SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                                   FORM 10-KSB
(Mark One)

              (X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                       THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended January 31, 2002
                                       OR
( )   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
                              EXCHANGE ACT OF 1934

Commission File No. 0-33259

                              ENERGAS RESOURCES, INC.
                              -----------------------
                   (Name of Small Business Issuer in its charter)

                Delaware                                    73-1620724
         ------------------------                      --------------------
         (State of incorporation)                        (IRS Employer
                                                       Identification No.)
      800 Northeast 63rd Street
       Oklahoma City, Oklahoma                                   73105
   (Address of Principal Executive Office)                     Zip Code

Registrant's telephone number, including Area Code: (405)-879-1752 Securities
registered pursuant to Section 12(b) of the Act: None Securities registered
pursuant to Section 12(g) of the Act:

                                  Common Stock
                                (Title of Class)

Check whether the Registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 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.
                                        X
                                     YES 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  the  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 Company's revenues during the year ended January 31, 2002 were $136,014.

The aggregate market value of the voting stock held by non-affiliates of the
Company, (16,112,315 shares) based upon the average bid and asked prices of the
Company's common stock on November 30, 2002 was approximately $1,028,000.

Documents incorporated by reference:      None

As of November 30, 2002 the Company had 26,143,001 issued and outstanding shares
of common stock.

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             CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING NFORMATION

         This report includes "forward-looking statements". All statements other
than statements of historical facts included in this Registration Statement,
regarding the Company's financial position, reserve quantities and net present
values, business strategy, plans and objectives of management of the Company for
future operations and capital expenditures, are forward-looking statements.
Although the Company believes that the expectations reflected in the
forward-looking statements and the assumptions upon which such forward-looking
statements are based are reasonable, it can give no assurance that such
expectations and assumptions will prove to have been correct. Reserve estimates
are generally different from the quantities of oil and natural gas that are
ultimately recovered.



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                                    GLOSSARY

         The following terms are used throughout this report:

         BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, usually
used herein in reference to crude oil or other liquid hydrocarbons.

         BOE. Equivalent barrels of oil, using the ratio of six Mcf of natural
gas to one Bbl of crude oil, condensate or natural gas liquids.

         BTU. A British thermal unit which is the amount of heat required to
raise the temperature of one avoirdupois pound of pure water form 58.5 degrees
to 59.5 degrees Fahrenheit under standard conditions.

         DEVELOPED ACREAGE. The number of acres which are allocated or
assignable to producing wells or wells capable of production.

         DEVELOPMENT WELL. A well drilled as an additional well to the same
reservoir as other producing wells on a Lease, or drilled on an offset Lease not
more than one location away from a well producing from the same reservoir.

         EXPLORATORY WELL. A well drilled in search of a new undiscovered pool
of oil or gas, or to extend the known limits of a field under development.

         GROSS ACRES OR WELLS. A well or acre in which a working interest is
owned. The number of gross wells is the total number of wells in which a working
interest is owned.

         LEASE. Full or partial interests in an oil and gas lease, authorizing
the owner thereof to drill for, reduce to possession and produce oil and gas
upon payment of rentals, bonuses and/or royalties. Oil and gas leases are
generally acquired from private landowners and federal and state governments.
The term of an oil and gas lease typically ranges from three to ten years and
requires annual lease rental payments of $1.00 to $2.00 per acre. If a producing
oil or gas well is drilled on the lease prior to the expiration of the lease,
the lease will generally remain in effect until the oil or gas production from
the well ends. The Company is required to pay the owner of the leased property a
royalty which is usually between 12.5% and 16.6% of the gross amount received
from the sale of the oil or gas produced from the well.

         MCF. One thousand cubic feet. Expressed, where gas sales contracts are
in effect, in terms of contractual temperature and pressure bases and, where
contracts are nonexistent, at 60 degrees Fahrenheit and 14.65 pounds per square
inch absolute.

         MMBTU. One million Btu on a saturated basis.


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        MMCF. One million cubic feet. Expressed, where gas sales contracts are
in effect, in terms of contractual temperature and pressure bases and, where
contracts are nonexistent, at 60 degrees Fahrenheit and 14.65 pounds per square
inch absolute.

         NET ACRES OR WELLS. A net well or acre is deemed to exist when the sum
of fractional ownership working interests in gross wells or acres equals one.
The number of net wells or acres is the sum of the fractional working interests
owned in gross wells or acres expressed as whole numbers and fractions.

         OPERATING COSTS. The expenses of producing oil or gas from a formation,
consisting of the costs incurred to operate and maintain wells and related
equipment and facilities, including labor costs, repair and maintenance,
supplies, insurance, production, severance and other production excise taxes.

         PRODUCING PROPERTY. A property (or interest therein) producing oil or
gas in commercial quantities or that is shut-in but capable of producing oil or
gas in commercial quantities, to which Producing Reserves have been assigned.
Interests in a property may include Working Interests, production payments,
Royalty Interests and other non-working interests.

         PRODUCING RESERVES. Proved Developed Reserves expected to be produced
from existing completion intervals open for production in existing wells.

         PROSPECT. An area in which a party owns or intends to acquire one or
more oil and gas interests, which is geographically defined on the basis of
geological data and which is reasonably anticipated to contain at least one
reservoir of oil, gas or other hydrocarbons.

         PROVED DEVELOPED RESERVES. Proved developed oil and gas reserves are
reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. Additional oil and gas expected to be
obtained through the application of fluid injection or other improved recovery
techniques for supplementing the natural forces and mechanisms of primary
recovery may be included as "proved developed reserves" only after testing by a
pilot project or after the operation of an installed program has confirmed
through production response that increased recovery will be achieved.

         PROVED RESERVES. 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, i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.

    (i) Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation testing. The area of a
reservoir considered proved includes (a) that portion delineated by drilling and
defined by gas-oil and/or oil-water contacts, if any; and (b) the immediately
adjoining portions not yet drilled, but which can be reasonably judged as

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economically productive on the basis of available geological and engineering
data. In the absence of information on fluid contacts, the lowest known
structural occurrence of hydrocarbons controls the lower proved limit of the
reservoir.

    (ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.

      (iii) Estimates of proved reserves do not include the following: (a) oil
that may become available from known reservoirs but is classified separately as
"indicated additional reserves", (b) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (c)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (d) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.

         PROVED UNDEVELOPED RESERVES. Proved undeveloped oil and gas reserves
are reserves that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is required
for recompletion. Reserves on undrilled acreage are limited to those drilling
units offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of production from
the existing productive formation. Proved undeveloped reserves are not
attributable to any acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques have been
proved effective by actual tests in the area and in the same reservoir.

         ROYALTY INTEREST. An interest in an oil and gas property entitling the
owner to a share of oil and gas production free of Operating Costs.

         UNDEVELOPED ACREAGE. Lease acres on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of oil and gas regardless of whether or not such acreage contains
proved reserves. Undeveloped acreage should not be confused with undrilled
acreage which is "Held by Production" under the terms of a lease.

         WORKING INTEREST. The operating interest under a Lease which gives the
owner the right to drill, produce and conduct operating activities on the
property and a share of production, subject to all Royalty Interests and other
burdens and to all costs of exploration, development and operations and all
risks in connection therewith.



<PAGE>




ITEM 1. DESCRIPTION OF BUSINESS Energas Resources, Inc. and its wholly-owned
subsidiaries (the "Company") is a fully operational independent oil and gas
exploration and production company. The Company was initially incorporated under
the laws of British Columbia, Canada on November 2, 1989 and on August 20, 2001
the Company became domesticated and incorporated in Delaware. The Company's oil
and gas operations have consisted primarily of drilling Development Wells and
related operations.

            The Company conducts its oil and gas exploration and production
activities through its wholly-owned subsidiary, A.T. Gas Gathering Systems, Inc.

      As of August 31, 2002 the Company owned interests in six Gross (2.395 Net)
Wells, all of which were operated by the Company.

      As of August 31, 2002 the Company was pursuing development drilling and,
to a lesser extent, exploration drilling in the Arkoma Basin in southeastern
Oklahoma and western Arkansas; and the Powder River Basin in Wyoming. The
Company plans to engage in limited drilling activities, which will be primarily
dependent upon available financial resources to fund additional drilling
activities.

      The Company owns and operates a natural gas gathering system that serves
the wells operated by the Company for delivery to a mainline transmission
system. This system is located in Atoka County, Oklahoma and consists of four
miles of pipeline and is connected to four wells that supply natural gas.

      With the exception of the Company's natural gas gathering system, all of
the Company's oil and gas properties are leased.

            The Company's corporate offices are located at 800 Northeast 63rd
Street, Third Floor, Oklahoma City, Oklahoma 73105 and its telephone number is
(405) 879-1752.

PRINCIPAL AREAS OF OPERATION

            The Company principally operates in two geological provinces: (i)
the Arkoma Basin and (ii) the Powder River Basin. Most wells in the Arkoma Basin
produce from depths that range from 2,000 to 18,000 feet, while most wells in
the Powder River Basin produce from depths that range from 4,000 to 13,000 feet.
The Company has most recently concentrated its exploration and development
activities on its oil-producing properties in the Powder River Basin in Wyoming.
In Oklahoma, the Company's exploration activities, while more limited, are
focused on natural gas exploration and development.

            ARKOMA BASIN. The Arkoma Basin is a major gas producing area in the
Mid-Continent region of the United States. It is a crescent-shaped basin, 250
miles long and 20 to 50 miles wide, straddling the Arkansas-Oklahoma border and
encompassing approximately 9,000 square miles. As a result of uplifting of the

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Ouachita Mountains, this Basin contains complex overthrust zones. This Basin is
a dry natural gas region, with most producing wells ranging from 5,000 to 10,000
feet in depth. However, this Basin has recently undergone a resurgence in
drilling activity at depths ranging from 10,000 to 18,000 feet due to a better
understanding of the complex geology of the area, as well as improved access to
natural gas markets. The most significant recent natural gas discoveries
occurred in 1988 in the Arbuckle/Ouachita Overthrust Trend near Wilburton,
Oklahoma. At January 31, 2002, approximately 93% of the Company's Proved
Developed Reserves on a BOE basis were attributable to the Arkoma Basin.

      In fiscal 1999 and 2000 the Company drilled four wells on Prospects in the
Arkoma Basin, all of which were abandoned as non-commercial wells.

      In November 2001 the Company sold one gas well which was located in an
area known as the Lake Wells Prospect.

      As of August 31, 2002 the Company had four producing gas wells in the
Arkoma Basin.

            POWDER RIVER BASIN. The Powder River Basin is located in
northeastern Wyoming and is a major producing area of coal bed methane and crude
oil. The major oil objectives are the lower creataceous sands that are
stratigraphically trapped at depths of 4,000 to 13,000 feet. Individual field
six ranges from 1 to 100 million barrels of crude oil. In the past 20 years,
four fileds have been discovered with individual potentials of 10 to 30 million
barrels of crude oil. The Company's focus in the Powder River Basin has been
limited to the exploration and production of crude oil. At January 31, 2002,
approximately 7% of the Company's Proved Developed Reserves on a BOE basis were
attributable to the Powder River Basin.

      The Company's Leases in the Powder River Basin cover shallow, medium and
deep oil prospects that are in various stages of development and will be drilled
in an orderly manner as crude oil prices justify and available capital resources
permit. As of August 31, 2002, the Company was developing Prospects for future
drilling.

         The Company's oil and gas production and Reserves in the Powder River
Basin are attributable to two wells, the Finley #1 and Finley #2, drilled on the
Rusty Creek Prospect in Niobrara County, Wyoming. Subsequent to July 31, 2001
the Company performed a workover on these two wells at a cost to the Company of
approximately $17,000. In March 2000 the Company drilled a third well on this
prospect. This well was not productive of oil or gas in commercial quantities.
The Company's cost for the drilling of the well was approximately $32,000. The
Company does not intend to drill any additional wells on this prospect. As of
August 31, 2002 the Company's two wells in the Powder River Basin were producing
approximately eleven barrels of crude oil per day.

         PROSPECT ORIGINATION. The Company evaluates undeveloped oil and gas
prospects and participates in drilling activities on those prospects which in
the opinion of management are favorable for the production of oil or gas. If,
through its review, a geographical area indicates geological and economic
potential, the Company attempts to acquire Leases or other interests in the area
and assemble a Prospect. The Company normally sells portions of its leasehold
interests in a Prospect to unrelated third parties, thus sharing risks and

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rewards of the exploration and development of the Prospect with the joint owners
pursuant to an operating agreement. One or more Exploratory Wells may be drilled
on a Prospect, and if the results indicate the presence of sufficient oil and
gas reserves, additional Development Wells may be drilled on the Prospect. The
Company typically seeks potential joint venture partners for development of its
Prospects.

         As of August 31, 2002, the Company had interests in six wells, all of
which were operated by the Company. At August 31, 2002, the Company owned 29,304
Gross (26,479 Net) Acres of oil and gas leasehold interests. This acreage
consists of shallow, medium, and deep Prospects, which are in various stages of
pre-drilling development and will be developed or further developed in an
orderly manner.

NATURAL GAS GATHERING SYSTEM

         The Company owns a pipeline gathering system that serves the wells
operated by the Company in Atoka County, Oklahoma. The gathering system has a
design capacity of 8,000,000 cubic feet per day. The pipeline system was placed
in service and received the first delivery of natural gas in November 1988. The
gathering system is operated by an affiliate of the Company, Energas Pipeline
Company that is owned by George G. Shaw, an executive officer and a Director of
the Company. The natural gas is gathered under a five-year contract (with annual
one-year renewals) and is currently purchased by Duke Energy Field Services,
Inc. The Company, as opposed to Energas Pipeline Company, is responsible for all
costs of operating the gathering system. Energas Pipeline Company purchases the
produced natural gas at the wellhead and then resells the gathered gas. For its
gathering services, Energas Pipeline Company receives and retains a gathering
fee and the differential between the price paid for the natural gas at the
wellhead and the price paid by Duke Energy Field Services, Inc.

      During the years ended January 31, 2002 and 2001:

o    Energas Pipeline Company  received $13,765 and $12,466,  respectively,  for
     its gathering services,

o    the Company received revenues of $15,542 and $14,792 respectively, from its
     gathering system, and

o    the  Company   incurred   direct   pipeline  costs  of  $3,292  and  $3,283
     respectively.

         During the year ended January 31, 2002, natural gas deliveries
throughout the pipeline system totaled 94,443 MMBtu, compared to 90,377 MMBtu in
the year ended January 31, 2001, a 4% increase.

         The pipeline gathering system consists approximately of five miles of
pipe. The pipeline system receives natural gas from the Company's four wells in
Atoka County, Oklahoma. Natural gas competes with other forms of energy
available to end-users, including electricity, coal and fuel oils. The primary
competitive factor is price. Changes in the availability or price of natural gas
and other forms of energy, the level of business activity, conservation,
legislation and governmental regulations, the capability to convert to
alternative fuels, and other factors, including weather, affect the demand for

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natural gas in the areas served by the gathering system. The Company does not
gather or transport natural gas other than by means of its gathering system.

