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, 2006
                                       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 if the Company is not required to file  reports  pursuant to Section 13 or
15(d) of the Exchange Act [ ]

Check whether the Company (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, 2006 were $1,197,252

Indicate by check mark whether the Company is a shell company (as defined in
Rule 12b-25 of the Exchange Act):        Yes [ ] No [X]

The aggregate market value of the voting stock held by non-affiliates of the
Company, (36,483,731 shares) based upon the closing price of the Company's
common stock on May 4, 2006 was approximately $13,134,000.

As of May 4, 2006 the Company had 58,498,881 outstanding shares of common stock.

Documents incorporated by reference:      None


<PAGE>

            CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING NFORMATION

         This report includes "forward-looking statements". All statements other
than statements of historical facts included in this report, 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.



<PAGE>


                                    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.

      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.


                                       3
<PAGE>

      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 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.


                                       4
<PAGE>

      (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.

ITEM 1. DESCRIPTION OF BUSINESS The Company was 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 is involved in the exploration and development of oil and gas.
The Company's activities are primarily dependent upon available financial
resources to fund the costs of drilling and completing wells.

     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

                                       5
<PAGE>


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 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.

            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. The Company's web site is www.energasresources.com.

PRINCIPAL AREAS OF OPERATION

            The Company principally operates in the Arkoma Basin in Oklahoma,
the Powder River Basin in Wyoming and the Appalachian Basin of Eastern Kentucky.

            As of March 1, 2006 the Company had 4 gas wells in the Arkoma Basin
which were producing approximately 452 Mcf of gas per day.

      The Company's oil and gas production in the Powder River Basin are
attributable to two wells in Rusty Creek Prospect in Niobrara County, Wyoming.
The Company does not intend to drill any additional wells on this prospect. As
of March 1, 2006, the Company's two wells in the Rusty Creek Prospect produced
approximately 16 barrels of crude oil per day.

      In August 2003 the Company acquired 31 producing wells with a gathering
system, compressor stations, plus developed and undeveloped acreage. All of the
acquired properties are located in the Appalachian Basin of eastern Kentucky.
The Kentucky properties were acquired from three private corporations for
$3,000,000 in convertible notes. In March 2004 the Company paid $100,000, plus
interest, on one of the notes and holders of notes with a remaining principal
amount of $2,400,000 converted their notes into 4,800,000 shares of the
Company's common stock. The remaining note bore interest at 8.5% per and was due
in August 2023. On August 25, 2005 the Company issued 1,250,000 shares of its
common stock in full payment of the remaining note which had a principal balance
on that date of $479,218.

      Since August 2003 the Company has completed an additional 39 wells in
eastern Kentucky. In addition, the Company has acquired more leases in others
areas of eastern Kentucky that contain multiple wells. Of those wells, 4 have
been transferred under the Company's operating bond. As of May 10, 2006 the
Company's wells in Kentucky were producing approximately 310 Mcf of gas per day
and 6 barrels of oil per day.

DRILLING ACTIVITIES AND PROVEN RESERVES

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


                                       6
<PAGE>

                                         Year Ended January 31,
                            ------------------------------------------------
                                 2004            2005              2006
                                 ----            ----              ----
                            Gross    Net    Gross     Net     Gross     Net
Exploratory Wells (1):
  Productive:
   Oil                        --      --       --       --       --      --
   Gas                         1    .875        1     .137       --      --
   Nonproductive               1       1       --       --        1     .24

Development Wells (1):
  Productive:
   Oil                        --      --        1     .137        1    .137
   Gas                         6    5.25       27    9.625        3   2.625
  Nonproductive               --      --       --       --        1    .137

Total Wells (1):
  Productive:
   Oil                        --      --        1     .137        1    .137
   Gas                         7   6.125       28    9.762        3   2.625
  Nonproductive                1       1       --       --        2    .377

(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.

