
========== ==========
Production ......................................... (632,000) (471,000)
========== ==========
Extension of reservoir ............................. -- 2,000,000
========== ==========
Revisions of previous estimates .................... (4,370,000) (28,439,000)
========== ==========
Proved reserves (bbls), end of period ............... 8,262,000 13,264,000
========== ==========
Proved Developed reserves (bbls), beginning of period 4,567,000 5,493,000
========== ==========
Proved Developed reserves (bbls), end of period ..... 3,816,000 4,567,000
========== ==========

In the revised reserve report, Teton's proved reserves declined from 13.26
million barrels to 8.26 million barrels of which 632 thousand barrels reflected
production during 2003. Of the remaining decline, 4.37 million barrels, was due
to a revision from the previous estimate. In particular, the performance of
several of the Company's Jurassic formation wells led its engineers to reduce
the anticipated primary (before waterflood) recovery of reserves and revise
their opinion concerning the necessity of waterflooding. While the Company
anticipates it will eventually recover most of the reduction in reserves through
waterflooding, SEC regulations do not permit the inclusion of such reserves in
the proven category in the absence of either a pilot program or formal written
commitment by the operator and non-operators in a project to commence the
waterflood project. The Company also removed several Jurassic locations from the
proved category, either because they were deemed uneconomic for primary
production alone, based on the performance of offsetting Jurassic producing
wells or in two cases because the operator and Company have not yet formally
agreed to drill them. The company expects to restore the reserves from the two
wells to the proven category when they are drilled.

Finally, as previously reported in its Form 10-K for the year ended December 31,
2002, the Company recorded a decline in its reserves for the year 2002 of 28.4
million barrels. The majority of the reserve reduction in this period was
attributable to revision of the geologic maps of the license area based on new
and reprocessed seismic data and interpretations. The new interpretation led to
a reduction in the number of anticipated drilling locations and with them,
reserves.

Developed And Undeveloped Acreage

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, 2003:

Eguryak License Area Gross Net
Total Developed Acres 1,049 525
Total Proved Undeveloped 1,494 747
Acres
Total Other Undeveloped 6,481 3,241
Acres

Our offices are located in Denver, Colorado. We lease our offices from an
unaffiliated third party. This year we also opened a representative office in
Moscow, also leased 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 2003.

PART II

Item 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDERS MATTERS.

Teton's common stock listed on The American Stock Exchange, under the symbol
"TPE," on May 6, 2003. Prior to listing on the AMEX, our common stock was quoted
on the OTC Bulletin Board under the symbol "TTPT" from November 27, 2001 to
April 25, 2003 and then under the symbol "TTPE" from April 28, 2003 to May 5,
2003 as a result of a 1 for 12 reverse stock split.

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, and after May 5,
2003 on the American Stock Exchange:

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
Second quarter as of May 5, 2003 $ 5.00* $4.10*

The American Stock Exchange

Second quarter commencing May 6, 2003 $ 5.40 $4.10

Third quarter $ 4.58 $3.71
Fourth quarter $ 5.58 $3.80

*reflects a 12 for 1 reverse stock split effectuated on April 24, 2003.

The quotations reflect inter-dealer prices without retail markup, markdown, or a
commission, and may not necessarily represent actual transactions.

Holders: As of January 23, 2004, there were approximately 195 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.

Recent Issuances of Unregistered Securities

During the fourth quarter for the year ended December 31, 2003, the Company sold
2,263,330 shares of 8% convertible preferred shares for a total consideration of
$9,845,486, less $520,856 in commissions. The preferred shares carry an 8%
dividend, payable quarterly and are convertible into common stock at a price of
$4.35. If converted within 60 days of closing, the investors will be entitled to
receive (i) dividends payable in common stock for one year; and (ii) 2 Class B
Warrants for each 10 invested, exercisable at $6.00 per share.

Equity Compensation Plan Information

Plan category Number of Weighted average Number of
securities to exercise price securities
be issued upon of outstanding remaining
exercise of options, available for
outstanding warrants and future issuance
options, rights
warrants and
rights
(a) (b) (c)
Equity compensation plans 1,578,037 $3.48 505,296
approved by security holders
Equity compensation plans 0 0 0
not approved by security
holders
Total 1,578,037 $3.48 505,296

Item 6. MANAGEMENT'S DISCUSSION AND ANALYSIS

The following discussion and analysis of our plan of operation should be read in
conjunction with the financial statements and the related notes. This document
contains forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934
which are based upon current expectations that involve risks and uncertainties,
such as our plans, objectives, expectations and intentions. Our actual results
and the timing of certain events could differ materially from those anticipated
in these forward-looking statements as a result of certain factors, including
those set forth under "Risk Factors," "Business" and elsewhere in this document.

We have identified certain policies 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. See the section entitled "Critical Accounting Policies" at
the end of this discussion.

Overview

Teton Petroleum Company is an independent oil and gas exploration company whose
current focus is the Russian Federation, particularly Western Siberia. It
currently is the only publicly traded US independent with all of its production
in Russia.

In 2003, Teton achieved several milestones in its finances and operations, as
well as some challenges. Highlights include the following:

o Annual sales increased by 42.5% from 443,268 to 631,626 barrels, net to
Teton.

o Seven new wells (gross) were drilled on the Company's Goloil license
bringing the total to 21 wells, 16 of which were in production at year-end.
Of the 21 wells, one is awaiting completion, and four are off-line pending
upgrades to the gathering system.

o Revenues increased 65.2%, from $6,923,320 to $11,437,802.

o The Company's net loss for the year narrowed from $10,973,923 to
$5,634,844.

o In April, Teton's Board of Directors made several changes to the management
of the Company the most important of which was the appointment of a new
President and Chief Executive Officer, Karl Arleth, who assumed
responsibility for the day-to-day management of the Company. Other
management changes made at the time included the appointment of a
Controller and an interim full-time Chief Financial Officer.

o Also in April, the Company relocated its corporate headquarters from
Steamboat Springs, CO to Denver, CO and over the next several months hired
several administrative and accounting personnel to support the Company's
plans for growth. The Company also took steps to tighten its internal
controls, enhance its ability to evaluate potential acquisitions, and
improve its information systems.

o In May, the Company effected a 1:12 reverse share split and listed its
shares on the American Stock Exchange.

o Also in May, the Company announced the signing of a purchase and sale
agreement to acquire the 50% ownership interest in LLC Chernogorskoye held
by Anderman Smith, which if completed would have added approximately 4,000
BOPD to the Company's net oil production. To date, however, the Company has
been unable to close this transaction owing to differences with the seller
over closing price adjustments the Company believed necessary following its
due diligence, as well as changes in the valuations accorded Russian oil
producers. Although the Company is continuing to pursue the acquisition of
all or part of LLC Chernogorskoye, there is no assurance it will be able to
close any transaction.

o In November, the Company successfully concluded the private placement of
$9.8 million (later increased to $10.3 million in January of 2004) of 8%
Convertible Preferred Stock to be used primarily for working capital in the
Goloil license and for general corporate purposes.

o The Company opened a Moscow Representative Office in December to better
monitor its operations in Russia as well as to establish a higher profile
in the Russian oil industry and facilitate greater deal-flow as it pursues
acquisition opportunities there and in other FSU states.

Dispute with RussNeft

Foremost among the challenges facing the Company in 2003 were those presented by
its former and present partners in the Goloil license. In September, OAO NK
RussNeft, a newly formed Russian independent oil producer acquired the shares
held by Mediterranean Overseas Trust and InvestPetrol in Goloil and assumed
responsibility for operating the License. During the transition in September,
the Company subsequently learned, Goloil sold substantially less than its export
quota into export markets where prices are substantially higher, instead selling
the production into the domestic market.

Commencing October 1, RussNeft began selling Goloil's production to a third
party for a fixed price of 2,400 rubles per ton (roughly $11 per barrel), a
price substantially below the blended market price Goloil formerly received
selling its production into the export, near abroad and domestic markets. As a
consequence, the Company estimates its revenues after taxes for the quarter were
reduced by approximately $1.44 million. Moreover, since this pricing arrangement
prevailed through the end of the fourth quarter and beyond, the Company has had
to significantly reduce the present value of its reserves effective January 1,
2004.

Teton has strenuously objected to RussNeft's actions and is continuing to engage
its management in discussions over the issue, while retaining counsel with the
intention of vigorously pursuing it rights under previous agreements and as a
significant minority shareholder in Goloil. While counsel has advised the
Company that its position has merit, the outcome of this dispute cannot be
predicted at the current time.

2004 Operational and Financial Objectives

In 2004, Teton intends to focus its efforts primarily in two areas:

1) Continued development of its Goloil License; and

2) The acquisition, development and exploitation of similar projects in the
Russian Federation.

As a specific target, Teton intends through a combination of drilling and
acquisition(s) to increase its daily net production in 2004 to at least 5,000
BOPD.

Goloil will continue to expand operations with the drilling of four horizontal
wells on the Golevaya Field and carry out fracture stimulations on four existing
Jurassic wells in the Egurayah Field. Also, new development plans for the South
Egurayah Field will be completed once the results of an on-going 3D seismic
program are evaluated. Goloil's capital budget for 2004 is approximately $17
million. Most of this budget is expected to be provided for out of internal cash
flow and borrowing by Goloil, including possible cash calls to Teton. Teton
believes it has sufficient working capital on hand to meet its share of any such
cash calls, but whether it will elect to do so will be contingent upon
successful resolution of its dispute with RussNeft over product pricing
described above. There can be no guarantee it will reach such a successful
resolution, and if it is unable to, management intends to look at various
options including legal action or the possible sale of its stake in Goloil. In
Management's opinion the proceeds from the sale of the Company's stake in Goloil
would exceed it's investment at December 31, 2003.