NATURAL GAS UTILITY

         In November 2000 the Company entered into an agreement to acquire First
Natural Gas, Inc., ("FNG") for $600,000. The Company was not able to pay the
purchase price for FNG and the acquisition was terminated.

GOVERNMENT REGULATION

         GENERAL. Numerous departments and agencies, federal, state and local,
issue rules and regulations binding on the oil and gas industry, some of which
carry substantial penalties for failure to comply. The regulatory burden on the
oil and gas industry increases the cost of doing business and, consequently,
affects profitability of operations.

     EXPLORATION AND PRODUCTION. The Company's operations are subject to various
types of regulation at the federal, state and local levels. Such regulation
includes requiring permits for the drilling of wells, maintaining bonding
requirements in order to drill or operate wells and regulating the location of
wells, the method of drilling and casing wells, the surface use and restoration
of properties upon which wells are drilled, the plugging and abandoning of wells
and the disposal of fluids used or obtained in connection with operations. The
Company is also subject to various conservation regulations. These include the
regulation of the size of drilling and spacing units and the density of wells
which may be drilled and the unitization or pooling of oil and gas properties.
In addition, state conservation laws establish maximum rates of production from
oil and gas wells, generally prohibit the venting or flaring of gas and impose
certain requirements regarding the ratability of production. These regulations
limit the amount of oil and gas that can be produce from wells and to limit the
number of wells or the locations at which wells can be drill.

ENVIRONMENTAL REGULATIONS. The Company is subject to federal, state and local
laws and regulations governing environmental quality and pollution control.
During the fiscal years ended January 31, 2002, 2001 and 2000, the Company spent
$1,396, $12,390 and $20,867, respectively, on plugging and filling well holes,
removing drilling anchors, hauling and disposing of water and drilling mud,
filling mud pits, surface leveling and reseeding, and general site clean up. It
is anticipated that, absent the occurrence of an extraordinary event, compliance
with existing federal, state and local laws, rules and regulations concerning
the protection of the environment and human health will not have a material
effect upon the Company, capital expenditures, or earnings. The Company cannot
predict what effect additional regulation or legislation, enforcement policies
thereunder and claims for damages for injuries to property, employees, other
persons and the environment resulting from the Company's operations. The
Company's operations related to the exploration, development and production of
oil and natural gas are subject to stringent environmental regulation by state
and federal authorities including the Environmental Protection Agency ("EPA").
This regulation has increased the cost of planning, designing, drilling,
operating and in some instances, abandoning wells. In most instances, the
regulatory requirements relate to the handling and disposal of drilling and
production waste products and waste created by water and air pollution control

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procedures. Although the Company believes that compliance with environmental
regulations will not have a material adverse effect on its operations or results
of these operations, risks of substantial costs and liabilities are inherent in
oil and gas operations, and there can be no assurance that significant costs and
liabilities, including criminal penalties, will not be incurred. Moreover, it is
possible that other developments, including stricter environmental laws and
regulations, and claims for damages for injuries to property or persons
resulting from the Joint Activities could result in substantial costs and
liabilities.

         Waste Disposal. The Company currently owns or leases, and has in the
past owned or leased, numerous properties that for many years have been used for
the exploration and production of oil and gas. Although the Company has utilized
operating and disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed of or released on or under
the properties owned or leased by the Company or on or under other locations
where these wastes have been taken for disposal. State and federal laws
applicable to oil and natural gas wastes and properties have gradually become
more strict. Under these laws, the Company could be required to remove or
remediate previously disposed wastes (including wastes disposed of or released
by prior owners or operators) or property contamination (including groundwater
contamination) or to perform remedial plugging operations to prevent future
contamination. The Company's operations and activities may generate wastes,
including hazardous wastes, that are subject to the federal Resource
Conservation and Recovery Act ("RCRA") and comparable state statutes. The EPA
and applicable state agencies have limited the disposal options for certain
hazardous and nonhazardous wastes and are considering the adoption of stricter
disposal standards for nonhazardous wastes. Furthermore, certain wastes that may
be generated by the oil and natural gas operations that are currently exempt
from treatment as hazardous wastes may in the future be designated as hazardous
wastes, and therefore be subject to considerably more rigorous and costly
operating and disposal requirements.

         Superfund. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability,
without regard to fault or the legality of the original conduct, on certain
classes of persons with respect to the release of a "hazardous substance" into
the environment. These persons include the owner and operator of a site, persons
that disposed of or arranged for the disposal of the hazardous substances found
at a site, and prior owners and operators of the site. CERCLA also authorizes
the EPA and, in some cases, third parties to take actions in response to threats
to the public health or the environment and to seek to recover from responsible
classes of persons the costs of such action. In the course of operations, the
Company's operations and activities may generate wastes that fall within
CERCLA's definition of "hazardous substances." The Company may be responsible
under CERCLA for all or part of the costs to clean up sites at which such wastes
have been released. To date, however, the neither Company nor, to its knowledge,
its predecessors have been named a potentially responsible party under CERCLA or
similar state superfund laws affecting the Leases on which the Company's wells
are located.

         Air Emissions. The Company's operations and activities are subject to
local, state and federal regulations for the control of emissions of air
pollution. Legal and regulatory requirements in this area are increasing, and
there can be no assurance that significant costs and liabilities will not be
incurred in the future as a result of new regulatory developments. In
particular, regulations promulgated under the Clean Air Act Amendments of 1990
may impose additional compliance requirements that could affect the operations.
However, it is currently impossible to predict accurately the effect, if any, of

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the Clean Air Act Amendments on the Company's operations and activities. The
Company may in the future become subject to civil or administrative enforcement
actions for failure to comply strictly with air regulations or permits. These
enforcement actions are generally resolved by payment of monetary fines and
correction of any identified deficiencies. Alternatively, regulatory agencies
could require the Company to forego construction or operation of certain air
emission sources.

         OSHA. In the conduct of its activities the Company and its operations
will be subject to the requirements of the federal Occupational Safety and
Health Act ("OSHA") and comparable state statutes. The OSHA hazard communication
standard, the EPA community right-to-know regulations under Title III of the
federal Superfund Amendment and Reauthorization Act and similar state statutes
require us to organize information about hazardous materials used, released or
produced in its operations. Certain of this information must be provided to
employees, state and local governmental authorities and local citizens. The
Company is also subject to the requirements and reporting set forth in OSHA
workplace standards. The Company provides safety training and personal
protective equipment to its employees.

         OPA and Clean Water Act. Federal regulations require certain owners or
operators of facilities that store or otherwise handle oil to prepare and
implement spill prevention control plans, countermeasure plans and facilities
response plans relating to the possible discharge of oil into surface waters.
The Oil Pollution Act of 1990 ("OPA") amends certain provisions of the federal
Water Pollution Control Act of 1972, commonly referred to as the Clean Water Act
("CWA"), and other statutes as they pertain to the prevention of and response to
oil spills into navigable waters. The OPA subjects owners of facilities to
strict joint and several liability for all containment and cleanup costs and
certain other damages arising from a spill, including, but not limited to, the
costs of responding to a release of oil to surface waters. The CWA provides
penalties for any discharges of petroleum product in reportable quantities and
imposes substantial liability for the costs of removing a spill. State laws for
the control of water pollution also provide varying civil and criminal penalties
and liabilities in the case of releases of petroleum or its derivatives into
surface waters or into the ground. Regulations are currently being developed
under OPA and state laws concerning oil pollution prevention and other matters
that may impose additional regulatory burdens on the Company.

         In addition, the CWA and analogous state laws require permits to be
obtained to authorize discharges into surface waters or to construct facilities
in wetland areas. With respect to certain aspects of the its operations and
activities, the Company will be required to maintain these permits or meet
general permit requirements. The EPA has adopted regulations concerning
discharges of storm water runoff. This program requires covered facilities to
obtain individual permits, participate in a group permit or seek coverage under
an EPA general permit. The Company believes that with respect to its wells it
has obtained, or are included under, these permits and with respect to the
proposed operations the Company will be able to obtain, or be included under,
such permits, where necessary. Compliance with these permits is not expected to
have a material effect on the Company's operations and activities.

         Norm. Oil and gas exploration and production activities have been
identified as generators of concentrations of low-level naturally-occurring
radioactive materials ("NORM"). Although Oklahoma has not adopted NORM

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regulations, NORM regulations have recently been adopted in Wyoming. The Company
does not believe that compliance with these regulations will have a material
adverse effect on the Company.

         Safe Drinking Water Act. The Company's operations and activities
involve the disposal of produced saltwater and other nonhazardous oilfield
wastes by reinjection into the subsurface. Under the Safe Drinking Water Act
("SDWA"), oil and gas operators, like the Company, must obtain a permit for the
construction and operation of underground Class II injection wells. To protect
against contamination of drinking water, periodic mechanical integrity tests are
often required to be performed by the well operator. The Company has obtained
permits for the Class II well it operates. The Company has also disposed of
wastes in facilities other than those owned by the Company which are commercial
Class II injection wells.

         Toxic Substances Control Act. The Toxic Substances Control Act ("TSCA")
was enacted to control the adverse effects of newly manufactured and existing
chemical substances. Under the TSCA, the EPA has issued specific rules and
regulations governing the use, labeling, maintenance, removal from service and
disposal of PCB items, including transformers and capacitors used by oil and gas
companies. The Company believes it is in compliance with the TSCA and that the
TSCA will not have a material adverse effect on the Company's operations and
activities.

COMPETITION

          The Company is faced with strong competition from many other companies
and individuals engaged in the oil and gas business, many are very large, well
established energy companies with substantial capabilities and established
earnings records. The Company may be at a competitive disadvantage in acquiring
oil and gas prospects since it must compete with these individuals and
companies, many of which have greater financial resources and larger technical
staffs. It is nearly impossible to estimate the number of competitors; however,
it is known that there are a large number of companies and individuals in the
oil and gas business. At times there is competition among operators for drilling
equipment, tubular goods and drilling crews which may affect the Company's
ability expeditiously to drill, complete, recomplete and work-over its wells.

         There is also extensive competition in the market for natural gas. The
recent increases in domestic as well as worldwide consumption of energy and
decreases in production, especially domestically, have brought about substantial
increased demand for energy. This in turn has resulted in substantial increases
in natural gas prices, widespread increase in gas production and accelerations
in producing and marketing gas after it is discovered. In contrast, this recent
increase in demand for energy was preceded by a period of increases in worldwide
energy production capability and decreases in energy consumption as a result of
conservation efforts, which resulted in substantial surpluses in energy
supplies. This, in turn, resulted in substantial competition in markets
historically served by domestic natural gas from alternative sources of energy,
such as residual fuel oil, and among domestic gas suppliers. As a result, there
was significant reductions in gas prices, widespread curtailment of gas
production and delays in producing and marketing gas after it is discovered.
Changes in government regulations relating to the production, transportation and
marketing of natural gas have also resulted in significant changes in the
historical marketing patterns of the industry. Generally, these changes have
resulted in the abandonment by many pipelines of long-term contracts for the
purchase of natural gas, the development by gas producers of their own marketing
programs to take advantage of new regulations requiring pipelines to transport

<PAGE>

gas for regulated fees, and an increasing tendency to rely on short-term
contracts priced at spot market prices.

         During periods of decreasing demand for energy, many producers have
been willing to accept prices that are lower than those previously prevailing in
order to sell their production. As a consequence, gas prices, which were once
effectively determined by government regulations, are now largely influenced by
competition. Competitors in this market include producers, gas pipelines and
their affiliated marketing companies, independent marketers, and providers of
alternate energy supplies, such as residual fuel oil.

         Exploration for and production of oil and gas are affected by the
availability of pipe, casing and other tubular goods and certain other oil field
equipment including drilling rigs and tools. The Company depends upon
independent drilling contractors to furnish rigs, equipment and tools to drill
its wells. The Company has not experienced and does not anticipate difficulty in
obtaining supplies, materials, drilling rigs, equipment or tools. However,
higher prices for oil and gas production have recently caused competition for
these items to increase and may result in increased costs of operations.

     Due to its lack of capital, the Company is presently not competitive in the
exploration and development of oil and gas properties.

MARKETS

         The Company does not refine or otherwise process crude oil and
condensate production. Substantially all of the crude oil and condensate
production of the Company's wells are sold at posted prices under short-term
contracts, which is customary in the industry.

         The Company's gas production is sold primarily on the spot market to a
variety of purchasers, including intrastate and interstate pipelines, their
marketing affiliates, independent marketing companies and other purchasers who
have the ability to move the gas under firm transportation agreements.

         The availability of a market for produced oil and gas will be dependent
upon a number of factors beyond the Company's control, which at times cannot be
accurately predicted. These factors include the proximity of wells to, and the
capacity of, natural gas pipelines, the extent of competitive domestic
production and imports of oil and gas, the availability of other sources of
energy, fluctuations in seasonal supply and demand, and governmental regulation.
In addition, there is always the possibility that new legislation may be enacted
which would impose price controls or additional excise taxes upon crude oil or
natural gas, or both. Oklahoma, the state in which the operations and properties
are located, has experienced an oversupply of natural gas which may cause
delays, restrictions or reductions of their natural gas production. Oversupplies
of natural gas can be expected to recur from time to time and may result in the
gas producing wells being shut-in. Increased imports of natural gas, primarily
from Canada, have occurred and are expected to continue. Such imports may
adversely affect the market for domestic natural gas.

         Since the early 1970's the market price for crude oil has been
significantly affected by policies adopted by the member nations of Organization
of Petroleum Exporting Countries ("OPEC"). Members of OPEC establish prices and

<PAGE>

production quotas among themselves for petroleum products from time to time with
the intent of controlling the current global supply and consequently price
levels. Canada has recently amended its tax laws and other laws affecting the
exportation of its natural gas to the United States, and such amendments are
expected to materially increase competition and may adversely affect the price
of natural gas in certain geographic areas of the United States. The Company is
unable to predict the effect, if any, that OPEC or the Canadian amendments will
have on the amount of, or the prices received for, crude oil and natural gas
produced and sold from the Company's wells.

         Changes in natural gas and crude oil prices will significantly affect
the revenues and cash flow of the wells and the value of the oil and gas
properties. Declines in the prices of crude oil and natural gas could have a
material adverse effect on the success of the Company's operations and
activities, recoupment of the costs of acquiring, developing and producing the
its wells and profitability. The Company is unable to predict whether the prices
of crude oil and natural gas will rise, stabilize or decline in the future.

GENERAL

     The Company has never been a party to any bankruptcy, receivership,
reorganization, readjustment or similar proceedings. Since the Company is
engaged in the oil and gas business, it does not allocate funds to product
research and development in the conventional sense. The Company does not have
any patents, trade-marks, or labor contracts. With the exception of the
Company's oil and gas leases, the Company does not have any licenses,
franchises, concessions or royalty agreements. Backlog is not material to an
understanding of the Company's business. The Company's business is not subject
to renegotiation of profits or termination of contracts or subcontracts at the
election of federal government.

EMPLOYEES

         At November 30, 2002, the Company employed nine people in its Oklahoma
City office whose functions were associated with management, engineering,
geology, land and legal, accounting, financial planning and administration. In
addition, two part-time employees were responsible for the supervision and
operation of the Company's field activities and the providing of well services.