      In May 2003 the Company arranged with a private investor to fund the
drilling of two natural gas wells in the Arkoma Basin of eastern Oklahoma. The
two wells were drilled in June 2003 and one well was successfully completed as a
gas well and the other well was a dryhole. The Company will receive
approximately 5% of the production from the productive well, after payment of
the Company's share of operating expenses, until the investor is repaid the
amounts advanced to drill and complete the wells, which were approximately
$490,000. After the amount advanced by the investor has been repaid, the Company
will receive approximately 25% of the production from the well after payment of
the Company's share of operating expenses

      The following table shows, as of April 30, 2006, by state and basin, the
Company's producing wells, Developed Acreage, and Undeveloped Acreage, excluding
service (injection and disposal) wells:

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

   Oklahoma       4        1.5            --          --       --          --
   Wyoming        2        .75            80          32    7,085    4,356.07
   Kentucky      74       63.7         1,440       1,250   13,853      12,100
   Kansas         3        .41            --          --       --          --
                ---       ----         -----      ------   ------    --------
       Totals    79      66.36         1,520       1,282   20,938   16,456.07
                 ==      =====         =====       =====   ======   =========

                                       7
<PAGE>

(1)  The wells in Oklahoma  and  Kentucky 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 following table shows, as of May 1, 2006 the status of Company's gross
developed and undeveloped acreage.

      Gross Acreage           Held by Production     Not Held by Production

      Oklahoma                         640                      --
      Wyoming                          640                   6,526
      Kentucky                      12,120                   3,053
      Kansas                           480                   3,884

      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 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.

      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:                2004        2005         2006
                                ----        ----         ----
   Production -
      Oil (Bbls)                 950       4,008         2,962
      Gas (Mcf)              143,616      106,276      130,748
   Average sales price -
      Oil (Bbls)         $     28.62     $  39.06     $  50.16
      Gas (Mcf)          $      4.86     $   5.33     $   7.96
   Average production
       costs per MCF    $       3.74     $   2.49     $   3.49


                                       8
<PAGE>

      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 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.

      Below are estimates of the Company's net Proved 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 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.

<TABLE>
<S>                          <C>       <C>      <C>      <C>         <C>      <C>
                                               January 31,
                           -------------------------------------------------------
                                  2004                2005                2006
                           -----------------    -----------------   --------------
                            Oil        Gas       Oil       Gas         Oil        Gas
                           (Bbls)     (Mcf)     (Bbls)    (Mcf)     (Bbls)      (Mcf)

Proved reserves             73,790   4,394,959  30,398  2,181,471   41,180    1,764,909
Estimated future net cash
   flows from proved oil
   and  gas reserves          $12,908,072          $7,164,199          $8,227,331

Present value of future net
  cash flows from proved
  oil and gas reserves         $5,510,762          $4,337,635          $4,992,059
</TABLE>

      The Company's Proved Reserves 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
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


                                       9
<PAGE>

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.

GOVERNMENT REGULATION

      Various state and federal agencies regulate the production and sale of oil
and natural gas. All states in which the Company operated impose restrictions on
the drilling, production, transportation and sale of oil and natural gas.

      Under the Natural Gas Act of 1938, the Federal Energy Regulatory
Commission (the "FERC") regulates the interstate transportation and the sale in
interstate commerce for resale of natural gas. The FERC's jurisdiction over
interstate natural gas sales has been substantially modified by the Natural Gas
Policy Act under which the FERC continued to regulate the maximum selling prices
of certain categories of gas sold in "first sales" in interstate and intrastate
commerce.

      Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act
(the "Decontrol Act") deregulated natural gas prices for all "first sales" of
natural gas. Because "first sales" include typical wellhead sales by producers,
all natural gas produced from the Company's natural gas properties is sold at
market prices, subject to the terms of any private contracts which may be in
effect. The FERC's jurisdiction over natural gas transportation is not affected
by the Decontrol Act.

     The  Company's  sales of natural  gas will be affected  by  intrastate  and
interstate gas  transportation  regulation.  Beginning in 1985, the FERC adopted
regulatory  changes  that have  significantly  altered  the  transportation  and
marketing  of natural  gas.  These  changes  are  intended by the FERC to foster
competition by, among other things, transforming the role of interstate pipeline
companies  from  wholesale  marketers  of natural gas to the primary role of gas
transporters.  All natural gas  marketing by the pipelines is required to divest
to a marketing affiliate,  which operates separately from the transporter and in
direct competition with all other merchants.  As a result of the various omnibus
rulemaking   proceedings  in  the  late  1980s  and  the   individual   pipeline
restructuring  proceedings of the early to mid-1990s,  the interstate  pipelines
must    provide     open    and     nondiscriminatory     transportation     and
transportation-related   services  to  all  producers,   natural  gas  marketing
companies,  local  distribution  companies,   industrial  end  users  and  other
customers seeking service. Through similar orders affecting intrastate pipelines
that provide similar interstate  services,  the FERC expanded the impact of open
access regulations to intrastate commerce.