As for growth through acquisitions, Teton has been actively seeking to make
acquisitions of properties similar to the Goloil license since the spring of
2003. Specifically, the Company is targeting properties with existing production
ranging from 3,000 to 10,000 BOPD with upside potential from developmental
drilling and other exploitation opportunities. The Company has a strong
preference to be the operating partner in such projects in order to better
control their development. In addition to the LLC Chernogorskoye transaction
announced, but not consummated, in 2003, the Company has held talks with several
Western and Russian owned companies that are seeking to divest properties.

Teton's plans to pursue such acquisitions means that it will incur increased due
diligence and legal expenses. The Company is now devoting significant internal
resources to evaluating acquisitions while also utilizing the services of
outside technical and legal consultants.

An even more important factor in executing its acquisition strategy is the
Company's ability to attract the capital necessary to acquire and develop its
acquisition targets. Towards that end, the Company has been working to develop
strong relationships with commercial, primarily European banks, which are active
in Russia and the former Soviet Union. Teton has traditionally financed its
operations by raising equity, but it is the opinion of its management that the
acquisition of properties with significant production is best financed with a
combination of debt and equity. This approach is less dilutive to existing
shareholders and offers the Company greater flexibility. Based on its
discussions with various lending institutions, Teton management is confident of
its ability to secure bank financing for producing property acquisitions.

Insofar as most acquisitions will require Teton to provide at least some equity
financing, Management anticipates that it will likely be required to raise
additional equity. The Company maintains an active investor relations program
and is also in frequent contact with investment banks, both in the U.S. and
abroad, as well as with institutional and industry sources of private capital.

Teton management expects a rising trend in the cost of producing property
acquisitions in Russia over the next several years as the export bottlenecks
preventing Russian oil from leaving the country ease and as well-capitalized
Western E&P companies are increasingly drawn to the country's vast reserves
of oil and gas. Consequently, a key challenge facing the Company is its ability
to acquire reserves on an economically attractive basis. Management believes the
day is long gone when projects with the quality of Goloil could be acquired for
as little as $0.25 per proven barrel in the ground. Today, the asking price for
many Russian producing properties is ten times that level or $2.50 per barrel,
compared to $6 - 8 per barrel currently for Texas oil and gas properties. Teton
management, therefore, applies rigorous economic analysis to determine if such
acquisitions can meet the Company's economic hurdle rates based on a
conservative market-linked forecast of oil prices. Present indications are that
such projects are available for sale today in Russia, but are less common than
they used to be, necessitating that they be actively sought out.

The following table sets forth certain operating data for the periods presented:

Year ended December 31, 2003 compared to year ended December 31, 2002.

The table below summarizes some of the most important components of our
revenues, operating costs and net loss. Please note that since Teton absorbs its
share of the cost of producing the oil paid under the production payment
(included in the cost amounts), per barrel costs are effectively doubled.

Results of Operations

Operating Highlights for the Twelve Months ended December 31
(in U.S. Dollars, unless otherwise noted)

Fourth
Quarter
2003 2003 2002 Change($) Change(%)
------------ ------------ ------------ ------------ --------
Sales, Barrels ........ 150,938 631,626 443,268 188,358 42.5%
Average Daily Sales,
Barrels .............. 1,654 1,730 1,214 516 42.5%
Average Selling Price,
$/barrel ............. $15.45 $ 18.11 $15.62 $ 2.49 15.9%
Revenues .............. $ 2,332,464 $ 11,437,802 $ 6,923,320 $4,514,482 65.2%

Costs of Sales and
Expenses, excl. DD&A
Production Costs ..... 563,590 2,020,447 1,218,411 802,036 65.8%
Transportation &
Marketing ........... 6,061 807,266 611,956 195,310 31.9%
Taxes other than
Income taxes ........ 1,700,920 5,864,920 3,537,990 2,326,930 65.8%
Export Duties ......... -- 1,492,999 910,936 582,063 63.9%
------------ ------------ ------------- ------------ ---------
2,270,571 10,185,632 6,279,293 3,906,339 62.2%

Results from Goloil
Operations, before DD&A 61,889 1,252,170 644,027 608,143 94.4%
Less General &
Administrative Expense,
Goloil ............... 188,229 837,134 588,774 248,360 42.2%

Goloil operating (loss)
income before DD&A .... (126,340) 415,036 55,253 359,783 --

Depreciation, Depletion
& Amortization, Goloil 919,744 1,582,513 451,930 1,130,583 250.2%
------------ ------------ ------------ ------------ --------

Operating loss, Goloil (1,046,084) (1,167,477) (396,677) (770,800) --

General &
Administrative Expense,
Teton ................ 1,244,063 3,919,746 4,744,952 (825,206) -17.4%
------------ ------------ ------------ ------------ --------

Operating Loss, Teton . $ (2,290,147) $ (5,087,223) $ (5,141,629) $ 54,406 -
============ ============ ============ ============ ========

Costs and Expenses Per Barrel during the Twelve Months ended December 31
(in U.S. Dollars)

Fourth
Quarter Change
Controllable Costs 2003 2003 2002 ($) % Change
------------------------------------------------------------
------------------------------------------------------------
Production Costs $3.73 $ 3.20 $ 2.75 $0.45 16.4%
G&A - Goloil 1.25 1.33 1.33 (0.00) -0.%
G&A - Teton 8.24 6.21 10.70 (4.49) -42.0%
13.22 10.74 14.78 (4.04) -27.4%

Non-Controllable Costs
Transportation & 0.04
Marketing 1.28 1.38 (0.10) -7.2%
Taxes other than 11.27
Income Taxes 9.29 7.98 1.31 16.4%
Export Duties 0.00 2.36 2.06 0.30 14.6%
$11.31 $12.93 $11.42 $1.51 13.2%

In 2003, Teton's net loss narrowed from $10,973,923 to $5,634,844, or $8,415,537
after giving effect to the imputed preferred stock dividends for inducements and
beneficial conversion charges associated with the Company's 8% convertible
preferred stock offering and subsequent conversion. In terms of earnings per
share, Teton's loss narrowed from $3.53 to $1.23 per share. The decrease in
losses was largely attributable to improved operating results at Goloil and a
significant decline in non-cash charges related to financing, offset by
increased salaries and other expenses related to the Company's increased
staffing levels.

Oil revenues increased from $6,923,320 to $11,437,802 from 2002 to 2003. The
increase was due to both a 42.5% increase in barrels sold and a 15.9% increase
in the average price per barrel sold from $15.62 to $18.11 per bbl.
Historically, Teton has not hedged its sales and this remained the case in 2003.
However, as discussed above revenues were less than expected during the fourth
quarter of 2004 by $1.44 million due to the fixed price paid by an affiliate of
RussNeft when compared to blended market price Goloil received previously. If
such affiliate continues to pay the fixed price in 2004, the Company anticipates
that a similar reduction in revenues and operating earnings for each 2004
quarter.

Teton's share of Goloil's costs of sales and expenses (before depreciation,
depletion and amortization expenses or "DD&A") increased 62.2%, which was
slightly less than the increase in revenues. As seen from the table above, taxes
other than income taxes and export tariffs are both important contributors to
these costs and expenses accounting for more than 70% of the total costs in both
2002 and 2003. Both are tied directly to revenues, and in the case of the export
tariff, to the price of oil as well. Export tariffs would have been higher had
not Goloil effectively stopped exporting oil at the end of the third quarter,
instead selling all of its production domestically for a flat fee of 2,400
rubles per ton.

Teton's share of Goloil's operating income before DD&A increased from $55,253 to
$415,036 from 2002 to 2003, but after Goloil's DD&A its share of operating
losses rose from $396,677 to $1,167,477. DD&A itself increased by 250.1%, from
$451,930 to $1,582,513, reflecting the capital expenditures incurred by Goloil
as it has developed its license.

General and administrative expense ("G&A") at Teton decreased from $4,774,952 to
$3,919,746 or 17.4% from 2002 to 2003. The decrease was largely attributable to
a $1,562,575 decline in fees paid to consultants for capital raising activities
offset by increases in compensation to officers and employees ($323,951),
professional fees ($109,146), travel and entertainment ($193,773), and expenses
relating to marketing, advertising, and investor relations ($167,987). In
addition to the increase in compensation relating to additional staffing to meet
Company goals and objectives, most of the other G&A increases were the result of
activities such as Teton's preferred stock offering, its listing on the American
Stock Exchange, the filing of its registration statement with the SEC, and due
diligence with respect to the proposed acquisition of LLC Chernogorskoye.

Liquidity and Capital Resources

Future cash flows will be influenced, among other factors, by the market price
of oil and gas as well as the number of producing properties on line. To the
extent that oil prices decline, the Company's revenues, cash flows and earnings
could be adversely affected. The Company's management believes that even if oil
prices were to decline to a level that would have a material adverse effect on
cash flows, the Company would continue to meet its working capital obligations
and its 2004 capital budget (as discussed below).

The Company had cash balances of $7,588,439 at December 31, 2003 and a working
capital deficit of $1,159,687. Excluding the pro rata consolidation of Goloil's
working capital deficit, Teton has a working capital surplus of $7,469,785.
Teton is not liable for Goloil's debts.

Sources and Uses of Funds

To date the Company's primary source of liquidity is cash provided by equity
offerings. Capital markets will continue to be utilized in order to maintain the
Company's indebtedness at moderate levels to enable the Company to have the
necessary financial flexibility to react to future opportunities. The Company's
primary needs for cash are for the operation, development, production,
exploration and acquisition of oil and gas properties and working capital
obligations.