         The Company's future performance depends in significant part upon the
continued service of its key technical and management personnel and its
continuing ability to attract and retain highly qualified and motivated
personnel in all areas of the Company's operations. Competition for qualified
personnel is intense. The Company provides no assurance that it can retain key
managerial and technical employees or that the Company can attract, assimilate
or retain other highly qualified personnel in the future. The Company's
employees are not represented by a labor union. The Company has not experienced
any work stoppages and considers its employee relations to be good. The Company
considers the following persons to be key employees: George Shaw (President),
Taylor Dillard (Exploration Manager), and Jerry Parry (Land Manager).



<PAGE>


ITEM 2.  DESCRIPTION OF PROPERTY

         The Company conducts its oil and gas exploration and production
operations in eastern Oklahoma and western Arkansas in the Arkoma Basin and in
the Powder River Basin of Wyoming. At August 31, 2002, the Company had interests
in six producing wells located in Oklahoma and Wyoming, all of which were
operated by the Company.

        All of the Company's Producing Properties are leased for an
indeterminate number of years, as long as production is maintained. Therefore,
it is not possible to provide expiration dates of the Leases on which Producing
Properties are located.

         The following table sets forth, at January 31, 2002, by state and
basin, the Company's producing wells, Developed Acreage, and Undeveloped
Acreage, excluding service (injection and disposal) wells:

<TABLE>
<S>                            <C>        <C>       <C>         <C>       <C>         <C>

                            Productive Wells (1)   Developed Acreage   Undeveloped Acreage (2)
                              Gross       Net      Gross         Net      Gross       Net

Oklahoma (Arkoma Basin)         4        2.11      1,920      1,012.8    1,298.4     444.7
Wyoming (Powder River Basin)    2        .285         80         36.8     26,006  25,010.2

Totals                          6       2.395      2,000      1,049.6   27,304.4  25,454.9

</TABLE>


         The following table sets forth, as of August 31, 2002, by state and
basin, the Company's producing wells, Developed Acreage, and Undeveloped
Acreage, excluding service (injection and disposal) wells:

<TABLE>
<S>                            <C>        <C>       <C>         <C>       <C>         <C>

                            Productive Wells (1)   Developed Acreage   Undeveloped Acreage (2)
                              Gross       Net      Gross         Net      Gross       Net

Oklahoma (Arkoma Basin)         4        2.11      1,920      1,012.8    1,298.4     444.7
Wyoming (Powder River Basin)    2        .285         80         11.4     26,006  25.010.2

Totals                          6       2.395      2,000      1,024.2   27,304.4  25,454.9

</TABLE>


(1)  The wells in Oklahoma are gas wells and the wells in Wyoming are oil wells.
(2)  "Undeveloped Acreage" includes leasehold interests on which wells have not
     been drilled or completed to the point that would permit the production of
     commercial quantities of natural gas and oil regardless of whether the
     leasehold interest is classified as containing proved undeveloped reserves.

      The basic terms of the oil and gas leases held by the Company as of August
31, 2002 are shown in the following table.

                     Gross           Annual                    Lease
                     Acres          Rental (1)              Expiration

Oklahoma           1,920.0       Held By Production           N/A
                   1,140.0             (2)                   09/02

<PAGE>

                     Gross           Annual                    Lease
                     Acres          Rental (1)              Expiration

                     158.4             (2)                   08/03
                  --------
                   3,218.4


Wyoming              640.0       Held By Production           N/A
                   1,943.4             (2)                   11/02
                  14,413.1             (2)                   08/03
                     159.5             (2)                   05/04
                     760.0         $   285                   07/04
                   2,302.0          $1,102                   12/04
                     360.0         $   326                   04/05
                   1,360.0          $1,645                   10/05
                     405.0         $   115                   03/06
                   1,561.0         $   930                   01/07
                     160.0        $     45                   05/07
                   2,022.0          $4,044                   02/08
                 ---------
                  26,086.0

(1)  Represents the Company's share of the annual rental payment.
(2)  All lease  rentals have been paid in advance on the leases  covering  these
     acres.

    Leased acres Held By Production remain in force so long as oil or gas is
produced from the well on the particular lease. Leased acres which are not Held
By Production require annual rental payments to maintain the lease until the
first to occur of the following the expiration of the lease or the time oil or
gas is produced from one or more wells drilled on the lease acreage. At the time
oil or gas is produced from wells drilled on the leased acreage the lease is
considered to be Held By Production.

        The Company is not obligated to provide a fixed and determined quantity
of oil or gas in the future. During the last three fiscal years, the Company has
not had, nor does it now have, any long-term supply or similar agreement with
any government or governmental authority. The following table sets forth the
Company's net production of oil and gas, average sales prices and average
production costs during the periods presented:


                                   Year Ended January 31,
                              -------------------------------
Production Data:              2000          2001         2002
                              ----          ----         ----

Production - Oil (Bbls)      1,112          473            498
Gas (Mcf)                   37,887       31,199         29,234
Average sales price -
Oil (Bbls)                 $ 16.39      $ 27.34         $19.65
Gas (Mcf)                  $  1.86      $  4.09         $ 3.24

Average production
    costs per BOE          $  4.35     $   4.97         $ 2.93

<PAGE>



      The decrease in average production cost per BOE during the year ended
January 31, 2002 was the result of less repairs needed in 2002 because of the
extensive workovers completed in 2001.

      The components of production costs may vary substantially among wells
depending on the methods of recovery employed and other factors, but generally
include severance taxes, administrative overhead, maintenance and repair, labor
and utilities.

        The quantities of natural gas and crude oil Proved Developed Reserves
presented below include only those amounts which the Company reasonably expects
to recover in the future from known oil and gas reservoirs under existing
economic and operating conditions, at current prices and costs, under existing
regulatory practices and with existing technology. Accordingly, any changes in
prices, operating and development costs, regulations, technology or other
factors could significantly increase or decrease estimates of Proved Developed
Reserves.

        The Company's net Proved Developed Reserves of oil and gas and the
present values thereof at January 31, 2002, 2001 and 2000 were estimated by
Ramsey Property Management, Inc. These estimates were utilized in the
preparation of the Company's consolidated financial statements for the
applicable periods, and for other reporting purposes.

        Set forth below are estimates of the Company's net Proved Developed
Reserves and the present value of estimated future net revenues from such
Reserves based upon the standardized measure of discounted future net cash flows
relating to proved oil and gas Reserves in accordance with the provisions of
Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and
Gas Producing Activities" (SFAS No. 69). The standardized measure of discounted
future net cash flows is determined by using estimated quantities of Proved
Developed Reserves and the periods in which they are expected to be developed
and produced based on period-end economic conditions. The estimated future
production is priced at period-end prices, except where fixed and determinable
price escalations are provided by contract. The resulting estimated future cash
inflows are then reduced by estimated future costs to develop and produce
reserves based on period-end cost levels. No deduction has been made for
depletion, depreciation or for indirect costs, such as general corporate
overhead. Present values were computed by discounting future net revenues by 10%
per year.

                                                  January 31,
                                  --------------------------------------------
                                  2002                2001            2000
                                  ----                ----            ----
                              Oil      Gas         Oil    Gas       Oil      Gas
                            (Bbls)    (Mcf)       (Bbls) (Mcf)    (Bbls)   (Mcf)

Proved reserves             6,842    713,262    11,676  760,143   8,909  730,441
Estimated future net cash
  flows from proved oil and
    gas reserves             $1,763,748           $7,008,916       $1,439,089

Present value of future net
  cash flows from proved
  oil and gas reserves         $493,982           $2,429,385      $   547,246

<PAGE>


        For further information on the Company's Reserves, costs relating to oil
and gas activities and results of operations from producing activities, see the
unaudited Supplemental Information included as part of the Company's financial
statements for the year ended January 31, 2002.

        As of August 31, 2002 one of the Company's wells in the Arkoma Basin
accounted for 93% of the Company's total oil and gas reserves and 92% of the
present value of the Company's future net cash flow from its oil and gas
reserves.

        In general, the volume of production from natural gas and oil properties
owned by the Company declines as reserves are depleted. Except to the extent the
Company acquires additional properties containing proved reserves or conducts
successful exploration and development activities, or both, the proved reserves
of the Company will decline as reserves are produced. Volumes generated from
future activities of the Company are therefore highly dependent upon the level
of success in acquiring or finding additional reserves and the costs incurred in
doing so.

        During the past year, the only report concerning the Company's estimated
proved reserves that was filed with a U.S. federal agency other than the
Commission was the Annual Survey of Domestic Oil and Gas Reserves which was
filed with the Energy Information Administration ("EIA") as required by law.
Only minor differences of less than 5% in reserve estimates, which were due to
small variances in actual production versus year-end estimates, occurred in
certain classifications reported in this document as compared to those in the
EIA report.

        During the periods indicated, the Company drilled or participated in the
drilling of the following wells:

                                         Year Ended January 31,
------------------------------------------------------------------------------
                                 2000              2001             2002
                                 ----              ----             ----
                          Gross     Net       Gross    Net       Gross     Net
Exploratory Wells (1):
  Productive:
   Oil                      --       --         --      --         --       --
   Gas                      --       --         --      --         --       --
  Nonproductive              3      1.5         --      --         --       --

Development Wells (1):
  Productive:
   Oil                      --       --         --      --         --       --
   Gas                      --       --         --      --         --       --
  Nonproductive              1      0.5          1     0.5         --       --

Total Wells (1):
  Productive:
   Oil                      --       --         --      --         --       --
   Gas                      --       --         --      --         --       --
  Nonproductive              4      2.0          1     0.5         --       --


(1)  Each well completed to more than one producing zone is counted as a single
     well. The Company has royalty interests in certain wells that are not
     included in this table.

<PAGE>

        The Company does not own any Overriding Royalty Interests.

        Title to properties is subject to royalty, overriding royalty, carried,
net profits, working and other similar interests and contractual arrangements
customary in the oil and gas industry, to liens for current taxes not yet due
and to other encumbrances. As is customary in the industry in the case of
undeveloped properties, little investigation of record title is made at the time
of acquisition (other than a preliminary review of local records). Drilling
title opinions are always prepared before commencement of drilling operations;
however, as is customary in the industry.

        In September 2001, the Company relocated its offices in 4,320 square
feet on the third floor at 800 Northeast 63rd Street, Oklahoma City, Oklahoma.
The office space is occupied under an unwritten lease, on a month-to-month
basis, requiring rental payments of $3,420 per month. The building is owned by
George G. Shaw, the Company's Chief Executive Officer and a Director.

ITEM 3.  LEGAL PROCEEDINGS.

            From time to time, the Company may be involved in litigation
relating to claims arising out of its operations in the normal course of
business. The Company is not currently a party to any pending legal proceedings.

      James Attarian, a director and principal shareholder of the Company, has
advised the Company that in his opinion the Company owes Mr. Attarian and
several companies controlled by Mr. Attarian $300,000 to $400,000 more than the
$360,000 in loans which the Company has recorded as loans to Mr. Attarian and
his affiliates. Dr. Attarian has indicated that his claims in this regard
represent amounts paid by Dr. Attarian and his affiliates for shares of the
Company's stock and the drilling costs of unproductive oil and gas wells. The
Company does not believe it owes any material amount to Dr. Attarian and his
affiliated entities over and above the $360,000, of which $60,000 is reflected
on the Company's balance sheet at January 31, 2002 as Due To Shareholders and
$300,000 of which is reflected on the Company's balance sheet as Due to Related
Party and Shareholder.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

         Not Applicable

ITEM 5. MARKET PRICE OF AND  DIVIDENDS  ON THE  REGISTRANT'S  COMMON  EQUITY AND
        OTHER SHAREHOLDER MATTERS.

      The Company's common stock is traded listed on the Canadian Venture
Exchange under the symbol EEG. The closing sale prices reflect inter-dealer
prices without adjustment for retail markups, markdowns or commissions and may
not reflect actual transactions. The following table sets forth the high and low
sale prices of our common stock in U.S. currency during the calendar quarters
presented as reported by the Canadian Venture Exchange.




<PAGE>


                                               Closing Sale Price
                                                 Common Stock
                                             _____________________
            Quarter Ended                    High           Low
            --------------                   ----           ----

            October 31, 2002                 $0.13          $0.03
            July 31, 2002                    $0.13          $0.03
            April 30, 2002                   $0.07          $0.04

            January 31, 2002                 $0.16          $0.03
            October 31, 2001                 $0.25          $0.12
            July 31, 2001                    $0.25          $0.12
            April 30, 2001                   $0.19          $0.12

            January 31, 2001                 $0.39          $0.12
            October 30, 2000                 $0.47          $0.20
            July 31, 2000                    $0.57          $0.13
            April 30, 2000                   $0.29          $0.15
            January 31, 2000                 $0.29          $0.15
            October 30, 1999                 $0.32          $0.12
            July 31, 1999                    $0.26          $0.13
            April 30, 1999                   $0.28          $0.10

      On August 31, 2002, the closing sale price of the Company's common stock
as quoted on the Canadian Venture Exchange was $0.13. On August 31, 2002, there
were approximately 870 holders of the Company's common stock.

      The market price of the Company's common stock is subject to significant
fluctuations in response to, and may be adversely affected by (i) variations in
quarterly operating results, (ii) developments in the oil and gas industry
generally and more particularly within the geographically and geological areas
that the Company owns and operates properties, and (iii) general stock market
conditions.

      Within the United States, the Company's common stock is subject to the
"penny stock" rules. The penny stock trading rules impose additional duties and
responsibilities upon broker-dealers and salespersons recommending the purchase
or sale of a penny stock. Required compliance with these rules will materially
limit or restrict the ability to resell the Company's common stock, and the
liquidity typically associated with other publicly traded stocks may not exist.

ITEM 6. MANAGEMENT'S  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND PLAN OF
        OPERATION

RESULTS OF OPERATIONS

     The  factors  that most  significantly  affect  the  Company's  results  of
operations are (i) the sale prices of crude oil and natural gas, (ii) the amount
of production sales, (iii) the amount of lease operating expenses,  and (iv) the
level of interest rates on, and amount of,  borrowings.  Sales of production and


<PAGE>

level of  borrowings  are  significantly  impacted by the  Company's  ability to
maintain or increase its production from existing oil and gas properties through
its  exploration and  development  activities.  The following table reflects the
average prices  received by the Company for oil and gas, the average  production
cost per BOE, and the amount of oil and gas produced for the periods presented:

                                           Year Ended January 31,
Production Data:             2000           2001           2002
                             ----           ----           ----

Production - Oil (Bbls)     1,112            473             498
Gas (Mcf)                  37,887         31,199          29,234
Average sales price -
  Oil (Bbls)              $ 16.39        $ 27.34          $19.65
Gas (Mcf)                 $  1.86        $  4.09          $ 3.24
Average production
  costs per BOE           $  4.35        $  4.97          $ 2.93

         Prices received by the Company for sales of crude oil and natural gas
have fluctuated significantly from period to period. The fluctuations in oil
prices during these periods reflect market uncertainty regarding the inability
of the Organization of Petroleum Exporting Countries ("OPEC") to control the
production of its member countries, as well as concerns related to the global
supply and demand for crude oil. Gas prices received by the Company fluctuate
with changes in the spot market price for gas, which reached recent record
levels in December 2000 in the United States.