Cash Flows and Capital Expenditures

Cash used in operating activities for the year ended December 31, 2003 was
$3,011,202 compared with cash used in operating activities for the year ended
December 31, 2002 of $5,168,785, resulting in a decrease of $2,157,583. Such
decrease is primarily the fact that operating assets and liabilities, which are
primarily in Goloil, increased in 2003 by $823,831 while they decreased
$1,129,412 in 2002.

The Company used $7,093,146 in investing activities, substantially all of which
was associated with oil and gas property and equipment expenditures. The
Company's pro rata share of the construction costs of a new gas-powered
electrical generating plant which will be operational in the first half of 2004
totaled $1,700,696. The plant will provide substantial increases in production
levels of electricity at lower cost than the diesel generators being replaced.
The plant will be fueled by natural gas from our wells, reducing or eliminating
the need to "flare" the gas. In addition Goloil drilled seven new wells (gross)
during 2003. The Company continues to expect significant additional investments
to be made in the future to drill and develop additional producing wells.
Teton's share of 2004 Goloil's capital expenditure program is estimated to be
$6.5 million. Goloil plans to drill in 2004 four horizontal wells, subject to
the results of a 3 D seismic program and begin installation of infrastructure
for the development of the South Eguriakhskoe oil field. The Company's funding
of the capital expenditure program will be included in the discussions regarding
resolving the dispute with RussNeft.

Cash provided by financing activities during 2003 was $16,812,518. In addition
to collecting $1,939,610 from stock subscriptions receivable at December 31,
2002, the Company raised $10,251,924 from the private placement of 8%
Convertible Preferred Stock to be used primarily for working capital in the
Goloil license and for general corporate purposes.

The Company anticipates future operations and significant oil and gas property
expenditures will be able to be funded through a combination of note payable
advances from an affiliate, cash raised from raising debt and equity financing
and production of oil and gas reserves.

Income Taxes, Net Operating Losses and Tax Credits

Currently, the Company is paying a profits tax in Russia equal to 24% of net
profits as defined by Russian income tax law. As discussed extensively
elsewhere, including Note 10 to the financial statements, the taxation system in
Russia is evolving as the central government transforms itself from a command to
a market-oriented economy. Based on current tax law and the U.S. Russian Income
Tax Treaty the profits tax paid to Russia will be a creditable tax when
determining the Company's U.S. income taxes payable, if any. At December 31,
2003 the Company has a U.S. net operating loss tax carry forward of
approximately $18,500,000. Based on the current investments of the Company and
the net operating loss combined with the Company's tax basis, the Company will
not be paying U.S. income taxes in the foreseeable future.

Critical Accounting Policies

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.

Reserve Estimates: 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. Estimates of economically
recoverable oil and natural gas reserves and future net cash flows necessarily
depend upon a number of variable factors and assumptions, such as historical
production from the area compared with production from other producing areas,
the assumed effects of regulations by governmental agencies and assumptions
governing future oil and natural gas prices, the exchange rate between the
Russian ruble and the U.S. dollar, future operating costs, severance, ad
valorem, export, excise and other taxes, development costs and workover and
remedial costs, all of which may, in fact, vary considerably from actual
results. For these reasons, estimates of the economically recoverable quantities
of oil and natural gas attributable to any particular group of properties,
classifications of such reserves based on risk of recovery, and estimates of the
future net cash flows expected there from may vary substantially. Any
significant variance in the assumptions could materially affect the estimated
quantity and value of the reserves, which could affect the carrying value of the
Company's oil and gas properties and the rate of depletion of the oil and gas
properties. Management believes that the current assumptions used in preparation
of the reserve study are reasonable. The Company's revised downward its estimate
of oil and gas reserves by 4.4 million barrels primarily due to the
reclassification of certain waterflood reserves and reserves associated with
undrilled locations to probable. Only reserves associated with two wells planned
and budgeted for 2004 have been classified as proved undeveloped. The Company's
estimated proved reserves at December 31, 2003 and 2002 were prepared by
independent petroleum engineering consultants Gustavson and Associates.

Property, Equipment and Depreciation: The Company follows the successful efforts
method of accounting for oil and gas properties. As of December 31, 2003 all of
the Company's oil and gas assets are held in one cost center located in Siberia,
Russia. As the Company makes additional acquisitions it will have additional
cost centers. Under the successful efforts method of accounting the costs of
development wells are capitalized, but exploratory wells are capitalized only if
they are successful. The Company plans to increase its oil and gas reserves by
acquisition and the development of reserves in place. Accordingly, acquisition
and drilling costs will be capitalized. Capitalized costs will be depleted and
depreciated using the units of production method based on estimated proved oil
reserves as determined by independent engineers, currently Gustavson and
Associates. If the estimates of oil and gas reserves are changed materially then
the amount of depreciation and depletion recorded by the Company could increase
or decrease materially. In addition the carrying costs of the oil and gas
properties are subject to the requirements of SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets". The Company is required to impair
the net book value for a cost center when such net book value is greater than
the estimated future cash flows for such cost center. At December 31, 2003 the
Company's carrying value for its Siberian cost center is less than its estimated
cash flows, even though such estimated cash flow was calculated using the
domestic Russian price of 2,400 rubles per ton ($11 per barrel). See discussions
above, and in footnotes 10 and 11 to the financial statements. As a result of
the downward revision in oil reserves recorded by the Company, the Company
increased its provision for depletion, depreciation and amortization to $919,744
for the fourth quarter compared to $274,538 recorded in the third quarter of
2003.

Pro Rata Consolidation: The Company currently pro rata consolidates its 50%
interest in Goloil, because, as of December 31, 2003, Management believes that
to be the most meaningful presentation. If the Company is not successful in its
dispute with RussNeft, then the Company may have to reconsider this accounting
policy. Such consideration will include determining the degree of influence the
Company exercises over its investment in Goloil.

Production Payment: During June, 2000 the Company entered into a Master
Agreement that requires, among other things, a seven year production payment to
Energosoyuz equal to 50% of the oil produced from new and existing Goloil wells
in exchange for wells and facilities constructed by Energosoyuz. Because the
production payment was for a specified amount of production and not for a fixed
and determinable dollar amount, the Company did not record such transaction as a
loan. Currently, Goloil is paying Energosoyuz a flat amount of 19,000,000 rubles
per month, which, at current prices, is less than 50% of the oil produced. If
the Company is not successful in its dispute with RussNeft, and the Company
continues with pro rata consolidation, it may be required to record as a
liability the net present value in U.S. dollars of the production payment with a
corresponding increase in the carrying value of its Siberian oil and gas cost
center. The amount of increase in carrying value can not be determined at this
time. However, based on the estimated cash flows at December 31, 2003, the
Company would, most likely, have to record an impairment charge.

Asset Retirement Obligation: During the fourth quarter of 2003 the Company
applied the provisions of SFAS 143 "Accounting for Asset Retirement Obligations"
and recorded the estimated December 31, 2003 liability for the retirement of its
Russian oil and gas assets along with a corresponding increase in the carrying
value of the related oil and gas properties. The liability was estimated based
on the estimated, discounted future cost to plug the oil and gas wells existing
at December 31, 2003 plus the costs of clean up based on the Company's current
understanding of the standards that will be applied at the time of retirement.
The Company will continually review the assumptions it used in making such
estimate and revise the liability as required.

Item 7. FINANCIAL STATEMENTS

TETON PETROLEUM COMPANY

Consolidated Financial Statements
and
Independent Auditors' Report
December 31, 2003

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 and subsidiary as of December 31, 2003, and the related consolidated
statements of operations and comprehensive loss, changes in stockholders'
(deficit) equity and cash flows for the years ended December 31, 2003 and 2002.
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 the 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 and subsidiary as of December 31, 2003, and the results of their
operations and their cash flows for the years ended December 31, 2003 and 2002
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 29, 2004
Denver, Colorado

TETON PETROLEUM COMPANY

Consolidated Balance Sheet
December 31, 2003

Assets

Current assets
Cash ................................................... $ 7,588,439
Proportionate share of accounts receivable ............. 15,739
Proportionate share of VAT receivable .................. 1,078,369
Proportionate share of inventory ....................... 448,812
Prepaid expenses and other assets ...................... 95,693
------------
Total current assets ................................. 9,227,052
------------

Non-current assets
Oil and gas properties, net (successful efforts) ....... 9,339,786
Cogeneration plant construction in- progress ........... 1,700,696
Other property and equipment, net ...................... 450,841
------------
Total non-current assets ............................. 11,491,323
------------

Total assets .............................................. $ 20,718,375
============

Liabilities and Stockholders' Equity

Current liabilities
Accounts payable and accrued liabilities ............... $ 376,429
Proportionate share of accounts payable and accrued
liabilities ........................................... 2,590,901
Proportionate share of notes payable owed to
affiliate ............................................. 7,419,409
------------
Total current liabilities ............................ 10,386,739
------------

Non-current liabilities
Asset retirement obligation ............................ 126,500
------------
Total non-current liabilities ........................ 126,500
------------
Total liabilities .................................... 10,513,239
------------

Commitments and contingencies

Stockholders' equity
Series A convertible preferred stock, $.001 par
value, 25,000,000 shares authorized, 618,231 issued
and outstanding. Liquidation preference at December
31, 2003 of $2,689,305 ................................ 618
Common stock, $.001 par value, 250,000,000 shares
authorized, 8,584,068 shares issued and outstanding
at December 31, 2003 .................................. 8,584
Additional paid-in capital ............................. 37,073,366
Unamortized preferred stock dividends ............... (118,610)
Accumulated deficit .................................... (27,657,578)
Foreign currency translation adjustment ................ 898,756
------------
Total stockholders' equity ........................... 10,205,136
------------

Total liabilities and stockholders' equity ................ $ 20,718,375
============

See notes to consolidated financial statements.