      This price increase was due to demand in excess of deliverability and
higher worldwide energy prices. However, natural gas prices have been declining
since December 2000 because of lower worldwide energy prices as well as
development of more adequate deliverability to meet demand requirements.
Relatively modest changes in either oil or gas prices significantly impact the
Company's results of operations and cash flow, and can significantly impact the
Company's borrowing capacity. During the third and fourth quarters of 2000 and
the first quarter of 2001, the Company experienced a significant increase in
cash flow and net income primarily as a result of an increase in crude oil
prices and natural gas prices with a slight decrease in the volume of crude oil
and natural gas production sales. During the year ended January 31, 2002 prices
for oil and natural gas declined significantly.

     Other than the foregoing, the Company does not know of any trends, events
or uncertainties that have had or are reasonably expected to have a material
impact on the Company's net sales, revenues or expenses.

PERIOD TO PERIOD COMPARISONS

YEAR ENDED JANUARY 31, 2002

     During the year ended  January  31, 2002  ("Fiscal  2002"),  the  Company's
revenue was comprised of three sources, oil and gas sales,  pipeline revenue and
a one-time  gain of $16,061  which  related to an  insurance  settlement  on the
Company's office equipment which was damaged or destroyed due to vandalism.  Oil


<PAGE>

and gas sales for Fiscal 2002 decreased by $37,278 compared with Fiscal 2001 due
to the decline in oil and gas prices.  Pipeline  revenue  during Fiscal 2002 did
not change materially from Fiscal 2001.

    In Fiscal 2002 salaries and benefits increased by $29,923 due to temporary
staff hired to assist the Company with filings with the Securities and Exchange
Commission. Depletion and depreciation increased $10,289 due to an adjustment
made at year end to conform the Company's depletion rate to its proven oil and
gas reserves. Legal and accounting expenses increased by $37,536 as the result
of costs related to preparing the Company's registration statement on Form 10SB
and additional auditing expense. During Fiscal 2002 the Company expensed $6,665
in the form of a write down of its oil and gas properties due to a decline in
the present value of the Company's oil and gas reserves. Rent expense decreased
due to the relocation of the Company's offices to space with a less expense
lease. The Company did not incur any business investigation costs during Fiscal
2002. Business investigation costs in Fiscal 2001 related to the unsuccessful
attempt to acquire oil and gas properties from the G.M. Oil Company. Oil and gas
production costs decreased moderately since none of the Company's wells required
workovers in Fiscal 2002. Consulting expenses increased slightly due to
increased amounts paid to a consultant to be competitive with market rates. The
Company's offices were vandalized in November 2000. Consequently office and
general expenses increased due to required repairs and cleaning subsequent to
January 31, 2001. Travel and promotion expenses decreased due to less travel to
inspect wells in Wyoming.

YEAR ENDED JANUARY 31, 2001

         Total revenue for the year ended January 31, 2001 ("Fiscal 2001"),
compared with the year ended January 31, 2000 ("Fiscal 2000"), increased by
$59,227. The Company's revenue was comprised of two sources, oil and gas sales
revenue and pipeline revenue. Oil and gas production revenue for Fiscal 2001,
compared with Fiscal 2000, increased by $59,758. The increase in oil and gas
production revenues was due to the increase in average sales prices for crude
oil and natural gas of $10.29 per Bbl and $2.23 per Mcf, respectively, although
the volumes of crude oil and natural gas sales decreased by 639 Bbls and natural
gas sales of 6,688 Mcf.

     The Company  incurred  operating  expenses of $702,398 for the year January
31,  2001 as  compared  to  $835,707  for  the  year  ended  January  31,  2000,
representing a 16% decrease.  Business  investigation costs increased by $50,000
and legal and accounting expenses increased by $44,601. These increases were due
to costs incurred in the Company's  unsuccessful  attempt to acquire oil and gas
properties  from the G.M.  Oil  Company,  which the Company did not incur in the
previous  year.  Travel and  promotion  expenses  also  increased by $4,223 as a
result  of costs  associated  with the  attempted  acquisition  of the G.M.  Oil
Company properties. Salaries and benefits decreased by $4,586 as a result of the
Company  reducing  compensation  and  the  number  of  employees.  Rent  expense
decreased by $10,649 a result of the Company's relocation of its office. Oil and
gas  production  expenses  decreased by $4,522 and pipeline  costs  decreased by
$1,409.  These  decreases  were the result of the Company not bearing any of the
costs  associated  with  drilling any wells during  fiscal 2001.  In Fiscal 2001
there  were  minimal  new  purchases  of fixed  assets,  however  depletion  and
depreciation  decreased  by  $20,211.  This  decrease  was  due to  the  Company
sustaining a large write-off of undeveloped  leasehold acreage in the prior year
as a result of management's  determination  that the acreage was uneconomical or
impractical to drill and develop.


<PAGE>

         During the year ended January 31, 2000, the Company issued 808,800
shares of common stock at $.25 per share for the settlement of debt in the
amount of $198,970. The remaining $49,930 owed to the lender was forgiven
resulting in a $49,930 gain. Interest expense in Fiscal 2001 declined as a
result of the payment of this debt.

EFFECTS OF OIL AND GAS PRICE FLUCTUATIONS

         Fluctuations in crude oil and natural gas prices have significantly
affected the Company's operations and the value of its assets. As a result of
the instability and volatility of crude oil and natural gas prices and at times
the market conditions within the oil and gas industry, financial institutions
are selective in the energy lending area and have reduced the percentage of
existing reserves that may qualify for the borrowing base to support energy
loans.

         The Company's principal source of cash flow is the production and sale
of its crude oil and natural gas reserves which are depleting assets. Cash flow
from oil and gas production sales depends upon the quantity of production and
the price obtained for such production. An increase in prices permits the
Company to finance its operations to a greater extent with internally generated
funds, may allow the Company to obtain equity financing more easily or on better
terms, and lessens the difficulty of attracting financing from industry partners
and non-industry investors. However, price increases heighten the competition
for Leases and Prospects, increase the costs of exploration and development
activities, and, because of potential price declines, increase the risks
associated with the purchase of Producing Properties during times that prices
are at higher levels.

         A decline in oil and gas prices (i) reduces the cash flow internally
generated by the Company which in turn reduces the funds available for servicing
debt and exploring for and replacing oil and gas reserves, (ii) increases the
difficulty of obtaining equity and debt financing and worsens the terms on which
such financing may be obtained, (iii) reduces the number of Leases and Prospects
which have reasonable economic terms, (iv) may cause the Company to permit
Leases to expire based upon the value of potential oil and gas reserves in
relation to the costs of exploration, (v) results in marginally productive oil
and gas wells being abandoned as non-commercial, and (vi) increases the
difficulty of attracting financing from industry partners and non-industry
investors. However, price declines reduce the competition for Leases and
Prospects and correspondingly reduce the prices paid for Leases and Prospects.
Furthermore, exploration and production costs generally decline, although the
decline may not be at the same rate as that of oil and gas prices.

SEASONALITY

         The results of operations of the Company are somewhat seasonal due to
seasonal fluctuations in the sales prices for natural gas. Although in recent
years crude oil prices have been generally higher in the third and fourth fiscal
quarters, these fluctuations are not believed to be seasonal. Natural gas prices
have been generally higher in the fourth fiscal quarter. Due to these seasonal
fluctuations, results of operations for individual quarterly periods may not be
indicative of results which may be realized on an annual basis.

<PAGE>


INFLATION AND CHANGES IN PRICES

         Within recent years, inflation generally has had a minimal effect on
the Company and its operations. However, crude oil and natural gas prices have
significantly affected the costs required to drill, complete and operate oil and
gas wells. The level of drilling activity within the oil and gas industry
increased or decreased based upon crude oil and natural gas prices without
regard to general inflation. With the decline in oil and gas prices since
December 2000, management believes that cost will remain relatively stable or
even decline from the current level over the next year.

INCOME TAX PROVISION (BENEFIT)

         Statement of Financial Accounting Standards 109, Accounting for Income
Taxes, requires the separate recognition, measured at currently enacted tax
rates, of deferred tax assets and deferred tax liabilities for the tax effect of
temporary differences between the financial reporting and tax reporting bases of
assets and liabilities, and net operating loss carryforward for tax purposes. A
valuation allowance must be established for deferred tax assets if it is "more
likely than not" that all or a portion will not be realized. At January 31, 2002
and 2001, the Company had the benefit of net operating loss carryforward of
$5,264,905 and $5,369,298, respectively, and the valuation allowance was the
amount of the operation loss carryforward for each year. Because of the
valuation allowance, the net operating loss carryforward did not have any value
at January 31, 2002 or 2001.

CAPITAL RESOURCES AND LIQUIDITY

         During the year ended January 31, 2002, the Company's operations used
$491,565 in cash. During the same period the Company repaid $120,644 in advances
from a shareholder and used $14,225 to purchase equipment. The Company satisfied
its cash requirements during this period through the sale of common stock and
warrants, proceeds from an insurance settlement relating to vandalism at the
Company's office, and cash on hand at the beginning of the year.

      During the year ended January 31, 2001 the Company's operations used
$367,531 in cash. During this same period the Company used $6,272 to purchase
equipment. The Company satisfied its cash requirements during this period
through the sale of shares of common stock and warrants for $93,023, advances
from a shareholder in the amount of $244,869, a loan from an unrelated party in
the amount of $50,000, and proceeds of $10,000 from the sale of oil and gas
properties.

     As a result of the Company's continued losses and lack of cash there is
substantial doubt as to the Company's ability to continue operations. The
Company plans to generate profits by drilling productive oil or gas wells.
However, the Company will need to raise the funds required to drill new wells
from third parties willing to pay the Company's share of drilling and completing
the wells. The Company may also attempt to raise needed capital through the
private sale of its securities or by borrowing from third parties. The Company
may not be successful in raising the capital needed to drill oil or gas wells.
In addition, any future wells which may be drilled by the Company may not be
productive of oil or gas. The inability of the Company to generate profits may
force the Company to curtail or cease operations.


<PAGE>

CAPITAL EXPENDITURES AND COMMITMENTS.

         During the years ended January 31, 2002 and 2001, the Company did not
incur any exploration expenditures or acquire any oil or gas properties;
however, during the year ended January 31, 2001 the Company purchased $6,272 of
equipment. Exploration expenditures and acquisition of oil and gas properties
expenditures by the Company during the year ended January 31, 2000 were
$214,707. The lack of capital expenditures during the years ended January 31,
2002 and 2001 was primarily the result of the Company's inability to conduct
exploration activities during these periods due to a lack of funds.

         As of November 30, 2002, the Company did not have any material capital
commitments, other than funding its operating losses. It is anticipated that any
capital commitments that may occur will be financed principally through
borrowings from institutional and private lenders (although such additional
financing has not been arranged) and the sale of shares of the Company's common
stock or other equity securities. However, there can be no assurance that
additional capital resources and financings will be available to the Company on
a timely basis, or if available, on acceptable terms.

FINANCING ARRANGEMENTS.

     In December 1998, the Company obtained a $248,900 loan for the purchase of
seismic data on and acquisition of Leases within the Arkoma Basin from an
unrelated third party. As partial consideration for this loan, the Company
issued warrants exercisable for the purchase of 50,000 shares of the Company's
common stock. These warrants expired on January 18, 2001. In November 1999 the
Company issued 808,800 shares of its common stock in repayment of this loan.
With the loan proceeds the Company identified four Prospects in the Arkoma
Basin.

         In February 1999 the Company borrowed $300,000 from Mankato Investments
LLC to fund lease acquisitions and the exploration and development of the Leases
acquired in the Arkoma Basin. Four wells were drilled on the leases. None of the
wells drilled were productive of oil or gas in commercial quantities. The loan
was due April 1, 2002 and beginning April 1, 2002 the loan bears interest at 12%
per year. As of August 31, 2002 this loan was in default. As partial
consideration for this loan, the Company issued warrants for the purchase of
60,000 shares of the Company's common stock at a price of $0.27 per share. These
warrants were exercised in September 2000. Mankato Investments LLC is controlled
by James Attarian, a director of the Company.

     During the year ended January 31, 2001, the Company received additional
loans of $60,000 from Mankato Investments LLC. The loan proceeds were used for
operating expenses. The loans are non-interest bearing, were due May 13, 2002
and are in default. As of November 30, 2002 Mankato Investments had not
instituted proceedings to collect the amounts owed by the Company. Accordingly,
the default in paying these loans has not had any affect on the Company's
operations.

     Mr.  Attarian  has advised the Company that in his opinion the Company owes
Mr. Attarian,  Mankato Investments and other entities controlled by Mr. Attarian
$300,000  to  $400,000  more than the  $360,000  in loans  which the Company has
recorded as loans to Mr. Attarian and his affiliates. Dr. Attarian has indicated
that his claims in this regard  represent  amounts paid by Dr.  Attarian and his

<PAGE>


affiliates  for  shares  of the  Company's  stock  and  the  drilling  costs  of
unproductive  oil and gas  wells.  The  Company  does  not  believe  it owes any
material  amounts to Dr.  Attarian over and above the $360,000  reflected in the
Company's financial  statements as of July 31, 2001. However, if Dr. Attarian is
successful  in his  position  the  Company  will be  required  to  record  these
additional  obligations  on  its  balance  sheet  and  eventually  settle  these
obligations with cash or non-cash payments.

         As of August 31, 2002, George G. Shaw, the Company's President and
Chairman had lent $382,659 to the Company. This loan is non-interest bearing
unsecured, and does not have fixed terms of repayment. The amounts borrowed from
Mr. Shaw were used to fund the Company's operations.

    In June 2000, the Company received a loan of $50,000 from an unrelated third
party, which bears interest at 25%. The loan was due December 31, 2000 and is in
default. In August 2000, the Company received a loan of $25,000 from an
unrelated third party, which bears interest at 10%. At July 31, 2001, $1,672 of
interest had been accrued on this note. This loan was due August 2002 and is in
default.

     As of November 30, 2002 the Company did not have sufficient funds to pay
the outstanding loans referred to above. The Company plans to repay these loans
from the sale of oil or gas from wells which may be drilled by the Company, if
sufficient capital is available, or from the proceeds received from the sale of
the Company's capital stock. Mr. Shaw has advised the Company that he will not
look for repayment of the amounts owed to him by the Company prior to December
31, 2003. The other lenders may at any time file a lawsuit to enforce the
collection of the amounts owed by the Company.

ITEM 7.  FINANCIAL STATEMENTS

      See the financial statements attached to this report.

ITEM 8.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS.