TETON PETROLEUM COMPANY

Consolidated Statements of Operations and Comprehensive Loss

For the Years Ended
December 31,
----------------------------
2003 2002
------------ ------------

Sales ............................................... $ 11,437,802 $ 6,923,320

Cost of sales and expenses
Oil and gas production ........................... 2,020,447 1,218,411
Transportation and marketing ..................... 807,266 611,956
Taxes other than income taxes .................... 5,864,920 3,537,990
Export duties .................................... 1,492,999 910,936
General and administrative - Goloil .............. 837,134 588,774

General and administrative - Teton ............... 3,919,746 4,744,952
Depreciation, depletion and amortization ......... 1,582,513 451,930
------------ ------------
Total cost of sales and expenses ............... 16,525,025 12,064,949
------------ ------------

Loss from operations ................................ (5,087,223) (5,141,629)
------------ ------------

Other income (expense)
Other income ..................................... 17,445 51,751
Interest expense ................................. (347,740) (385,939)
Financing charges ................................ (132,818) (5,498,106)
------------ ------------
Total other income (expense) .................. (463,113) (5,832,294)
------------ ------------

Net loss before tax ................................. (5,550,336) (10,973,923)
Foreign income tax .................................. (84,508) --
------------ ------------
Net loss ............................................ (5,634,844) (10,973,923)

Imputed preferred stock dividends for inducements and
beneficial conversion charges ....................... (2,780,693) --
------------ ------------

Net loss applicable to common shares ................ (8,415,537) (10,973,923)

Other comprehensive loss, net of tax
Effect of exchange rates ......................... 168,256 (140,773)
------------ ------------

Comprehensive loss .................................. $ (8,247,281) $(11,114,696)
============ ============

Basic and diluted weighted average common shares
outstanding ....................................... 6,840,303 3,105,235
============ ============

Basic and diluted loss per common share ............. $ (1.23) $ (3.53)
============ ============

See notes to consolidated financial statements.

TETON PETROLEUM COMPANY

Consolidated Statements of Changes in Stockholders' (Deficit) Equity
For the Years Ended December 31, 2003 and 2002

Foreign Total
Preferred Stock Common Stock Additional Unamortized Currency Stockholders'
---------------------------- --------------------------- Paid-in Preferred Stock Translation Accumulated (Deficit)
Shares Amount Shares Amount Capital Dividends Adjustment Deficit Equity
------------ ------------ ------------ ------------ ------------ ------------ ------------ ------------ ------------

Balance - December 31, 2001 ................................. -- $ -- 2,374,046 $ 2,374 $ 9,792,722 $ -- $ 871,273 (11,048,811) $ (382,442)

Common stock issued for cash ................................ -- -- 1,223,737 1,224 3,332,236 -- -- -- 3,333,460

Common stock subscriptions paid in 2003 ..................... -- -- 712,045 712 1,938,898 -- -- -- 1,939,610

Common stock and warrants issued for services ............... -- -- 221,198 221 836,905 -- -- -- 837,126

Common stock issued for conversion of convertible
debentures .................................................. -- -- 1,758,494 1,758 5,353,231 -- -- -- 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 ................................. -- -- 6,289,520 6,289 26,165,215 -- 730,500 (22,022,734) 4,879,270

Common stock issued for cash - net of commissions of $98,100 -- -- 437,012 437 1,091,463 -- -- -- 1,091,900

Common stock issued for settlement of accounts payable
and accrued liabilities ..................................... -- -- 79,793 80 219,920 -- -- -- 220,000

Options issued to advisory board and common stock issued
for services ................................................ -- -- 1,035 1 97,901 -- -- -- 97,902

Warrants issued with notes payable .......................... -- -- -- -- 110,170 -- -- -- 110,170

Preferred stock issued for cash, net of commissions of
$473,838 (cash) and $99,168 (non-cash) ...................... 2,226,680 2,226 -- -- 9,110,830 -- -- -- 9,113,056

Preferred stock converted to common stock ................... (1,645,099) (1,645) 1,776,708 1,777 (132) -- -- -- --

Preferred stock issued in exchange for notes payable and
accrued interest of $9,426 .................................. 36,650 37 -- -- 159,389 -- -- -- 159,426

In-the-money conversion feature charges to be amortized ..... -- -- -- -- 1,182,452 (1,182,452) -- -- --

Amortization of in-the-money conversion feature charges ..... -- -- -- -- (1,063,842) 1,063,842 -- -- --

Net loss .................................................... -- -- -- -- -- -- -- (5,634,844) (5,634,844)

Foreign currency translation adjustment ..................... -- -- -- -- -- -- 168,256 -- 168,256
------------ ------------ ------------ ------------ ------------ ------------ ------------ ------------ ------------

Balance - December 31, 2003 ................................. 618,231 $ 618 8,584,068 $ 8,584 $ 37,073,366 $ (118,610) $ 898,756 $(27,657,578) $ 10,205,136
============ ============ ============ ============ ============ ============ ============ ============ ============

See notes to consolidated financial statements.

TETON PETROLEUM COMPANY

Consolidated Statements of Cash Flows

For the Years Ended
December 31,
--------------------
2003 2002
-----------------------
Cash flows from operating activities
Net loss ............................................ $ (5,634,844) $(10,973,923)
------------ ------------
Adjustments to reconcile net loss to net cash used in
operating activities
Depreciation, depletion, and amortization .......... 1,582,513 451,930
Stock based compensation for variable plan warrants -- --
Stock and stock options issued for services and
interest ......................................... 107,128 --
Warrants issued for notes payable extensions ....... 110,170 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 .............................. 462,000 (1,048,608)
Prepaid expenses and other assets ................ (4,247) (57,446)
Inventory ........................................ 54,177 (313,489)
Accounts payable and accrued liabilities ......... 311,901 290,131
------------ ------------
2,623,642 5,805,138
------------ ------------
Net cash used in operating activities ........... (3,011,202) (5,168,785)
------------ ------------

Cash flows from investing activities
Oil and gas properties and equipment expenditures ... (5,392,450) (3,222,349)
Construction in progress ........................... (1,700,696) --
------------ ------------
Net cash used in investing activities ........... (7,093,146) (3,222,349)
------------ ------------

Cash flows from financing activities
Net proceeds from advances under notes payable owed
to affiliates ...................................... 4,470,984 2,178,525
Proceeds from stock subscription .................... 1,939,610 --
Proceeds from issuance of stock, net of $473,838
commissions ........................................ 10,251,924 --
Proceeds from issuance of convertible debentures .... -- 4,143,643
Proceeds from notes payable ......................... 628,750 300,000
Payments on notes payable ........................... (478,750) (894,210)
Issuance of common stock ............................ -- 3,333,460
------------ ------------
Net cash provided by financing activities ....... 16,812,518 9,061,418
------------ ------------

Effect of exchange rates .............................. 168,256 (140,773)
------------ ------------

Net increase in cash .................................. 6,876,426 529,511

Cash - beginning of year .............................. 712,013 182,502
------------ ------------

Cash - end of year .................................... $ 7,588,439 $ 712,013
============ ============

See notes to consolidated financial statements.

Supplemental disclosure of cash flow information

Cash paid for: Interest
----------

2003 $ 18,202
2002 $ 120,008

Supplemental disclosure of non-cash activity:

During the year ended December 31, 2003, the Company had the following
transactions:

128,700 warrants issued with debt and valued at $110,170 were
initially recorded as a discount on the note payable. At December 31,
2003, the full amount of the discount had been amortized as financing
costs.

79,793 shares of common stock were issued for settlement of accounts
payable and accrued liabilities valued at $220,000.

The Company issued 30,000 non-qualified options to advisory board
members valued at $94,702.

The Company issued 1,035 shares of common stock for services valued at
$3,201.

The Company has accrued a liability for $46,968 related to the
obligation to issue 57,420 warrants to a consultant for capital
raising services.

12,000 preferred shares were issued to consultants for services valued
at $52,200 related to capital raising.

Approximately $1,785,000 of capital expenditures for oil and gas
properties were included in accounts payable at December 31, 2003.

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 10,416
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 83,333 warrants also being issued under the same terms of the
Company's private placement offering of convertible debentures.

1,647,881 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 143,678 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 89,167 warrants valued at
$14,250 for a total amount of $281,750 were issued for consulting
services.

41,667 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 1,758,494 shares of stock with $466,771 being paid as a
premium at conversion and recorded as financing costs.

221,198 shares of stock were issued to consultants for services valued
at $607,790.

133,333 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 712,045 shares of stock. The cash
for these subscriptions was paid during the first quarter of 2003.

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 the Russian Federation. Since the
Company's operations are exclusively 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.

During 2002, 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
the Company reflected it's 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, 2003 and 2002, 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
("Payout"). 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.

In September OAO NK RussNeft acquired the shares held by Mediterranean Overseas
Trust and InvestPetrol in Goloil and assumed responsibility for operating the
License. During the transition, the Company subsequently learned in November,
Goloil sold substantially less than its export quota into export markets where
prices are substantially higher, instead selling the production into the
domestic market.

Commencing October 1, RussNeft began selling Goloil's production to a related
party for a fixed price of 2400 rubles per ton (roughly $11 per barrel), a price
substantially below the blended market price Goloil formerly received selling
its production into the export, near abroad and domestic markets. As a
consequence, the Company estimates its revenues after taxes for the quarter were
reduced by approximately $1.44 million. Moreover, since this pricing arrangement
prevailed through the end of the fourth quarter and beyond, the Company has had
to significantly reduce the present value of its reserves effective January 1,
2004. In addition, RussNeft has adjusted the amount of production payment to be
paid to EnergoSoyuz-A ("ESA") to a fixed amount per month which is less than the
50% of oil produced previously agreed to, based on the current price.