     Effective  January 24, 2002 the Company  retained  Spicer,  Jefferies & Co.
("Spicer") to act as the Company's independent  certified public accountant.  In
this regard  Spicer  replaced  Bedford  Curry & Co. which  audited the Company's
financial statements for the fiscal years ended January 31, 2001, 2000 and 1999.
The report of Bedford  Curry for these  fiscal  years did not contain an adverse
opinion, or disclaimer of opinion and were not qualified or modified as to audit
scope or accounting  principles.  However, the report of Bedford Curry for these
fiscal years was  qualified  with  respect to  uncertainty  as to the  Company's
ability to continue as a going concern.  During the Company's  three most recent
fiscal years and the subsequent interim period ended January 24, 2002 there were
no  disagreements  with Bedford Curry on any matter of accounting  principles or
practices, financial statement disclosure or auditing scope or procedures, which
disagreements,  if not resolved to the  satisfaction of Bedford Curry would have
caused it to make reference to such disagreements in its reports.


<PAGE>

      Bedford Curry is based in Vancouver, British Columbia. The Company
dismissed Bedford Curry due to rules of the Securities and Exchange Commission
which require the Company's financial statements to be audited by accountants
that are based in the United States. The Company has authorized Bedford Curry to
discuss any matter relating to the Company and its operations with Spicer.

      The change in the Company's auditors was recommended and approved by the
Company's board of directors.

      During the two most recent fiscal years and subsequent interim period
ended January 24, 2002, the Company did not consult with Spicer regarding the
application of accounting principles to a specified transaction, either
completed or proposed, or the type of audit opinion that might be rendered on
the Company's financial statements, or any matter that was the subject of a
disagreement or a reportable event as defined in the regulations of the
Securities and Exchange Commission.

ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS

         The following table sets forth information with respect to each of the
Company's executive officers and directors as of November 30, 2002. The
Company's directors are generally elected at the annual shareholders' meeting
and hold office until the next annual shareholders' meeting or until their
successors are elected and qualified. The Company's executive officers are
elected by our board of directors and serve at its discretion.

Name                         Age    Position

George G. Shaw               72     President and Chief Executive Officer and
                                      Chairman of the Board
G. Scott Shaw                31     Vice President - Corporate Development,
                                      and a Director
David W. Young               52     Chief Financial Officer and a Director
Stephen D. Wortley           43     Secretary
James H. Attarian, M.D.      42     Director

         The following is a brief description of the business background of the
Company's executive officers and directors:

     GEORGE G. SHAW is the President,  Chief  Executive  Officer and Chairman of
the Board of  directors of the Company and has held these  positions  since July
1991.  Mr.  Shaw is the  President  of Energas  Corporation  and its  subsidiary
Energas Pipeline Co., Inc., both privately held companies engaged in oil and gas
exploration and gas gathering. Mr. Shaw is the father of G. Scott Shaw.


<PAGE>

     G. SCOTT SHAW is the Vice President - Corporate  Development and a director
of the Company and has held these  positions since August 23, 1996. Mr. Shaw was
graduated  from Oklahoma  State  University in 1993 with a B.S. in Biology.  Mr.
Shaw is the son of George G. Shaw.

     DAVID W.  YOUNG has held the  position  of Chief  Financial  Officer of the
Company  since April 1995.  Mr.  Young has been a director of the Company  since
August 2001.  Mr. Young is a practicing  accountant  and was graduated  from the
University of Central Oklahoma in 1975, with a B.B.S. in accounting.

     STEPHEN D. WORTLEY has been the  Secretary of the Company  since  December,
1991.  Mr. Wortley is a partner and managing  attorney in the  Vancouver,  B.C.,
Canada office of Lang Michener Lawrence & Shaw, law firm.

     JAMES H.  ATTARIAN,  M.D.  became a director of the company in August 2001.
Dr.  Attarian has been a practicing  physician  since  February  1994. He is the
managing  member of Mankato  Investments  LLC and  Jurassic  Capital  LLC,  both
privately-held  investment companies. Dr. Attarian received a B.S. in 1983 and a
M.D. in 1987 from the University of Michigan.

     As of November  30, 2002 George  Shaw,  David Young and Dr.  Attarian  were
members of the Company's Audit Committee.

ITEM 10.  EXECUTIVE COMPENSATION

         The following table sets forth the compensation during the years ended
January 31, 2002, 2001 and 2000, paid or accrued, of George G. Shaw, the
Company's Chief Executive Officers during those years. None of the Company's
executive officers received compensation in excess of $100,000 during the three
years ended January 31, 2002.
                                                                     Long-Term
                                                                   Compensation
                                                                      Awards
                                                                   Common Stock
 Name and                      Year Ended    Annual Compensation    Underlying
Principal Position             January 31,  Salary (2) Bonus (3)     Options
---------------------------    -----------  ---------- ---------   -----------

George G. Shaw                     2002     $33,000     $ --             --
   President and Chief             2001     $33,000     $ --             --
 Executive Officer                 2000     $33,000     $ --      1,000,000

(1)  The named executive  officer  received  additional  non-cash  compensation,
     perquisites and other personal benefits;  however, the aggregate amount and
     value  thereof did not exceed 10% of the total annual salary and bonus paid
     to and accrued for the named executive officer during the year.
(2)  Dollar  value of base salary  (both cash and  non-cash)  earned  during the
     year.
(3)  Dollar value of bonus (both cash and non-cash) earned during the year.



<PAGE>


AGGREGATE OPTION GRANTS AND EXERCISES IN YEAR ENDED JANUARY 31, 2002
AND YEAR-END OPTION VALUES

         During the year ended January 31, 2002 and 2001, the Company did not
grant any stock options to its executive officers. The following table sets
forth information related to the number and value of options held by George Shaw
at January 31, 2002.

                                                         Value of Unexercised
                             Number of Unexercised           In-The-Money
                                 Options as of              Options as of
                                January 31, 2002           January 31, 2002
Name                      Exercisable  Unexercisable  Exercisable  Unexercisable

George G. Shaw, President
 and Chief Executive
   Officer                     --           --             --           --


Outstanding Options and Warrants

    As of January 31, 2002 the following officers, directors, and/or principal
shareholders held options or warrants:

                     Date of     Shares Issuable   Exercise       Expiration
Name                  Grant      Upon Exercise       Price           Date
----                  -----      -------------     ------------   ------------

James H. Attarian   12-21-00       275,675 (1)        $0.32        12-21-02
James H. Attarian    4-11-01       384,550 (2)        $0.20         4-11-03

(1) Represents warrants held by Mankato Investments LLC, a company controlled by
    Dr. Attarian.
(2) Represents warrants held by Jurassic Capital LLC, a company controlled by
    Dr. Attarian.

    As of November 30, 2002 none of the options expiring in 2002 or 2003 had
been exercised.

    Subsequent to January 31, 2002 the Company has not issued any options or
warrants.

INDEMNIFICATION OF OFFICERS AND DIRECTORS

     As permitted by the provisions of the Delaware General Corporation Law, the
Company's Certificate of Incorporation  eliminates the monetary liability of its
directors  for a breach of their  fiduciary  duty as directors.  However,  these
provisions  do not eliminate  our  director's  liability (i) for a breach of the
director's duty of loyalty to us or our shareholders, (ii) for acts or omissions
by a director not in good faith or which  involve  intentional  misconduct  or a
knowing violation of law, (iii) arising relating to the declaration of dividends
and  purchase or  redemption  of shares in  violation  of the  Delaware  General
Corporation  Act,  or for any  transaction  from which the  director  derived an
improper personal benefit.


<PAGE>

      In addition, these provisions do not eliminate liability of a director for
violations of federal securities laws, nor do they limit the rights of the
Company or its shareholders, in appropriate circumstances, to seek equitable
remedies including injunctive or other forms of non-monetary relief. These
remedies may not be effective in all cases.

      The Company's bylaws require the Company to indemnify its directors and
officers. Under these provisions, when an individual in his or her capacity as
an officer or a director is made or threatened to be made, a party to any suit
or proceeding, the individual may be indemnified if he or she acted in good
faith and in a manner reasonably believed to be in or not opposed to the
Company's best interest. These bylaws further provide that this indemnification
is not exclusive of any other rights to which the individual may be entitled.
Insofar as indemnification for liabilities arising under these bylaws or
otherwise may be permitted to the Company's directors and officers, the Company
has been advised that in the opinion of the Securities and Exchange Commission
indemnification for securities law violations is against public policy and is,
therefore, unenforceable.

EMPLOYMENT AGREEMENTS AND KEYMAN INSURANCE

      The Company does not have any employment agreements with its officers or
employees. The Company does not maintain any keyman insurance on the life or in
the event of disability of any of its officers.

ITEM 11.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

     The following table presents, as of November 30, 2002,  information related
to the beneficial ownership of the Company's common stock of (i) each person who
is known to us to be the  beneficial  owner of more  than 5%,  (ii)  each of our
directors and executive  officers,  and (iii) all of our executive  officers and
directors as a group.  All persons listed have sole voting and investment  power
with respect to their shares unless otherwise indicated, and there are no family
relationships among the Company's executive officers and directors,  except that
George G. Shaw is the father of G. Scott Shaw.  For  purposes  of the  following
table,  the number of shares and percent of  ownership of the  Company's  common
stock that the named person  beneficially  owns includes shares of the Company's
common  stock that the person has the right to acquire on or before  January 31,
2003  from  exercise  of  stock  options  or  otherwise  and  are  deemed  to be
outstanding,  but are not deemed to be outstanding for the purposes of computing
the number of shares beneficially owned and percent of common stock of any other
named person.

                                                  Shares           Percent of
                                                Beneficially      Outstanding
Name (and address) of Beneficial Owner          Owned (1)         Shares (1)(2)
--------------------------------------          ---------         --------------

George G. Shaw (3)
Third Floor, 800 Northeast 63rd Street
Oklahoma City, Oklahoma 73105                   7,070,236                27%

Energas Pipeline Co., Inc. (3)
Third Floor, 800 Northeast 63rd Street
Oklahoma City, Oklahoma 73105                   7,070,236                27%



<PAGE>

                                                   Shares           Percent of
                                                Beneficially      Outstanding
Name (and address) of Beneficial Owner          Owned (1)         Shares (1)(2)
--------------------------------------          ---------         --------------

Energas Corporation (3)
Third Floor, 800 Northeast 63rd Street
Oklahoma City, Oklahoma 73105                   7,070,236                27%

James H. Attarian, M.D. (4)
230 East Main Street
Mankato, Minnesota 56002-8674                   2,900,450              10.9%

Mankato Investments LLC (4)
230 East Main Street
Mankato, Minnesota 56002-8674                   2,900,450              10.9%

Jurassic Capital LLC (4)
230 East Main Street
Mankato, Minnesota 56002-8674                   2,900,450              10.9%

Clare LLC (5)
401 South LaSalle, Suite 302
Chicago, Illinois 60605                         2,000,000               7.7%

Dennis P. Flynn (5)
401 South LaSalle, Suite 302
Chicago, Illinois 60605                         2,000,000               7.7%

G. Scott Shaw 60,000 *

David W. Young                                         --                 --

Executive Officers and Directors as a group
 (four persons) (3) (4)                        10,030,686                39%

* The shares beneficially owned represent less than 1% of the outstanding
shares.

(1)  Shares not outstanding but deemed beneficially owned by virtue of the right
     of the named person to acquire the shares within 60 days of the
     above-mentioned date are treated as outstanding for determining the amount
     and percentage of common stock owned by the person. Based upon our
     knowledge, each named person has sole voting and sole investment power with
     respect to the shares shown except as noted, subject to community property
     laws, where applicable.

(2)  The percentage shown was rounded to the nearest one-tenth of one percent,
     based upon 26,143,001 shares of common stock outstanding on November 30,
     2002.

(3)  The  beneficially  owned shares and the  percentage  include (i)  2,444,916
     shares held by Energas  Corporation of which  1,759,680 of these shares are
     subject to a time-release escrow agreement,  and (ii) 3,460,320 shares held
     by Energas Pipeline Co., Inc. are subject to a time-based  escrow agreement
     and (iii)  1,585,000  shares of common stock held by Mr.  Shaw.  The shares
     held under the escrow  agreements  will be  released  from escrow in 12 six
     month   installments   commencing  on  March  21,  2002   (initially   four
     installments   of  290,000   shares  of  common  stock  followed  by  eight
     installments of 580,000 shares of common stock).  Mr. Shaw controls Energas
     Corporation and Energas Pipeline Co., Inc.


<PAGE>

(4)  The beneficially owned shares and the percentage include (i) 1,405,675
     shares of common stock and 275,675 shares of common stock underlying common
     stock purchase warrants held and exercisable by Mankato Investments LLC,
     (ii) 384,550 shares of common stock and 384,550 shares of common stock
     underlying common stock purchase warrants held by Jurassic Capital LLC, and
     (iii) 450,000 shares held by Dr. Attarian. Dr. Attarian controls Mankato
     Investments LLC and Jurassic Capital LLC.

(5)  Clare L.L.C. is controlled by Dennis P. Flynn.

ITEM 12.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

      For legal services performed, the Company was billed during the years
ended January 31, 2002, 2001 and 2000, Cdn $42,957, $75,521 and $37,262,
respectively, by Lang Michener Lawrence & Shaw. Larry S. Hughes, a former
Director of the Company, is a member of Lang Michener Lawrence & Shaw.

      In December 2000, Mankato Investments LLC purchased 275,675 shares of
common stock and common stock purchase warrants exercisable for the purchase of
275,675 shares of common stock for $.33 per share on or before December 21,
2002. The Company received proceeds from this sale of $60,350. In April 2001,
Jurassic Capital LLC purchased 384,550 shares of common stock and common stock
purchase warrants exercisable for the purchase of 384,550 shares of common stock
for $.195 per share on or before April 11, 2003. The Company received proceeds
from this sale of $74,733. Mankato Investments LLC and Jurassic Capital LLC are
controlled by James H. Attarian, a director and principal shareholder.

      In September 2000, the Company relocated its offices to the third floor,
800 Northeast 63rd Street, Oklahoma City, Oklahoma. The office space is occupied
under an unwritten month-to-month lease requiring rental payments of $3,420 per
month to Mr. Shaw, the owner of the building. During the years ended January 31,
2002 and 2001 the Company paid rent of $40,797 and $20,520, respectively. In
addition, Mr. Shaw owns Energas Pipeline Company that operates the natural gas
gathering system to which the Company's four wells in Atoka County, Oklahoma are
connected. During the years ended January 31, 2002, 2001 and 2000, Energas
Pipeline Company received $13,765, $12,466 and $15,454, respectively, for its
services in operating the gathering system.

      As of August 31, 2002 the Company had borrowed $382,659 from George Shaw
and $360,000 Mankato Investments LLC. See Item 6 of this report for information
concerning the terms of these loans.

      During the year ended January 31, 2002 the Company issued 400,070 shares
of its common stock to Mankato Investments LLC in payment of $138,800 advanced
to the Company by Mankato Investments. The $138,800 in advances were in addition
to the $360,000 owed by the Company to Mankato.


<PAGE>

      The Company believes that the legal fees paid Lang Michener Lawrence &
Shaw, the rent paid to Mr. Shaw and the terms of the other transactions between
the Company and its officers and directors discussed above were fair and
reasonable and were upon terms as least as favorable as the Company could have
obtained from unrelated third parties.

      Transactions with the Company's officers, directors, and principal
shareholders may continue and may result in conflicts of interest between the
Company and these individuals. Although these persons have fiduciary duties to
the Company and its shareholders, there can be no assurance that conflicts of
interest will always be resolved in favor of Company and its shareholders.
Neither the Company's Articles of Incorporation nor Bylaws contain any
provisions for resolving potential or actual conflicts of interest.

ITEM 13.  EXHIBITS AND REPORTS ON FORM 8-K

Exhibits

Exhibit No.  Description of Exhibit                              Page Number

3.1   Registrant's Certificate of Incorporation                        *

3.2   Registrant's Bylaws                                              *

3.3   Registrant's Certificate of Domestication                        *

4.1   Form of Certificate of Common Stock of Registrant                *

4.2   Warrant Agreement, dated September 10, 1999 between
        Registrant and MEDICOMP.                                       *

4.3   Warrant  Agreement,  dated  October 8, 1999  between
        Registrant  and Mankato Investments, LLC                       *

4.4   Warrant  Agreement,  dated  December 13, 2000 between
        Registrant and Mankato Investments, LLC                        *

4.5   Warrant  Agreement,  dated  March 5, 2001  between
        Registrant  and  Jurassic  Capital LLC                         *

4.6   Escrow  Amendment  Agreement  amongst  Registrant,
        Pacific Corporate Trust Company, Energas Corporation
        and  Energas  Pipeline Company                                 *

4.7   Escrow Agreement, dated September 20, 1991, amongst
        Registrant, Pacific Corporate Trust Company, Energas
        Corporation  and Energas Pipeline Company                      *


<PAGE>

Exhibits

Exhibit No.  Description of Exhibit                              Page Number

4.8   Registration  Rights  Agreement, dated July 18, 2001
        between  Registrant and Clare, LLC                             *

4.9   Escrow  Amendment Agreement, dated  April 13, 1994,
        amongst  Registrant, Pacific Corporate Trust Company,
        Energas  Corporation and Energas Pipeline Company              *

10.1  Stock Purchase Agreement,  dated August 26, 2000, amongst
        Registrant,  Larry G. Jordan, Jim and  Billie  Baker,
        Keith  D.  Menees, Williard  L. and  Jeanne  O'Daniel,
        James W. and Lacada Greer Living Trust, Jack Marie Sellers,
        and Mark R. Hoy.                                               *

10.2  Amendment to Stock Purchase Agreement, dated
        September 23, 2000,  amongst Registrant, Larry G. Jordan,
        Jim and  Billie  Baker, Keith D. Menees,  Williard L.
        and Jeanne O'Daniel, James W. and  Lacada  Greer  Living
        Trust, Jack  Marie Sellers, and Mark R. Hoy.                   *

10.3  Second  Amendment  to Stock  Purchase  Agreement,  dated
        October  30,  2000, amongst  amongst  Registrant,
        Larry G. Jordan,  Jim and Billie  Baker,  Keith D. Menees,
        Williard L. and Jeanne O'Daniel,  James W. and Lacada Greer
        Living Trust,  Jack Marie Sellers, and Mark R. Hoy.            *

10.4  Third  Amendment  to  Stock  Purchase  Agreement,  dated
        November  8,  2000, amongst  amongst  Registrant,
        Larry G. Jordan,  Jim and Billie  Baker,  Keith D. Menees,
        Williard L. and Jeanne O'Daniel,  James W. and Lacada
        Greer Living Trust,  Jack Marie Sellers, and Mark R. Hoy.      *

10.5  Escrow  Agreement,  dated November 8, 2000,  amongst
        Registrant,  BancFirst,Larry  G.  Jordan,  Jim and Billie
        Baker,  Keith  D. Menees,  Willard L. and Jeanned  O'Daniel,
        James W. and Lavada Greer Living Trust,  Jack Marie Sellers,
        Mark R. Hoy and First Natural Gas, Inc.                        *

10.6  Form of  Promissory  Note issued to Larry G.  Jordan,
        Jim and Billie  Baker, Keith D.  Menees,  Larry and
        Jeanne  O'Daniel,  James W. and Lavada Greer Living
        Trust,  Jack Marie Sellers,  and Mark R. Hoy.                  *

10.7  Gas Purchase  Agreement,  dated March 1, 1991 between
        Registrant and Energas Pipeline Company.                       *



<PAGE>


Exhibits

Exhibit No.  Description of Exhibit                              Page Number

10.8  Gas Purchase  Agreement,  dated March 1, 1991 between
        Registrant and Energas Pipeline Company.                       *

10.9  Gas Gathering Agreement, dated July 1, 1992 between
        Energas Pipeline Company, Inc. and A.T. Gas Gathering
        Systems, Inc.                                                  *

10.10 Gas Purchase Agreement, dated February 13, 1997, between
        Panenergy  Field Services, Inc. and Energas Pipeline Company.  *

10.11 Gas Purchase  Agreement,  dated October 1, 1999, between
        Registrant and Ozark Gas Gathering, L.L.C.                     *

10.12   Letter agreement, dated December 30, 1996, between
         Registrant and  Conoco, Inc.                                  *

10.13 Promissory Note ($25,000) payable to Craig and Karen Aubuchon    **

10.14 Promissory Note ($50,000) payable to Mark Swan                   **

10.15 Loan Agreement ($300,000) with Mankato Investments LLC           **

10.16 Promissory Note ($60,000) payable to Mankato Investments LLC     **

16. Letter regarding change in certifying public accountant.           **

21.   Registrant's Subsidiaries                                        *

*  Incorporated by referenced to the same exhibit filed with the Company's
   initial registration statement on Form 10-SB.

** Incorporated by reference to the same exhibit filed with Amendment No. 1 to
   the Company's registration statement on Form 10-SB

      During the three months ended January 31, 2002 the Company did not file
any reports on Form 8-K.

ITEM 14.  CONTROLS AND PROCEDURES

     George Shaw, the Company's Chief Executive  Officer and David W. Young, the
Company's  Chief  Financial  Officer,  have evaluated the  effectiveness  of the
Company's  disclosure  controls and procedures as of a date within 90 days prior
to the filing date of this report (the "Evaluation  Date"); and in their opinion
the  Company's   disclosure   controls  and  procedures   ensure  that  material
information relating to the Company, including its consolidated subsidiaries, is
made known to them by others  within  those  entities,  particularly  during the
period in which this report is being prepared,  so as to allow timely  decisions

<PAGE>


regarding required disclosure.  To the knowledge of Mr. Shaw and Mr. Young there
have been no significant  changes in the Company's internal controls or in other
factors  that  could  significantly   affect  the  Company's  internal  controls
subsequent  to the  Evaluation  Date. As a result,  no  corrective  actions with
regard  to  significant  deficiencies  or  material  weakness  in the  Company's
internal controls were required.





<PAGE>











                                       ENERGAS RESOURCES INC.

                                  CONSOLIDATED FINANCIAL STATEMENTS


                                      JANUARY 31, 2002 AND 2001














<PAGE>








                             ENERGAS RESOURCES INC.

                                    CONTENTS



                                                                   Page

Independent Auditors' Report                                         1

Consolidated Balance Sheets                                          2

Consolidated Statements of Operations                                3

Consolidated Statements of Stockholders' Equity (Deficit)            4

Consolidated Statements of Cash Flows                                5

Notes to Consolidated Financial Statements                           6



















<PAGE>



                          INDEPENDENT AUDITORS' REPORT


To the Board of Directors
Energas Resources Inc.

We have audited the consolidated balance sheets of Energas Resources Inc. as of
January 31, 2002 and 2001 and the consolidated statements of operations,
stockholders' equity (deficit) and cash flows for the years then ended. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

We conducted our audits in accordance with 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 financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as of January 31, 2002
and 2001 and the results of its operations and its cash flows for the years then
ended in accordance with accounting principles generally accepted in the United
States of America.

The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed in Note 1 to the
financial statements, the Company has not generated sufficient cash flows from
operations and has suffered operating losses since inception. These conditions
raise substantial doubt about its ability to continue as a going concern.
Management's plans in this regard are also discussed in Note 1. The financial
statements do not include any adjustments that might result from the outcome of
this uncertainty.




Denver, Colorado
May 2, 2002



<PAGE>


                             Energas Resources Inc.

                           CONSOLIDATED BALANCE SHEETS


                            January 31, 2002 and 2001




                                                            2002        2001
ASSETS

Current Assets
   Cash                                                  $   2,054   $  22,547
   Accounts receivable                                       6,792      14,922
   Prepaid expenses                                            214       2,419
                                                         ---------   ---------

                Total Current Assets                         9,060      39,888
                                                         ---------   ---------



Property and equipment, net                                505,258     545,476
Other assets                                                 4,132       4,488
                                                         ---------     -------


                                                         $ 518,450   $ 589,852
                                                         =========   =========

LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)

Current Liabilities
   Accounts payable and accrued expenses                 $ 201,380    $153,981
   Due to related party and shareholder  (Note 7)          374,860     712,328
   Note payable (Notes 4 and 9)                             50,000      50,000
                                                         ---------    --------

                           Total Current Liabilities       626,240     916,309
                                                         ---------   ---------
Long-term debt
Due to shareholder (Note 7):
  Principal amount
360,000               360,000
  Less unamortized discount                                  2,312     42,241
                                                         ---------    --------
  Long-term debt less unamortized discount                 357,688    317,759
                                                         ---------    -------



STOCKHOLDERS' EQUITY

Common Stock, $.001 par value, 100,000,000 shares
  authorized 26,143,001 and 22,459,153 shares issued
  and outstanding                                           26,143       22,459
Additional Paid in Capital                               7,621,777    6,828,342
Deficit                                                 (8,113,398)  (7,495,017)
                                                        -----------  -----------

                                                          (465,478)    (644,216)
                                                          ---------    ---------
                                                         $ 518,450    $ 589,852
                                                         =========    =========




<PAGE>



                             Energas Resources Inc.

                      CONSOLIDATED STATEMENTS OF OPERATIONS


                      Years ended January 31, 2002 and 2001




                                                2002        2001
REVENUE

Oil and gas sales                            $ 104,411      $141,689
Pipeline revenue                                15,542        14,792
Gain on disposal of assets                      16,061             -
                                             ---------      --------

                                               136,014       156,481

EXPENSES

Salaries and benefits                          335,847     305,924
Depreciation and depletion                      38,192      27,903
Legal and accounting                           123,060      85,524
Write-down of oil and gas properties             6,665           -
Rent                                            45,477      54,452
Business investigation costs                         -      50,000
Oil and gas production                          23,119      27,765
Consulting                                      31,983      27,500
Office and general                              61,703      27,207
Travel and promotion                            11,549      21,771
Telephone                                       18,525      18,478
Regulatory fees                                  4,119       4,074
Pipeline costs                                   3,292       3,283
Interest expense                                50,864      47,599
                                                -------    --------
                                               754,395     702,398

NET LOSS                                     $(618,381)  $(545,917)
                                             ==========  ==========


LOSS PER SHARE - BASIC AND DILUTED           $  (0.02)   $   (0.02)
                                             =========   ==========

WEIGHTED AVERAGE SHARES OUTSTANDING         24,400,598   22,177,227
                                            ==========   ==========


<PAGE>


                             Energas Resources Inc.

             CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)


                      Years ended January 31, 2002 and 2001



                                                        Additional
                                    Common Stock         Paid In    Accumulated
                                  Shares      Amount     Capital      Deficit


Balance, January 31, 2000       22,123,478   $22,123     6,735,655  $(6,949,100)


Common stock issued for:
   Warrants exercised              60,000         60        15,859           -
   Private placement              275,675        276        60,074           -
      Warrants issued                   -          -        16,754           -
Net loss                                -          -             -    (545,917)
                                 ----------  ----------  ---------   ----------


Balance, January 31, 2001       22,459,153    22,459     6,828,342  (7,495,017)


Common stock issued for:
     Private placements          2,384,550     2,385       462,910           -
   Warrants exercised              500,000       500       114,500           -
      Settlement of debt           799,298       799       216,025           -
Net loss                                 -         -             -    (618,381)
                                 ---------   ---------     -------    ---------

Balance, January 31, 2002        26,143,001   $26,143   $7,621,777 $(8,113,398)
                                 ==========   =======   ==========  ===========




<PAGE>


                             Energas Resources Inc.

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                      Years ended January 31, 2002 and 2001

                                                      2002             2001
Cash Flows From Operating Activities

Net loss                                            $(618,381)     $ (545,917)
Add items not involving cash:
   Depreciation and depletion                          38,192          27,903
   Amortization of discount and debt issue cost        44,285          47,356
   Accrual of interest on note payable and due to
     shareholder                                        3,542               -
   Write-down of oil and gas properties                 6,665               -
   Gain on involuntary conversion of assets           (16,061)              -

Change in non-cash working capital balances
  related to operations:
   Increase (decrease) in accounts payable and
      accrued expenses                                 43,858         111,037
   Decrease in prepaid expenses                         2,205           3,934
      Increase in other assets                         (4,000)         (5,497)
   Decrease (increase) in accounts receivable           8,130          (6,347)
                                                        -----        --------

Net Cash Used in Operating Activities                (491,565)       (367,531)
                                                    -----------    -----------

Cash Flows from Financing Activities

Shares issued for:
   Private placement                                   465,295        60,350
   Warrants                                            115,000        15,919
   Options                                                   -             -
      Settlement of debt                                     -             -
   Issuance of warrants                                      -        16,754
Increase (decrease) in due to shareholder             (120,644)      244,869
Increase in note payable                                     -        50,000
Repayment of bank loan                                       -        (3,694)
                                                   ------------       ------


Net Cash Provided By Financing Activities              459,651       384,198
                                                      ---------      --------


Cash Flows From Investing Activities

Purchase of equipment                                 (14,225)       (6,272)
Proceeds on disposal of oil and gas properties              -        10,000
Proceeds from involuntary conversion of assets         25,647             -
                                                       ------        -------

Net Cash Provided By Investing Activities              11,422         3,728
                                                      -------         ------

Increase (decrease) in cash                           (20,492)       20,395

Cash, beginning of year                                22,547         2,152
                                                     --------        -------

CASH, end of year                                    $  2,054      $ 22,547
                                                     ==========   ==========

Supplemental Cash Flow Information

Cash paid for interest                              $        -     $  1,130
                                                    ==========     ========

Supplemental Disclosure of Non-cash Investing and
 Financing Activities

Issuance of stock for settlement of debt           $  216,824      $     -
                                                   ==========     ========


<PAGE>


                             Energas Resources Inc.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                      Years ended January 31, 2002 and 2001

1. NATURE OF OPERATIONS

Energas  Resources Inc.,  incorporated in British  Columbia,  Canada is a public
company listed on the Canadian Venture Exchange.

The Company is primarily engaged in the operation, development, production,
exploration and acquisition of petroleum and natural gas properties in the
United States through its wholly-owned subsidiary, A.T. Gas Gathering Systems,
Inc. ("AT GAS"). In addition, the Company owns and operates a natural gas
gathering system, located in Oklahoma, which serves the wells operated by the
Company for delivery to a mainline transmission system. All of the Company's oil
and gas properties are leased, with the exception of the natural gas gathering
system. The majority of the Company's operations are maintained and occur
through AT GAS. AT GAS is a company incorporated in the State of Oklahoma,
U.S.A.