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.

Cash and Cash Equivalents
--------------------------

The Company considers all highly liquid instruments purchased with an original
maturity of three months or less to be cash equivalents. The Company continually
monitors its positions with, and the credit quality of, the financial
institutions it invests with. As of the balance sheet date, the Company had no
cash equivalents.

Revenue Recognition
-------------------

The Company recognizes oil sales revenue at the point in time oil quantities
have been delivered to purchasers.

Comprehensive Income
--------------------

Comprehensive income is defined as the change in equity during a period from
transactions and other events from non-owner sources. Comprehensive income is
the total of net income or loss and other comprehensive income or loss. The
effect of foreign currency exchange rates currently is the Company's only item
which constitutes comprehensive income or loss.

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. Currently the Company holds no unproved
properties.

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. 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 had a cogeneration plant under construction at December
31, 2003, the Company's share of which totaled $1,700,696 which has been
excluded from properties subject to depletion until its completion. The Company
did not have any significant development projects, which have been excluded from
depletion at December 31, 2003. Support equipment and other property and
equipment are depreciated over their estimated useful lives.

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.

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 3 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. Goloil may be required to
reimburse the TDA in the form of a success fee if certain events occur by
December 31, 2004, 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. As of March 25, 2004 the
Company has completed and submitted to TDA its feasibility study of the Eguryak
license area. The Company has received $255,000 as of December 31, 2003 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, 2003 and 2002, the Company received $0 under
TDA grants, respectively.

Impairment of Long-Lived Assets
-------------------------------

The Company evaluates its long-lived assets for impairment, in accordance with
the provisions established under Statement of SFAS no. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets", when events or changes in
circumstances indicate that the related carrying amount may not be recoverable.
An impairment is considered to exist if the total estimated future cash flows on
an undiscounted basis is less than the carrying amount of the related assets. An
impairment loss is measured and recorded based on the discounted estimated
future cash flows. Changes in significant assumptions underlying future cash
flow estimates or fair values of assets may have a material effect on the
Company's financial position and results of operations.

Asset Retirement Obligations
----------------------------

During 2003 the Company applied the provisions of SFAS No. 143, "Accounting for
Asset Retirement Obligations." The Company recorded $126,500 as the fair value
of the Company's estimated liability for the retirement of its Russian oil and
gas assets along with a corresponding increase in the carrying value of the
related oil and gas properties as of December 31, 2003, as the effect of
adopting SFAS No. 143 on January 1, 2003 was not material. Had the Company
adopted SFAS No. 143 on January 1, 2002 the net loss to common shareholders
would have been increased by $13,000.

Stock-Based Compensation
------------------------

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 results of operations. 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 stock options issued to employees, officers and
directors under the stock option plan. Had compensation cost for the Company's
options issued to employees, officers and directors been determined based on the
fair value at the grant date for awards consistent with the provisions of SFAS
No. 123, as amended by SFAS No. 124, the Company'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,
---------------------------
2003 2002
------------ ------------

Net loss applicable to common shareholders - as reported $ (8,415,537) $(10,973,923)
Net loss applicable to common shareholders - pro forma $(13,389,678) $(11,945,964)
Basic loss per common share - as reported $ (1.23) $ (3.53)
Basic loss per common share - pro forma $ (1.96) $ (3.84)

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,
--------------------
2003 2002
-----------------------

Approximate risk free rate 4.00% 4.50%
Average expected life 10 years 2 years
Dividend yield -% -%
Volatility 100% 87.20%

Estimated fair value of total options granted $4,974,141 $972,041

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, 2003 and
2002 were approximately 1 U.S. dollar to 29.45 and 31.78, Russian rubles,
respectively. For the years ended 2003 and 2002, the average exchange rate for 1
U.S. dollar was 30.66 and 31.39, 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.

The following table reflects the effects of dilutive securities as of December
31, 2003.

Dilutive effects of stock options 1,578,037
Dilutive effects of warrants 7,389,981
Dilutive effects of convertible preferred shares 2,381,351
----------
Weighted average common shares outstanding including 11,349,369
the effects of dilutive securities

Fair Value of Financial Instruments
-----------------------------------

The carrying amounts of financial instruments including cash, accounts
receivable, sundry receivables, accounts payable, accrued liabilities, notes
payable and convertible debentures approximated fair value as of December 31,
2003 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, 2003 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 2002 consolidated financial statements have been
reclassified to conform to the 2003 presentation.

Recently Issued Accounting Pronouncements
-----------------------------------------

In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity." SFAS No. 150
establishes standards for how an issuer measures certain financial instruments
with characteristics of both liabilities and equity and requires that an issuer
classify a financial instrument within its scope as a liability (or asset in
some circumstances). SFAS No. 150 was effective for financial instruments
entered into or modified after May 31, 2003 and otherwise was effective and
adopted by the Company on July 1, 2003. As the Company has no such instruments,
the adoption of this statement did not have an impact on the Company's
consolidated financial statements. During December 2003, the FASB issued
Interpretation No. 46R, "Consolidation of Variable Interest Entities" ("FIN
46"), which requires the consolidation of certain entities that are determined
to be variable interest entities ("VIE's"). An entity is considered to be a VIE
when either (i) the entity lacks sufficient equity to carry on its principal
operations, (ii) the equity owners of the entity cannot make decisions about the
entity's activities or (iii) the entity's equity neither absorbs losses or
benefits from gains. Teton Petroleum owns no interests in variable interest
entities, and therefore this new interpretation will not affect the Company's
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 (the "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, 2003. 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 2,262,343 barrels of oil through December
31, 2003. The Company also has the obligation to compensate the affiliate for a
minimum of 4,088,000 barrels of oil (1,825,657 barrels remaining at December 31,
2003) over a seven-year period for its investments under the oilfield
development agreement. See Note 10 for a discussion of the changes made to the
production payment being proposed by OAO NK RussNeft, a newly formed Russian
independent oil producer ("RussNeft").

Additionally, the affiliate has net direct loans to Goloil of approximately
$14,839,000, 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, 2003:

Building $ 123,942
Vehicles 178,598
Computers and equipment 30,053
Other equipment 175,707
Furniture and fixtures 27,689
-------------
535,989
Less: Accumulated depreciation (85,148)
-------------
$ 450,841
=============

Note 4 - Oil and Gas Properties
-------------------------------

Goloil License
--------------

The Company holds an interest in the 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
186.8 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 the 186.8 square kilometers of the license. 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 comply
with 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 any
past license requirements.

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 is 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, is the
property of Goloil.

During 2003, Goloil began the construction of a gas-powered electrical
generating plant which will be operational in the first quarter of 2004.

See note 10 for a discussion of a dispute with RussNeft, the operator of Goloil.

Note 5 - Notes Payable
----------------------

During 2003:

The Company received proceeds of $628,750 from the issuance of promissory notes
to three shareholders. In connection with these notes, 128,700 warrants valued
at $110,170 were issued. At December 31, 2003, the full amount of the discount
had been amortized and recorded as a non-cash financing charge. The Company has
recorded the value of these warrants using the Black-Scholes option-pricing
model using the following assumptions: volatility of 73%, a risk-free rate of
3.5%, zero dividend payments, and a life of one year.

The Company paid $478,750 of the promissory notes issued during the year. The
remaining $150,000 along with accrued interest of $9,426 was exchanged for
Teton's 8% convertible preferred shares.

During 2002:

The scheduled 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 10,417 stock purchase warrants, with an
exercise price of $6.00 that expired February 2004, which had 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 143,678 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 83,333 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, 41,667 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
modifications totaled $353,379 and have been recorded as non-cash financing
charges during the year ended December 31, 2002.

Note 6 - Proportionate Share of Liabilities
-------------------------------------------

The proportionate share of accounts payable and accrued liabilities of
$2,590,901 at December 31, 2003 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 by and owed to Goloil owed to an affiliate. These advances are
obligations of Goloil at December 31, 2003 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 interest payable either quarterly or on maturity, maturing
through December 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 extended to future periods. $7,419,409
---------

Less: current portion $(7,419,409)
-------------

Note 7 - Stockholders' Equity
-----------------------------

Changes in Stockholders' Equity during 2003
-------------------------------------------

On March 19, 2003, the stockholders authorized an increase in the Company's
common shares from 100,000,000 to 250,000,000 and authorized 25,000,000
shares of preferred stock for future issuance.

Private Placements of Common Stock
----------------------------------

During the year ended December 31, 2003 the Company received the following
proceeds from the issuance of privately placed common stock:

o $1,091,900 (net of costs of $98,100) from the issuance of 437,012 shares of
common stock. In connection with the private placement, the Company also
issued a warrant for each $3.00 stock investment. The warrants have a term
of two years and an exercise price of $6.00,

o $1,939,610 during the year ended December 31, 2003 related to outstanding
stock subscriptions receivable at December 31, 2002,

o 80,828 common shares valued at $317,902 were issued for (i) settlement of
accounts payable and accrued liabilities of $220,000; and (ii) services
provided by the advisory board of $97,902.

Private Placements of Series A Convertible Preferred Stock
-----------------------------------------------------------

During the year ended December 31, 2003 the Company received the following
proceeds from the issuance of privately placed preferred stock issued at an
offering price of $4.35 per share.

o Proceeds of $9,145,450 (net of cash costs of $473,888 and net of $46,968
related to the obligation to issue warrants for capital raising) from the
issuance of 2,266,680 shares of 8% convertible preferred stock.

o $14,574 from the issuance of 40,000 preferred shares in exchange for a
$150,000 note payable outstanding and accrued interest of $9,426.