Although the Company has taken steps to verify title to resource properties in
which it has an interest, in accordance with industry standards for the current
stage of exploration of such properties, these procedures do not guarantee the
Company's title. Property title may be subject to unregistered prior agreements
and title may be affected by undetected defects.

The Company is in the process of developing its petroleum and natural gas
properties and as of January 31, 2002 had a working capital deficiency of
$617,180 and incurred an operating loss of $618,381 for the year then ended. The
Company's ability to continue as a going concern is dependent upon achieving
profitable levels of operations and, if necessary, on the ability of the Company
to obtain necessary financing. The ability of the Company to continue operations
is contingent upon attaining profitable operations and obtaining additional debt
and/or equity capital to fund its operations. Subsequent to January 31, 2002,
the Company entered into an agreement with an unrelated party to fund specific
drilling prospects. The Company believes if they are successful in their
upcoming drilling program they will attain profitable operations. In addition,
the Company plans to raise additional funds through private placements of common
stock and/or debt.

The consolidated financial statements do not give effect to any adjustments
which would be necessary should the Company be unable to continue as a going
concern and therefore be required to realize its assets and discharge its
liabilities in the normal course of business at amounts different from those
reflected in these consolidated financial statements.

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of consolidation - The consolidated financial statements include the
accounts of the Company and its wholly-owned subsidiary, AT GAS. All significant
intercompany items have been eliminated in consolidation.

Use of estimates in the preparation of financial statements - 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 and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.

Revenue recognition - Oil and natural gas revenue is recognized at the time
title is transferred to the customer. Pipeline revenue is earned as a gathering
fee at the time the gas is gathered by the customer.

Petroleum and natural gas properties - The Company employs the full cost method
of accounting for petroleum and natural gas properties whereby all costs
relating to exploration and development of reserves are capitalized. Such costs
include land acquisition costs, geological and geophysical costs, costs of
drilling both productive and non-productive wells and related overhead.


<PAGE>

                             Energas Resources Inc.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

                      Years ended January 31, 2002 and 2001

2. SIGNIFICANT ACCOUNTING POLICIES (continued)

Capitalized costs, excluding costs relating to unproven properties, are depleted
using the unit-of-production method based on estimated proven reserves, as
prepared by an independent engineer. For the purposes of the depletion
calculation, proven reserves are converted to a common unit of measure on the
basis of their approximate relative energy content. Investments in unproved
properties are not amortized until the proved reserves associated with the
projects can be determined or until impairment occurs. If the results of an
assessment of such properties indicate that properties are impaired, the amount
of impairment is added to the capitalized cost base to be amortized.

In applying the full-cost method, the Company performs a ceiling test to ensure
that capitalized costs net of accumulated depletion do not exceed the estimated
future net revenues from production of proven reserves. The carrying value of
the properties is compared quarterly to estimated future net cash flows from
production or proven reserves. The present value of future net revenue is
estimated, using a 10% discount rate, of the future net revenue from proved
reserves, based on current prices and costs, less estimated future development
and production costs. In addition, the cost of properties not being amortized
and the lower of cost or estimated fair value of unproven properties included in
the costs being amortized is added to the present value of the future net
revenues and this amount is adjusted for the related tax effects for the
purposes of computing the ceiling. During the years ended January 31, 2002 and
2001, the Company recognized impairment of $6,665 and $0, to properly state its
capitalized costs under the full cost method.

Proceeds on disposal of properties are normally applied as a reduction of the
capitalized costs without recognition of a gain or loss, unless such amounts
would significantly alter the relationship between capitalized costs and proved
reserves of oil and gas, in which case gain or loss would be recognized.
Abandonment of properties are accounted for as adjustments of capitalized costs
with no loss recognized, unless such adjustment would significantly alter the
relationship between capitalized costs and proved reserves of oil and gas
attributable to a cost center.

Long-lived assets - The Company reviews its long-lived assets for impairment
whenever changes in circumstances indicate that the carrying amount of an asset
may not be recoverable. For purposes of evaluating the recoverability of
long-lived assets, the recoverability test is performed using undiscounted net
cash flows estimated to be generated by the asset.

Equipment - Equipment is recorded at cost and depreciated on the declining
balance basis at the following rates:

                             Computer equipment         30%
                             Truck                      30%
                             Office equipment           20%
                             Computer software         100%

Pipeline is recorded at cost and depreciated using the straight-line method over
a period of 3 years.

Environmental liabilities - The Company expenses or capitalizes environmental
costs depending on their future economic benefit. Costs that relate to an
existing condition caused by past operations with no future economic benefit are
expensed. Liabilities for future expenditures of a non-capital nature are
recorded when future environmental expenditures and/or remediation is deemed
probable and the costs can be reasonably estimated. Costs of future expenditures
for environmental remediation obligations are not discounted to their present
value. During the years ended January 31, 2002 and 2001, the Company spent
$1,304 and $12,390, respectively, on

<PAGE>


                             Energas Resources Inc.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

                      Years ended January 31, 2002 and 2001

2. SIGNIFICANT ACCOUNTING POLICIES (continued)

plugging and filling well holes, removing drilling anchors, hauling and
disposing of water and drilling mud, filling mud pits, surface leveling and
reseeding and general site clean up.

Financial instruments - The Company's financial instruments consist of cash,
accounts receivable, accounts payable, loans payable, and amounts due to
shareholder. Amounts due to shareholder and loans payable are interest free. It
is management's opinion that the Company is not exposed to significant interest,
currency or credit risk arising from its financial instruments and that their
fair values approximate their carrying values, unless otherwise noted.

Foreign currency translation - Foreign currency is translated in accordance with
Statement of Financial Accounting Standards No. 52, which provides the criteria
for determining the functional currency for entities operating in foreign
countries. The Company has determined its functional currency is the United
States (U.S.) dollar since substantially all of its operations are in U.S.
dollars. Financial statements of previous periods presented in Canadian dollars
have been translated to US dollars as follows: at rates prevailing during the
year for revenue and expense items; at year-end rates for assets and liabilities
except for fixed assets and prepaid expenses which are translated at the rate in
effect at the time of their acquisition. The net effects of currency
translations were not material in any period.

Earnings per share - The Company follows SFAS No. 128, Earnings per Share, for
computing and presenting earnings per share, which requires, among other things,
dual presentation of basic and diluted earnings per share on the face of the
statement of operations. Basic EPS is computed by dividing income available to
common shareholders by the weighted average number of common shares outstanding
for the period. Diluted EPS reflects the potential dilution that could occur if
securities, options or warrants were exercised or converted into common shares
or resulted in the issuance of common shares that then shared in the earnings of
the entity.

Stock-based compensation - In October 1995, the FASB issued SFAS No. 123,
"Accounting for Stock-Based Compensation." SFAS No. 123 encourages, but does not
require, companies to record compensation expense for stock-based employee
compensation plans at fair value. The Company has elected to account for its
stock-based compensation plans using the intrinsic value method prescribed by
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees" (APB No. 25). Under the provisions of APB No. 25, compensation cost
for stock options is measured as the excess, if any, of the quoted market price
of the Company's common stock at the date of grant over the amount an employee
must pay to acquire the stock.

Concentration - The Company sells all of its oil production and all of its gas
production to a related company, Energas Pipeline Company. Energas Pipeline
Company then resells the oil production to Conoco and gas production to Duke
Energy. The Company believes that either or both of these customers can be
replaced on a timely basis.

Cash and cash equivalents - For purposes of the statement of cash flows, the
company considers all highly liquid debt instruments purchased with a maturity
of three months or less to be cash equivalents.

Income taxes - Income taxes are accounted for under the asset and liability
method. Deferred tax assets and liabilities are recognized for future timing
differences between the financial statement carrying amounts and their
respective tax bases. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years in which
those temporary differences are expected to be recovered.

Recent pronouncements - In June 2001, The Financial Accounting Standards Board
("FASB") issued statement of Financial Accounting Standard ("SFAS") No. 141,
"Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible
Assets". SFAS 141 requires all business combinations to be accounted for using
the purchase method of accounting and is effective for all business combinations
initiated after June 30, 2001. SFAS 142

<PAGE>


                             Energas Resources Inc.

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

                      Years ended January 31, 2002 and 2001

2. SIGNIFICANT ACCOUNTING POLICIES (continued)

requires goodwill be tested for impairment under certain circumstances, and
written off when impaired, rather than being amortized as previous standards
required. The adoption of SFAS 141 and 142 did not have a material effect on the
Company's financial position or results of operations.

In August 2001, the FASB issued SFAS 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets". This statement supercedes SFAS 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of". This statement removes goodwill from the scope of SFAS 121, and requires
long-lived assets to be tested for recoverability whenever events or changes in
circumstances indicate that the carrying amount may not be recoverable. The
adoption of SFAS 144 did not have a material effect on the Company's financial
position or results of operations.

Reclassification - Certain prior year amounts have been reclassified to conform
to current year presentation.


3. PROPERTY AND EQUIPMENT
                                              Accumulated
                                             Depreciation/     Net Book Value
                                     Cost     Depletion      2002        2001
                                    ------    -----------    ----        -----

Unproved oil and gas properties   $204,213    $      -     $204,213   $ 204,213
Proved oil and gas properties      337,341      47,572      289,769     320,998
Computer equipment                   9,945         367       9,578        7,329
Truck                               24,120      24,120           -        4,923
Pipeline                            24,750      24,750           -        4,125
Office equipment                     7,626       5,928       1,698        2,688
Computer software                    2,400       2,400           -        1,200
                                 ---------   ---------   ---------   ----------
                                 $ 610,395   $ 105,137   $ 505,258    $ 545,476
                                 =========   =========   =========    =========

Oil and gas properties are accounted for using the full cost method (see note
2). Depletion was $19,564 and $21,343 for the years ended January 31, 2002 and
2001, respectively.

4. NOTE PAYABLE

In June, 2000, the Company received a loan of $50,000, which bore interest at
25%. As consideration of this loan, the Company issued warrants to purchase
50,000 shares of its stock at $1.00 per share. This note was also convertible
into common stock up to December 1, 2000. In addition, the president of the
Company pledged 200,000 shares of his own common stock of the Company as
collateral to the loan as well as personally guaranteeing the loan. The note was
due December 1, 2000 and as of January 31, 2002 this note is in default and has
subsequently been changed, see Note 10 for subsequent events.




<PAGE>


                             Energas Resources Inc.

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

                      Years ended January 31, 2002 and 2001

5. COMMON STOCK

The Company has authorized capital of 100,000,000 common shares with a $.001 par
value. The issued shares are as follows:

                                          2002                    2001
                                   Number     Amount      Number      Amount

Balance, beginning of year     22,459,153   $6,850,801  22,123,478   $6,616,570
Shares issued for:
  Private placement net
    of legal costs              2,384,550      465,295     275,675       60,350
  Warrants exercised net of
    legal costs                   500,000      115,000      60,000       15,919
  Settlement of debt              799,298      216,824           -            -
  Issuance of warrants for
    consideration of debt               -            -           -       16,754
                                ----------     -------     --------    --------

Balance, end of year            26,143,001  $7,647,920   22,459,153  $6,850,801

In September 2000, warrants were exercised to purchase 60,000 shares of common
stock at $.27 per share or $15,919.

In December 2000, the Company issued 275,675 shares of common stock and 275,675
warrants to purchase common stock through a private placement for $.22 per share
or $60,350. The warrants expire two years from issuance.

During the year ended 1/31/01, warrants were issued as consideration for debt.
The warrants were valued at fair value of $16,754.

In April 2001, the Company issued 384,550 shares of common stock and warrants to
purchase 384,550 shares of common stock at $.195 for $74,733 in a private
placement. These warrants expire April 1, 2003.

In June 2001, the Company issued 400,070 shares of common stock for the relief
of debt of the Company's subsidiary due to a related party in the amount of
$138,800.

In July 2001, the Company had a private placement and issued 2,000,000 shares
for $390,562.

On September 12, 2001, the Company issued 399,228 shares of common stock for the
relief of $78,024 of debt.

In October 2001, a related party exercised warrants to purchase 500,000 shares
of common stock in relief of debt of the Company's subsidiary in the amount of
$115,000.

Options and warrants - The Company has issued stock options to directors and
employees and stock warrants as follows:


<PAGE>


                             Energas Resources Inc.

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

                      Years ended January 31, 2002 and 2001

<TABLE>
<S>            <C>          <C>          <C>         <C>         <C>            <C>
                        Outstanding   Granted    Exercised   Outstanding
             Exercise    January 31,     or          or       January 31,     Expiration
             Price          2000     (Cancelled)   Expired       2001            date
------------------------------------------------------------------------------------------

Options:
              $0.17      1,835,000          -          -      1,835,000     August 24, 2001
Warrants:
              $0.27         50,000          -    (50,000)             -     January 18, 2001
              $0.27         60,000          -    (60,000)             -     April 1, 2001
              $0.23        500,000          -          -        500,000     October 13, 2001
              $0.27         50,000          -          -         50,000     October 22, 2001
              $0.31              -     25,000          -         25,000     August 31, 2001
              $0.32              -    275,675          -        275,675     December 21, 2002

</TABLE>

 <TABLE>
<S>            <C>          <C>          <C>         <C>         <C>            <C>
                        Outstanding   Granted     Exercised    Outstanding
             Exercise    January 31,     or          or       January 31,     Expiration
             Price          2001     (Cancelled)   Expired       2002            date
------------------------------------------------------------------------------------------

Options:      $0.17      1,835,000         -    (1,835,000)            -     August 24, 2001
Warrants:
              $0.23        500,000         -      (500,000)            -     October 13, 2001
              $0.27         50,000         -       (50,000)            -     October 22, 2001
              $0.31         25,000         -       (25,000)            -     August 31, 2001
              $0.32        275,675         -             -       275,675     December 21, 2002
              $0.195             -   384,550             -       384,550     April 7, 2003

</TABLE>

There were no options  granted for  compensation  during the years ended January
31, 2002 and 2001.

6. RELATED PARTY TRANSACTIONS

The Company had oil and gas sales and pipeline revenue of $119,953 and $156,481
during the years ended January 31, 2002 and 2001 from Energas Pipeline Company
("EPC"), which is owned by the President of the Company. EPC purchases oil and
gas at the wellhead from the Company, generating oil and gas sales, and then
resells to Conoco and Duke Energy. EPC also pays a gathering fee to the Company,
generating pipeline revenue.

The Company incurred oil and gas production and pipeline costs to Energas Corp.,
a company owned by the President of the Company, in the amounts of $26,411 and
$31,048 for the years ended January 31, 2002 and 2001.

In addition, the Company leases office space on a month-to-month basis from Shaw
Construction Company, owned by the President of the Company, and incurred rent
expense in the amount of $45,477 and $17,100 during the years ended January 31,
2002 and 2001.




<PAGE>


                             Energas Resources Inc.

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

                      Years ended January 31, 2002 and 2001

7. DUE TO RELATED PARTY AND SHAREHOLDER

The Company has an amount due to related party of $349,860 and $687,328 at
January 31, 2002 and 2001, respectively. These amounts represent advances from a
company controlled by the president and director of the Company that are
non-interest bearing with no fixed terms of repayment. While the loan has no
terms of repayment, the related party has indicated it will not require
repayment within the next fiscal year.

On February 13, 1999 the Company entered into a loan agreement with a related
party to borrow US $300,000. The loan is non-interest bearing and repayable on
the earlier of 3 years from the date the funds were advanced or 30 days after
the funds have been utilized for pre-drilling costs on 10 separate oil and gas
prospects and initial test wells have been commenced on each prospect. In the
event the loan is not repaid on its due date, interest at 12% per annum will
become chargeable. In consideration for the loan the Company will render a 10%
working interest in certain prospects and has issued 60,000 share purchase
warrants. On September 6, 2000, the 60,000 warrants were exercised at $.27 per
share. The 10% working interest was to be given on certain wells that were
drilled using the loan proceeds. Three of these such wells were dry and the
fourth well had marginal production. These wells were then sold for no gain or
loss; therefore, no portion of the note payable was allocated to the 10% working
interest or the warrants.

During the year ended January 31, 2001, the Company received additional advances
of $60,000 from this related party. The advances are secured by a promissory
note, which is non-interest bearing, and due May 13, 2002.

In August 2000, the Company received a shareholder loan of $25,000 which bears
interest at 10%. As consideration for this loan, the Company issued a warrant to
purchase 25,000 shares of its stock at $0.31 per share. This note is due August
2002.

8.  LONG-TERM DEBT

Long-term debt at January 31, 2001 and 2000 consisted of the following:

                                               2001                 2000
                                                Unamortized          Unamortized
                                       Principal  Discount   Principal  Discount

  Non-interest bearing note due
February 13, 2002 (discount is based
on imputed interest rate of 12%)       $300,000  $ 300,000   $ 32,542   $    --

  Non-interest bearing note due May
13,2002 (discount is based on imputed
interest rate of 12%)                    60,000    60,000       2,312     9,699
                                        --------  -------      ------     -----

  Long-term debt and unamortized
     discount                           360,000    $2,312     360,000    42,241
                                        =======   ========    =======    ======


9.  INCOME TAXES

The  Company has  approximately  $5,264,905  of net  operating  losses  expiring
through 2022 which may be used to offset future taxable income,  but are subject
to various  limitations imposed by rules and regulations of the Internal Revenue
Service. The net operating losses are limited each year to offset future taxable
income,  if any,  due to the change of ownership  in the  Company's  outstanding
shares of common  stock.  In addition,  at January 31, 2002,  the Company had an
unused Canadian net operating loss carry-forward of approximately  $395,576 USD,
expiring  through 2008.  These net operating loss  carry-forwards  may result in
future  income  tax  benefits  of  approximately  $2,176,697;  however,  because
realization  is uncertain  at this time, a valuation  reserve in the same amount


<PAGE>


                             Energas Resources Inc.

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

                      Years ended January 31, 2002 and 2001

has been  established.  Deferred  income  taxes  reflect  the net tax effects of
temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax purposes.

Significant components of the Company's deferred tax liabilities and assets as
of January 31, 2002 and 2001 are as follows:


                                                2002        2001
         ------------------------------------------------------------
         Deferred tax liabilities          $       --   $        --
                                           ==========   ===========
         Deferred tax assets
           Net operating losses            $2,167,697  $  2,210,633
           Valuation allowance for
             deferred tax assets           (2,167,697)   (2,210,633)
                                           ----------   ------------
                                           $       --   $         --
                                           ==========   ============


The valuation allowance decreased $42,936 and increased $267,405 for the period
ending January 31, 2002 and 2001, respectively.

10.  SUBSEQUENT EVENTS

In March, 2002 the Company signed a promissory note in the amount of $60,000
bearing interest at 12% in payment of the note payable of $50,000 in default
discussed in Note 4. On March 15, 2002, the Company began paying $5,000 a month
plus interest until the note is paid in full.

11. COMMITTMENTS AND CONTINGENCIES

The Company is subject to federal, state and local laws and regulations
governing environmental quality and pollution control. During the years ended
January 31, 2002 and 2001, the Company spent $1,304 and $12,390, respectively,
on plugging and filling well holes, removing drilling anchors, hauling and
disposing of water and drilling mud, filling mud pits, surface leveling and
reseeding and general site clean up. Although the Company believes that
compliance with environmental regulations will not have a material adverse
effect on its operations or results of these operations, risks of substantial
costs and liabilities are inherent in oil and gas operations, and there can be
no assurance that significant costs and liabilities, including criminal
penalties, will not be incurred. Through the date of this report, the Company
has no asserted or unasserted environmental claims, therefore, no liability has
been accrued in the accompanying balance sheets.

The Company is in disagreement with a shareholder who advanced funds to both the
Company and an entity related to the Company as to the outstanding balances owed
to the shareholder. The shareholder is claiming additional amounts owed of
$300,000 to $400,000 related to this matter. The outcome of this matter cannot
presently be determined.



<PAGE>




                             ENERGAS RESOURCES INC.

                      SUPPLEMENTAL INFORMATION (UNAUDITED)

                      Years ended January 31, 2002 and 2001


                                                          2002         2001

-------------------------------------------------------------------------------
Capitalized Costs Relating to Oil and Gas Producing
Activities at January 31,

Unproved oil and gas properties                         $ 204,213   $ 204,213
Proved oil and gas properties                             337,341     424,184
Support equipment and facilities                                -           -
                                                         --------   ---------
                                                          541,554     628,397

Less accumulated depreciation, depletion, amortization,
   and impairment                                         (47,572)    (103,186)
                                                         ---------    ---------
         Net capitalized costs                          $ 493,982     $525,211
                                                        =========     ========

Costs Incurred in Oil and Gas Producing Activities
For the Year Ended January 31,

Property acquisition costs
      Proved                                            $      --     $     --
      Unproved                                                 --           --
Exploration costs                                              --           --
Development costs                                              --           --
Amortization rate per equivalent barrel of production   $    5.32     $   3.76

Results of Operations for Oil and Gas Producing
Activities
For the Year Ended January 31,

Oil and gas sales                                        $ 104,411    $141,689
Gain on sale of oil and gas properties                          --          --
Gain on sale of oil and gas leases                              --          --
Production costs                                           (23,119)    (27,765)
Exploration expenses                                            --          --
Depreciation, depletion, and amortization                  (26,229)    (21,343)
                                                           --------    --------
                                                            55,063      92,581

Income tax expense                                              --          --
                                                            ------      ------
Results of operations for oil and gas producing
  activities (excluding corporate overhead and
  financing costs)                                        $ 55,063     $92,581

<PAGE>


                             ENERGAS RESOURCES INC.

                      SUPPLEMENTAL INFORMATION (UNAUDITED)

                      Years ended January 31, 2002 and 2001


The following estimates of proved and proved developed reserve quantities and
related standardized measure of discounted net cash flow are estimates only, and
do not purport to reflect realizable values or fair market values of the
Company's reserves. The Company emphasizes that reserve estimates are inherently
imprecise and that estimates of new discoveries are more imprecise than those of
producing oil and gas properties. Accordingly, these estimates are expected to
change as future information becomes available. All of the Company's reserves
are located in the United States.

Proved reserves are estimated reserves of crude oil (including condensate and
natural gas liquids) and natural gas that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed reserves are those expected to be recovered through existing wells,
equipment, and operating methods.

The standardized measure of discounted future net cash flows is computed by
applying year-end prices of oil and gas (with consideration of price changes
only to the extent provided by contractual arrangements) to the estimated future
production of proved oil and gas reserves, less estimated future expenditures
(based on year-end costs) to be incurred in developing and producing the proved
reserves, less estimated future income tax expenses (based on year end statutory
tax rates, with consideration of future tax rates already legislated) to be
incurred on continuation of existing economic conditions. The estimated future
net cash flows are then discounted using a rate of 10 percent a year to reflect
the estimated timing of the future cash flows.




<PAGE>


                             ENERGAS RESOURCES INC.

                      SUPPLEMENTAL INFORMATION (UNAUDITED)


                                        2002                      2001
                                        ----                      ----
                                      Oil        Gas         Oil         Gas
                                    (Bbls)      (Mcf)       (Bbls)      (Mcf)
Proved developed and undeveloped
reserves
  Beginning of year                  8,909     730,441      9,382      761,640
  Revisions of previous estimates        -           -          -            -
  Improved recovery                      -           -          -            -
  Purchases of minerals in place         -           -          -            -
  Extensions and discoveries             -           -          -            -
  Production                        (2,067)    (17,179)      (473)     (31,199)
 Sales of minerals in place             -           -          -            -
                                    -------    --------      -----     --------
End of year                          6,842     713,262      8,909      730,441
                                    ======     =======      =====      =======
Proved developed reserves
  Beginning of year                  8,909     730,441      9,382      761,640
  End of year                        6,842     713,262      8,909      730,441



                                                     2002           2001
Standardized Measure of Discounted Future
  Net cash flows
  Future cash inflows                            $ 1,763,748    $ 2,195,177
  Future production costs                           (425,642)      (675,710)
  Future development costs                                 -              -
  Future income tax expenses                               -              -
                                                  ----------      ----------
                                                   1,338,106      1,519,467
  Future net cash flows                             (844,124)      (994,256)
    10% annual discount for estimated timing
       of cash flows
Standardized measures of discounted future net
  cash flows relating to proved oil and gas
   reserves                                       $  493,982      $ 525,211
                                                 ============    ==========

The following reconciles the change in the standardized measure of
discounted future net cash flow during 2002.

Beginning of year                                 $  525,211     $  547,246

Sales of oil and gas produced, net of
   production costs                                 (100,016)      (113,924)
Net changes in prices and production costs           (56,652)       (21,250)
Extensions, discoveries, and improved recovery,
     less related costs                                    -              -
Development costs incurred during the year which
     were previously estimated                             -              -
Net change in estimated future development costs           -              -
Revisions of previous quantity estimates             (91,875)       143,431
Net change from purchases and sales of minerals
   in place                                                -              -
Accretion of discount                                 52,744         54,725
Net change in income taxes                                 -              -
Other                                                164,570        (85,017)
                                                   ---------      ----------
End of year                                       $  493,982      $ 525,211
                                                  ==========      =========

<PAGE>


                                   SIGNATURES

    In accordance with Section 13 or 15(a) of the Exchange Act, the Registrant
has caused this Report to be signed on its behalf by the undersigned, thereunto
duly authorized on the 6th day of December, 2002.

                                  ENERGAS RESOURCES, INC.

                                  By  /s/  George G. Shaw
                                      --------------------------------------
                                      George G. Shaw, President and Chief
                                       Executive Officer

                                  By /s/ David W. Young
                                     ----------------------------
                                     David W. Young, Chief Financial Officer

    Pursuant to the requirements of the Securities Act of l934, this Report has
been signed below by the following persons on behalf of the Registrant and in
the capacities and on the dates indicated.

                                     Title                    Date

/s/ George G. Shaw
----------------------
George G. Shaw                      Director             December 6, 2002


/s/ G. Scott Shaw
----------------------
G. Scott Shaw                       Director             December 6, 2002


/s/ David W. Young
----------------------
David W. Young                      Director             December 6, 2002


---------------------
James H. Attarian                   Director             December 6, 2002

                                  CERTIFICATION

     In connection with the Annual Report of Energas Resources, Inc. (the
"Company") on Form 10-KSB for the year ended January 31, 2002 as filed with the
Securities and Exchange Commission on the date hereof (the "Report"), we, George
G. Shaw, the President and Chief Executive Officer and David W. Young, the Chief
Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350,
as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to
the best of our knowledge:

(1)  The Report fully complies with the  requirements  of Section 13(a) or 15(d)
     of the Securities Exchange Act of 1934; and

(2)  The information  contained in the Report fairly  presents,  in all material
     respects the financial condition and results of the Company.

Date:  December 6, 2002
                                 By: /s/ George G. Shaw
                                     --------------------------
                                     George G. Shaw, President and Chief
                                      Executive Officer

                                    /s/ David W. Young
                                    ----------------------------
                                    David W. Young, Chief Financial Officer


<PAGE>


                          CERTIFICATION PURSUANT TO THE
                               SARBANES-OXLEY ACT

I, George Shaw, the Chief Executive Officer of Energas Resources,  Inc., certify
that:

1. I have reviewed this annual report on Form 10-KSB of Energas Resources, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. I am responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the
registrant and have:

   a) designed such disclosure controls and procedures to ensure that material
      information relating to the registrant, including its consolidated
      subsidiaries, is made known to me by others within those entities,
      particularly during the period in which this annual report is being
      prepared;

   b) evaluated the effectiveness of the registrant's disclosure controls and
      procedures as of a date within 90 days prior to the filing date of this
      annual report (the "Evaluation Date"); and

   c) presented in this annual report my conclusions about the effectiveness of
      the disclosure controls and procedures based on my evaluation as of the
      Evaluation Date;

5. I have disclosed, based on my most recent evaluation, to the registrant's
auditors and the audit committee of registrant's board of directors (or persons
performing the equivalent functions):

   a) all significant deficiencies in the design or operation of internal
      controls which could adversely affect the registrant's ability to record,
      process, summarize and report financial data and have identified for the
      registrant's auditors any material weaknesses in internal controls; and

   b) any fraud, whether or not material, that involves management or other
      employees who have a significant role in the registrant's internal
      controls; and

6. I have indicated in this annual report whether there were significant changes
in internal controls or in other factors that could significantly affect
internal controls subsequent to the date of my most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.

Date: December 6, 2002               /s/ George Shaw
                                     -----------------------------
                                     George Shaw, Chief Executive Officer


<PAGE>


                          CERTIFICATION PURSUANT TO THE
                               SARBANES-OXLEY ACT

I, David W.  Young,  the Chief  Financial  Officer of Energas  Resources,  Inc.,
certify that:

1. I have reviewed this annual report on Form 10-KSB of Energas Resources, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. I am responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the
registrant and have:

   a) designed such disclosure controls and procedures to ensure that material
      information relating to the registrant, including its consolidated
      subsidiaries, is made known to me by others within those entities,
      particularly during the period in which this annual report is being
      prepared;

   b) evaluated the effectiveness of the registrant's disclosure controls and
      procedures as of a date within 90 days prior to the filing date of this
      annual report (the "Evaluation Date"); and

   c) presented in this annual report my conclusions about the effectiveness of
      the disclosure controls and procedures based on my evaluation as of the
      Evaluation Date;

5. I have disclosed, based on my most recent evaluation, to the registrant's
auditors and the audit committee of registrant's board of directors (or persons
performing the equivalent functions):

   a) all significant deficiencies in the design or operation of internal
      controls which could adversely affect the registrant's ability to record,
      process, summarize and report financial data and have identified for the
      registrant's auditors any material weaknesses in internal controls; and

   b) any fraud, whether or not material, that involves management or other
      employees who have a significant role in the registrant's internal
      controls; and

6. I have indicated in this annual report whether there were significant changes
in internal controls or in other factors that could significantly affect
internal controls subsequent to the date of my most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.

Date: December 6, 2002               /s/ David W. Young
                                     -----------------------------
                                     David W. Young, Chief Financial Officer