We also issued 12,000 preferred shares to a consultant for capital raising
services valued at $52,200.

The preferred shares carry an 8% dividend, payable quarterly commencing January
1, 2004 and are convertible into common stock at a price of $4.35 per share. The
preferred stock is entitled to vote on all matters presented to the Company's
common stockholders, with the number of votes being equal to the number of
underlying common shares. The preferred stock also contains a liquidation
preference of $4.35 per share plus accrued unpaid dividends. The preferred
shares can be redeemed by the Company after one year for $4.35 per share upon
proper notice of redemption being provided by the Company.

In connection with the preferred share private placement for Tranches 1 and 2,
certain placements were entered into when the underlying price of the common
stock to which the preferred shares are convertible into, exceeded $4.35, the
stated conversion rate. As a result of the underlying shares being in-the-money,
the Company was required to compute a beneficial conversion charge, which is
calculated as the difference between the conversion price of $4.35 and the
closing stock price on the effective date of each offering, multiplied by the
total of the related common shares to be issued upon conversion of the preferred
stock. These charges are reflected as a dividend to the preferred shareholders
and are recognized over the period in which the preferred stock first becomes
convertible. For the Tranche 1 shares the charge was immediately recognized as
the shares were immediately convertible into common. For Tranche 2 the shares
could not be converted until a shareholder vote on January 27, 2004 took place
approving the issuance of additional common shares. The calculated beneficial
conversion feature on Tranche 2 was therefore amortized from the effective date
of each issuance through January 27, 2004. This resulted in total beneficial
conversion charges of $ 1,182,452, of which $1,063,842 were recorded during the
fourth quarter of 2003, and $118,610 will be amortized and recorded as preferred
dividends in January of 2004.

The Company also sent each preferred shareholder an inducement offer to convert
their shares of preferred into common shares. If converted within 60 days of
closing, the investors will be entitled to receive (i) dividends payable in
common stock equivalent to one years worth of dividends; and (ii) 2 Class B
Warrants for each $10 invested, exercisable at $6.00 per share.

In connection with the preferred share private placement for Tranche 1,
shareholders converted 1,645,099 of 8% convertible preferred shares to common
stock at a price of $4.35 per share. Common share dividends of 8% for a full
year were paid totaling $546,173 and 1,431,237 warrants were issued valued at
$1,170,678, for a total inducement charge of $1,716,851 recognized as a
preferred dividend during the fourth quarter for those investors which accepted
the inducement offer. The warrants issued were valued using the black-scholes
option pricing model using the following assumptions: volatility of 55%, a
risk-free rate of 1.875%, zero dividend payments, and a life of two years.

In connection with the preferred share private placement for Tranche 2, a common
share dividend of 8% for a full year was paid totaling $157,601 and warrants
were issued valued at $337,805 , for a total inducement charge of $495,406 which
will be recognized as a preferred dividend in the first quarter of 2004,
associated with the preferred stock inducement offer ending on March 27, 2004.
The warrants issued were valued using the black-scholes option pricing model
using the following assumptions: volatility of 55%, a risk-free rate of 1.875%,
zero dividend payments, and a life of two years.

Warrants to Purchase Common Shares
----------------------------------

During 2003, the Company issued 440,140 warrants to entities for their
services directly related to raising capital under private placements. The
Company also issued 128,700 warrants in conjunction with debt valued at
$110,170.

During 2003, the Company issued 1,019,883 warrants in connection with
common stock private placement offerings, with an exercise price of $6.00
that expire December 30, 2004.

Changes in Stockholder Equity during 2002
-----------------------------------------

Private Placements of Common Stock
----------------------------------

During the year ended December 31, 2002 the Company received the following
proceeds from the issuance of privately placed common stock:

o $3,333,460 from the issuance of 1,223,737 shares of common stock. In
connection with the private placement offerings, the Company also issued a
warrant for each $3.00 stock investment. The warrants have a term of two
years and an exercise price of $6.00.

o $605,136 from the issuance of 221,198 common shares issued for consulting
services.

o $23,200 from the issuance of 7,407 common shares for services provided in
2001. The Company 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
at a $3 conversion rate.

The debentures also included warrants to purchase common stock and
have an exercise price of $6 and a term of two years. Each debenture
holder received one warrant for each $.25 (pre-split) 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 $3
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.

Warrants to Purchase Common Shares
----------------------------------

During 2002, the Company issued 133,333 warrants to consultants for
services valued at $215,086. The Company also issued 616,793 to
employees and directors for services performed.

The following table presents the activity for warrants outstanding:

Weighted
Average
Exercise
Shares Price
------------------------

Outstanding - December 31, 2001 544,098 $ 5.28
Granted 4,068,682 5.52
Forfeited/canceled (25,000) 2.04
---------------------------

Outstanding - December 31, 2002 4,587,780 5.52
Granted 3,210,249 2.49
Forfeited/canceled (408,048) 0.30
---------------------------

Outstanding - December 31, 2003 7,389,981 $ 5.63
===========================

The following table presents the composition of warrants outstanding and
exercisable:

Shares Outstanding
--------------------------
Range of Exercise Prices Number Price* Life*
----------------------------------------- ------------ ------------ ---------
$2.72 - $4.80 997,800 $ 0.41 .27
$6.00 - $12.00 6,392,181 5.22 .93
------------ ------------ ------------

Total - December 31, 2003 7,389,981 $ 5.63 1.20
============ ============ ============

*Price and Life reflect the weighted average exercise price and weighted average
remaining contractual life, respectively.

Note 8 - Stock Options
----------------------

At the annual meeting on March 19, 2003, the Company's shareholders approved an
employee stock option plan and authorized 2,083,333 shares of Common Stock for
issuance thereunder. Under the plan, incentive and non-qualified options may be
granted. During the second quarter of 2003, the Company issued 30,000
non-qualified options to outside advisory board members which has been recorded
as compensation expense during the three-months ended June 30, 2003 valued at
$94,701, using the Black-Scholes option-pricing model with the following
assumptions: volatility of 100%, a risk-free rate of 4%, zero dividend payments,
and a life of ten years. The Company also issued 1,448,037 incentive options to
employees, officers and directors valued at $4,571,026 using the Black-Scholes
option-pricing model under the same assumptions described above. In the third
quarter, 100,000 options valued at $308,414 were issued to a director under the
Company Plan.

As of December 31, 2003, 1,478,037 options with an exercise price of $3.48 were
outstanding as well as 100,000 options with an exercise price of $3.71. The
weighted average price and contractual life of both issues were $3.26 and $3.71
and 8.59 and .61 years, respectively.

The following table presents the activity for stock options outstanding:

Shares Outstanding
--------------------------
Range of Exercise Prices Number Price* Life*
----------------------------------------- ------------ ------------ ---------
Outstanding - December 31, 2002 - $ - -
Issued 1,578,037 3.49 9.20
------------ ------------ ------------

Outstanding - December 31, 2003 1,578,037 $ 3.49 9.20
============ ============ ============

*Price and Life reflect the weighted average exercise price and weighted average
remaining contractual life, respectively.

Note 9 - 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 carry-forwards, no provision for
income taxes has been recorded.

The Company has net operating loss carry-forwards for U.S. tax purposes of
approximately $18,500,000, which expire between 2012 and 2023, 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 taxes, value-added taxes ("VAT"), unified
social taxes, transport taxes and property taxes.

The Company had no income tax liabilities for the years ended December 31, 2003.
ZAO Goloil has net operating loss carry-forwards, which are available to offset
future taxable income, which will expire in 2013. The foreign income tax
carry-forwards for Russian tax purposes are limited to a maximum of 30% of
taxable income in any year. As of December 31, 2003, Goloil had $210,662 in
deferred tax assets ($105,331 net to Teton) and $34,906 ($17,453 net to Teton)
in deferred tax liabilities. These amounts can be applied against future income
taxes.

Note 10 - Commitments and Contingencies
---------------------------------------

Contingencies
-------------

Dispute with Current operator of Goloil

In September, RussNeft acquired the shares held by Mediterranean Overseas Trust
and InvestPetrol in Goloil and assumed responsibility for operating the License.
During the fourth quarter, the Company subsequently learned, Goloil sold
substantially less than its export quota into export markets where prices are
substantially higher, instead selling the production into the domestic market.

Commencing October 1, RussNeft began selling Goloil's production to a related
party of RussNeft (RussTrade) for a fixed price of 2,400 rubles per ton (roughly
$11 per barrel), a price substantially below the blended market price Goloil
formerly received selling its production into the export, near abroad and
domestic markets. As a consequence, the Company estimates its revenues after
taxes for the quarter were reduced by approximately $1.44 million. Moreover,
since this pricing arrangement prevailed through the end of the fourth quarter
and beyond, the Company has had to significantly reduce the present value of its
reserves effective January 1, 2004. In addition, RussNeft has adjusted the
amount of production payment to be paid to EnergoSoyuz-A ("ESA") to a fixed
amount per month which is less than the 50% of oil produced previously agreed
to, based on the current price.

Taxation
--------

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, 2003.

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.

Environmental
-------------

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.

Political
---------

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
-----------

Mr. Howard Cooper, Chairman, signed an agreement on May 1, 2002. The employment
agreement is for a three-year term, whereby Mr. Cooper's salary is $13,333 per
month. Under the terms of the agreement, Mr. Cooper is entitled to 24 months of
severance pay, payable in monthly installments over 24 months, from the date of
termination. The Company may discontinue the severance payments if Mr. Cooper
violates the confidentiality, noncompetition, or nonsolicitation provisions of
his employment agreement.

Mr. Karl Arleth, President and Chief Executive Officer, signed an agreement on
May 1, 2003. The employment agreement is for a three-year term, with a salary of
$10,000 per month. Under the terms of the agreement, Mr. Arleth is entitled to
24 months severance pay in the event of change of position or control of the
company.

Ms. Anya Cooper, Secretary, signed an agreement on May 1, 2002. The employment
agreement is for a three-year term, whereby Ms. Cooper's salary is $6,500 per
month. Under the terms of the agreement, Ms. Cooper is entitled to 12 months of
severance pay, payable in monthly installments over 12 months from the date of
termination. The Company may discontinue the severance payments if Ms. Cooper
violates the confidentiality provision of her employment agreement.

Note 11 - 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,
--------------------
2003 2002
-----------------------

Property acquisition costs............................. $ -- $ --

Construction in progress .............................. 1,700,696
Development costs ..................................... 5,207,931 4,150,742
---------- ----------

Total .......................................... $6,908,627 $4,150,742
========== ==========

The following reflects the Company's capitalized costs associated with oil and
gas producing activities:

For the Years Ended
December 31,
----------------------------
2003 2002
------------ ------------

Property acquisition costs .......................... $ 595,558 $ 595,558
Construction in progress 1,700,696
Development costs ................................... 10,808,813 4,830,421
------------ ------------
13,105,067 5,425,979
Accumulated depreciation, depletion, amortization and
valuation allowances ............................... (2,064,585) (529,671)
------------ ------------
Net capitalized costs ............................... $ 11,040,482 $ 4,896,308
============ ============

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,
----------------------------
2003 2002
------------ ------------

Oil and gas sales $ 11,437,802 $ 6,923,320
Oil and gas production (2,020,447) (1,218,411)
Transportation and marketing (807,266) (611,956)
Export duties (1,492,999) (910,936)

Taxes other than income taxes (5,864,920) (3,537,990)
Depletion, depreciation and amortization (1,534,914) (451,930)
------------ ------------

Results of operations from oil and gas producing
activities $ (282,744) $ 192,097
============ ===========

Reserves (Unaudited) - Base Case
--------------------------------

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.

See Note 10 to the financial statements for a full discussion of the dispute
with RussNeft. As the outcome of this dispute cannot be predicted at this time,
the Company has prepared two separate proved oil reserve cases: the "Base Case
SEC reserves and Cash Flow Projections" and the "Alternate Case". The Base Case
assumes that the Company is not successful in it's dispute with RussNeft,
accordingly, the price received for oil is set at 2,400 rubles per ton ($11 per
barrel) and the production payment is deducted assuming 19 million rubles per
month ($645,000 per month less VAT). The Alternate Case assumes that the Company
is successful in the dispute and that RussNeft and Goloil would honor all
pre-existing agreements. In the Base Case, future cash flows are substantially
less than in the Alternate Case, however oil reserves quantities are greater as
a result of payout being delayed and how the production payment is being
calculated. Management has elected to report the lower, alternate case reserves
as it's oil reserves.

For the Years Ended
December 31,
--------------------------
2003 2002
----------- -----------

Proved reserves (bbls), beginning of period ........ 13,264,000 40,174,000

Production ......................................... (632,000) (471,000)

Extension of reservoir ............................. -- 2,000,000

Revisions of previous estimates .................... (4,370,000) (28,439,000)
----------- -----------

Proved reserves (bbls), end of period .............. 8,262,000 13,264,000
=========== ===========

Proved developed reserves (bbls, beginning of period 4,567,000 5,493,000
=========== ===========

Proved developed reserves (bbls), end of period .... 3,816,000 4,567,000
=========== ===========

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 summarizes the Base Case standardized measure and 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 assuming the Company is not successful in it's dispute with
RussNeft.

For the Years Ended
December 31,
2003 2002
------------- -------------

Future cash inflows ...................................... $ 114,992,000 $ 230,581,000

Future production costs .................................. (80,812,000) (151,167,000)

Future development costs ................................. (14,595,000) (18,556,000)

Future income tax expense ................................ (7,360,000) (16,365,000)
------------- -------------

Future net cash flows (undiscounted) ..................... 12,225,000 44,493,000
Annual discount of 10% for estimated timing of cash
flows ................................................... (6,232,000) (19,069,000)
------------- -------------

Standardized measure of future net discounted cash flows $ 5,993,000 $ 25,424,000
============= =============

Changes in Standardized Measure Base Case (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,
------------------------------
2003 2002
------------- -------------

Standardized measure, beginning of period, ....... $ 25,424,000 $ 40,362,000
Net changes in prices and production costs ....... (11,483,000) 189,975,000
Future development costs ......................... (3,098,000) 22,344,000
Revisions of previous quantity estimates ......... (11,806,000 (274,605,000)
Extension of reservoir ........................... -- 19,867,000
Accretion of discount ............................ 2,542,000 4,036,000
Changes in income taxes, net ..................... 4,414,000 23,445,000
------------- -------------

Standardized measure, end of period, 2003 and 2002 $ 5,993,000 $ 25,424,000
============= =============

Reserves (Unaudited) - Alternate Case
--------------------------------------

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 and assuming that the Company
is successful in resolving its dispute with RussNeft, the Alternate Case.

For the Years Ended
December 31,
-----------------------------------
2003 2002
------------- -------------

Future cash inflows ...................................... $ 175,631,000 $ 230,581,000

Future production costs .................................. (104,257,000) (151,167,000)

Future development costs ................................. (14,595,000) (18,556,000)

Future income tax expense ................................ (15,567,000) (16,365,000)
------------- -------------
Future net cash flows (undiscounted) ..................... 41,212,000 44,493,000
Annual discount of 10% for estimated timing of cash
flows ................................................... (17,560,000) (19,069,000)
------------- -------------

Standardized measure of future net discounted cash flows $ 23,652,000 $ 25,424,000
============= =============

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,
------------------------------
2003 2002
------------- -------------
Standardized measure, beginning of period, December 31,
2002 and 2001 ........................................ $ 25,424,000 40,362,000
Net changes in prices and production costs ............ 50,949,000 189,975,000
Future development costs .............................. (3,098,000) 22,344,000
Revisions of previous quantity estimates .............. (52,623,000) (274,605,000)
Extension of reservoir ................................ -- 19,867,000
Accretion of discount ................................. 2,542,000 4,036,000
Changes in income taxes, net .......................... 458,000 23,445,000
------------- -------------

Standardized measure, end of period, 2003 and 2002 .... $ 23,652,000 $ 25,424,000
============= =============

Note 12 - Fourth Quarter Adjustments

The following significant adjustments were recorded by the Company during the
fourth quarter of 2003:

Depletion, amortization and amortization ............. $ 919,744
Exploration expenses ................................. 275,416
Imputed preferred stock dividends for
inducements and beneficial conversion charges ....... 2,762,137
----------
Total impact on loss applicable to common stockholders $3,957,297
==========

As described in Note 10 to these financial statements, the operations of Goloil
have had some significant management changes that have affected the operating
results of Goloil during the fourth quarter. The effects of these changes can be
seen in the accompanying table reflecting the fourth quarter results of
operations.

Fourth Quarter
2003
------------------
------------------
Sales, Barrels 150,938
Average Daily Sales, Barrels 1,654
Average Selling Price, $/barrel $15.45
Revenues $2,332,464

Costs of Sales and Expenses, excl.
DD&A
Production Costs 563,590
Transportation & Marketing 6,061
Taxes other than Income taxes 1,700,920
Export Duties -
-

Results from Goloil Operations,
before DD&A 61,889
Less General & Administrative
Expense, Goloil 188,229
-------
Goloil operating (loss) income
before DD&A (126,340)

Depreciation, Depletion & 919,744
-------
Amortization, Goloil

Operating loss, Goloil (1,046,084)

General & Administrative Expense,
Teton 1,244,063
---------

Operating Loss, Teton $(2,290,147)
============

Item 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.

None.

ITEM 8A. CONTROLS AND PROCEDURES

As of December 31, 2003, an evaluation was performed by our Chief Executive
Officer and 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 not completely effective as of December
31, 2003.

In connection with the audit of the year ended December 31, 2003, there were no
"reportable events" except that the Company's auditors reported to the
Registrant's Audit Committee that the auditors' considered two matters involving
internal controls and their operation to be material weaknesses. Specifically,
in connection with its audit of the consolidated financial statements of
Registrant and its subsidiary for the year ended December 31, 2003, the auditors
reported that a material weakness existed related to the lack of formalized
policies and procedures to permit timely recording and processing of financial
information to permit the timely preparation of financial statements and
recommended implementation of formal policies and procedures and significantly
enhancing the accounting staff. The Registrant has since December 31, 2003
addressed this concern and has hired a controller and added a new chief
financial officer, and added formalized procedures to permit timely recording
and processing of financial information. The second matter related to oversight
of its Russian subsidiary and reporting of its financial results on a timely
basis which impact and represents the bulk of the company's operating results.
The Registrant continues to work with management and its new partner OAO NK
RussNeft in an effort to improve financial reporting in this area.

PART III

Item 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(A) OF THE EXCHANGE ACT.

DIRECTORS AND EXECUTIVE OFFICERS

Directors, executive officers, and significant employees of Teton, their
respective ages and positions with Teton are as follows:

Name Age Position
---- --- --------

H. Howard Cooper 47 Chairman and Founder, Director
Karl F. Arleth 55 President and CEO, Director
Igor Effimoff 58 Chief Operating Officer
John I. Mahar 50 Executive VP of Finance
James J. Woodcock 65 Director
Thomas F. Conroy 65 Director
John T. Connor, Jr. 63 Director
Patrick A. Quinn 50 Chief Financial Officer
Ilia Gurevich 40 Controller

H. HOWARD COOPER, has been our chairman and founder since 1996. Mr. Cooper was
our president and CEO from 1996 until May 2003. 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.

KARL F. ARLETH, has been our president and CEO since May 2003 and our director
since 2002. Mr. Arleth was 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 to 1996 Mr. Arleth was President of Amoco Poland
Ltd. in Warsaw, Poland.

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, was our chief financial officer from March 2002, until May
2003 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.

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.

JOHN T. CONNOR, Jr. became a director in 2003 and chairs the Board's audit
committee. He is the Founder and Portfolio Manager of the Third Millennium
Russia Fund, a US based mutual fund specializing in the equities of Russian
public companies. A former attorney at Cravath, Swaine & Moore in New York City,
he has been a partner in leading law firms in New York, Washington and New
Jersey. Mr. Connor is a member of the Council on Foreign Relations and the
American Law Institute.

JOHN I. MAHAR. Since 1995, Mr. Mahar has been a Managing Director of Gladstone
Capital, LLC, an oil-and-gas financial advisory firm based in New York he
co-founded. Prior to forming Gladstone Capital, Mr. Mahar worked in the New York
office of Schroder Capital Management International, Inc. where he was
responsible for the firm's domestic U.S. investment operations. He started his
career at the Federal Reserve Bank of New York, where he served as an analyst
and foreign exchange trader. He has a B.A. from Union College ('76) and an MBA
from the Simon School of Business at the University of Rochester ('78).

ILIA GUREVICH. Mr. Gurevich attended both University of Saratov and University
of 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.

PATRICK A. QUINN, CPA, CVA. Mr. Quinn joined Teton in February, 2004 to serve as
the Company's Chief Financial Officer on a part-time basis. For the past fifteen
years Mr. Quinn has been the CEO of Quinn & Associates, P.C. (Q&A). Q&A provides
accounting, tax and auditing services primarily to the oil and gas industry. Q&A
has provided accounting and tax services to Teton since its inception. Mr. Quinn
has extensive experience in international oil and gas operations including
serving as the Controller of Hamilton Oil Corporation, which was the first
company to produce oil in the U.K. sector of the North Sea.

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 currently consists of two directors
John Connor and James J. Woodcock. Mr. Woodcock is an independent director based
on Rule 4200(a)(15) of the NASD's listing standards. The Nominating Committee is
made up of Mr. Woodcock and Mr. Conroy.

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 met three times by teleconference
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 met more than once by teleconference during 2003

For the fiscal year ended 2003, 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 2003, 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, 2003 and 2002 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. Please see the appendices for a copy.

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,
2003 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. [to be updated by Teton]

The following table sets forth information concerning the compensation received
by Mr. Howard Cooper, the Chairman of Teton, and Mr. Karl Arleth who served as
its president and chief executive officer during 2003:

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 2003 160,000 0 0 0 603,289 0 0
Cooper, 2002 160,000 50,000 0 0 375,000 0 0
President 2001 210,000 0 0 0 0 0 0
Karl F. 2003 85,000 0 0 0 410,338 0 0
Arleth CEO

1. In consideration of services rendered, Mr. Cooper received 603,289 warrants
during 2003 to purchase shares of our common stock at an exercise price of
$3.48 which was the market price of our common stock on the date of the
grant.

2. In consideration of services rendered, Mr. Arleth received 410,338 warrants
during 2003 to purchase shares of our common stock at an exercise price of
$3.48 which was the market price of our common stock on the date of the
grant.

Stock Options

Options/SARs Grants During Last Fiscal Year

The following table provides information related to options granted to our
named executive officers during the fiscal year ended December 31, 2003.

% of
Total
Number of Options
Securities Granted
Underlying in Exercise
Options Fiscal Price Per Expiration
Name Granted 2003 (1) Share Date
-------------- ---------- ------------- ------------ --------------

Howard Cooper 603,289 38.2% $3.48 04/08/13
Karl F. Arleth 410,338 26.0% $3.48 04/08/13
Jim Woodcock 210,148 13.3% $3.48 04/08/13
John Connor 100,000 6.3% $3.71 08/03/13
Igor Effimoff 89,815 5.7% $3.48 04/08/13
John Mahar 83,333 5.3% $3.48 04/08/13
Tom Conroy 28,658 1.8% $3.48 04/08/13

(1) The exercise price of the stock options was based on the fair market value
of the stock on the day of the grant.

Aggregated Option Exercises in Last Fiscal Year and Fiscal Year-End Option Value

There were no options exercised during 2003.

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 pays it's outside Director's an annual retainer of $26,000, payable
quarterly. In addition, at 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 will replace 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 January 23, 2004, 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 1,214,667 (1) 12.6%
1600 Broadway, Suite 2400
Denver, Colorado 80202-4921

Karl Arleth 608,334 (3) 7.3%
P.O. Box 23507
0467 Lariat Loop
Silverthorne, CO 80498

James J. Woodcock 608,334 (2) 6.7%
2404 Commerce Drive
Midland, TX 79702

John Connor 467,108 (8) 5.3%
1600 Broadway, Suite 2400
Denver, Colorado 80202-4921

Igor Effimoff 92,101 (4) 1.1%
13134 Hermitage Lane
Houston, TX 77079

John Mahar 83,334 (5) 1.0%
7 West 73rd St.
New York, NY 10023

Thomas F. Conroy 83,334 (6) 1.0%
3825 S. Colorado Blvd.
Denver, CO 80110

Ilia Gurevich 34,770 (7) 0.4%
1804 South Ironton Street
Aurora, CO 80012

All executive officers and
Directors as a group (7 persons) 3,193,982 28.19%

(1) Includes (i) 145,857 shares of common stock, (ii) 465,521 shares underlying
warrants and (iii) 603,289 shares underlying warrants exercisable at $3.48
per share.

(2) Includes (i) 100,963 shares of common stock, (ii) 297,223 shares underlying
warrants and (iii) 210,148 shares underlying warrants exercisable at $3.48
per share.

(3) Includes (i) 75,772 shares of common stock, (ii) 197,995 shares underlying
warrants and (iii) 410,339 shares underlying warrants exercisable at $3.48
per share.

(4) Includes (i) 89,815 shares underlying warrants exercisable at $3.48 per
share, (ii) 1,905 shares underlying Series A Convertible Preferred Stock,
and (iii) 381 shares underlying Class B Common Stock Purchase Warrants.

(5) Represents 83,334 shares of underlying warrants exercisable at $3.48 per
share.

(6) Includes (i) 15,972 shares of common stock, (ii) 38,704 shares underlying
warrants and (iii) 28,658 shares underlying warrants exercisable at $3.48
per share.

(7) Represents 24,456 shares of underlying warrants exercisable at $3.48 per
share

(8) Includes (i) 183,554 shares of common stock owned indirectly, (ii) 183,554
shares of common stock underlying warrants, which owned indirectly, and
(iii)100,000 shares of common stock underlying options exercisable at $3.71
per share.

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. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

Audit and Non-Audit Fees

Aggregate fees for professional services rendered for the Company by Ehrhardt
Keefe Steiner & Hottman P.C. as of or for the two fiscal years ended December
31, 2003 are set forth below:

Fiscal Fiscal
Year Year
2003 2002
----------- -----------

Audit Fees $ 141,917 $ 142,296
Audit-Related Fees 51,047 33,778
Tax Fees 6,500 12,805
---------- ----------
Total $ 199,464 $ 188,879
=========== ===========

Audit Fees

Aggregate fees for professional services rendered by Ehrhardt Keefe Steiner
& Hottmen P.C. in connection with its audit of our consolidated financial
statements for the fiscal years 2003 and 2002 and the quarterly reviews of our
financial statements included in Forms 10-QSB.

Audit-Related Fees

These were primarily related to SB-2 and SB-2/A filings for the registration of
our stock, assistance with the AMEX application process, and reviews and
discussions regarding accounting treatment of debt and equity transactions.

Tax Fees

These were related to tax compliance and related tax services.

Ehrhardt Keefe Steiner & Hottman P.C. rendered no professional services to us in
connection with the design and implementation of financial information systems
in fiscal year 2003 or 2002.

Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit
Services of Independent Auditors

The Audit Committee pre-approves all audit and non-audit services provided by
the independent auditors prior to the engagement of the independent auditors
with respect to such services. The Chairman of the Audit Committee has been
delegated the authority by the Committee to pre-approve interim services by the
independent auditors other than the annual exam. The Chairman must report all
such pre-approvals to the entire Audit Committee at the next committee meeting.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, 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 Form 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.

31.1 Certification by Chief Executive Officer and Chief Financial Officer
pursuant to Sarbanes-Oxley Section 302.

32.1 Certification by Chief Executive Officer and Chief Financial Officer
pursuant to 18 U.S. C. Section 1350

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 did not file any reports on Form 8-K during our fourth quarter of 2003.

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.

Signature Title Date

/s/ H. Howard Cooper Chairman and Founder April 21, 2004
---------------------------------
H. Howard Cooper

/s/ Karl Arleth President and CEO April 21, 2004
---------------------------------
Karl Arleth

/s/ Thomas F. Conroy Director April 21, 2004
---------------------------------
Thomas F. Conroy

/s/ James J. Woodcock Director April 21, 2004
---------------------------------
James J. Woodcock

/s/ John Connor Director April 21, 2004
---------------------------------
John Connor

/s/ Patrick A. Quinn Chief Financial Officer April 21, 2004
---------------------------------
Patrick A. Quinn