     More  recently,  the FERC has pursued  other policy  initiatives  that have
affected natural gas marketing. Most notable are (1) the large-scale divestiture
of  interstate   pipeline-owned  gas  gathering   facilities  to  affiliated  or
non-affiliated  companies;  (2)  further  development  of  rules  governing  the
relationship  of  the  pipelines  with  their  marketing  affiliates;   (3)  the
publication of standards  relating to the use of electronic  bulletin boards and
electronic  data  exchange by the  pipelines  to make  available  transportation
information  on a timely basis and to enable  transactions  to occur on a purely


                                       10
<PAGE>

electronic  basis;  (4) further  review of the role of the secondary  market for
released  pipeline  capacity and its  relationship to open access service in the
primary  market;  and (5)  development  of  policy  and  promulgation  of orders
pertaining to its  authorization of market-based  rates (rather than traditional
cost-of-service  based  rates)  for  transportation  or   transportation-related
services  upon the  pipeline's  demonstration  of lack of market  control in the
relevant service market.  The Company does not know what effect the FERC's other
activities will have on the access to markets,  the fostering of competition and
the cost of doing business.

      As a result of these changes, sellers and buyers of natural gas have
gained direct access to the particular pipeline services they need and are
better able to conduct business with a larger number of counter parties. The
Company believes these changes generally have improved the access to markets for
natural gas while, at the same time, substantially increasing competition in the
natural gas marketplace. The Company cannot predict what new or different
regulations the FERC and other regulatory agencies may adopt or what effect
subsequent regulations may have on production and marketing of natural gas from
the Company's properties.

      In the past, Congress has been very active in the area of natural gas
regulation. However, as discussed above, the more recent trend has been in favor
of deregulation and the promotion of competition in the natural gas industry.
Thus, in addition to "first sales" deregulation, Congress also repealed
incremental pricing requirements and natural gas use restraints previously
applicable. There are other legislative proposals pending in the Federal and
State legislatures which, if enacted, would significantly affect the petroleum
industry. At the present time, it is impossible to predict what proposals, if
any, might actually be enacted by Congress or the various state legislatures and
what effect, if any, these proposals might have on the production and marketing
of natural gas by the Company. Similarly, and despite the trend toward federal
deregulation of the natural gas industry, whether or to what extent that trend
will continue or what the ultimate effect will be on the production and
marketing of natural gas by the Company cannot be predicted.

     The  Company's  sales of oil and natural gas liquids are not  regulated and
are at market prices. The price received from the sale of these products will be
affected  by the cost of  transporting  the  products  to  market.  Much of that
transportation is through interstate common carrier pipelines.  In 1995 the FERC
implemented   regulations  generally   grandfathering  all  previously  approved
interstate  transportation  rates and  establishing an indexing system for those
rates by which  adjustments  are made  annually  based on the rate of inflation,
subject to certain  conditions and  limitations.  These  regulations may tend to
increase  the cost of  transporting  oil and natural  gas liquids by  interstate
pipeline,  although the annual  adjustments  may result in decreased  rates in a
given year.  These  regulations have generally been approved on judicial review.
Every five  years,  the FERC will  examine the  relationship  between the annual
change in the  applicable  index and the actual cost changes  experienced by the
oil pipeline  industry.  The Company is not able to predict with  certainty what
effect, if any, these relatively new federal  regulations or the periodic review
of the index by the FERC will have on the Company.


                                       11
<PAGE>

      Federal, state, and local agencies have promulgated extensive rules and
regulations applicable to the Company's oil and natural gas exploration,
production and related operations. Most states require permits for drilling
operations, drilling bonds and the filing of reports concerning operations and
impose other requirements relating to the exploration of oil and natural gas.
Many states also have statutes or regulations addressing conservation matters
including provisions for the unitization or pooling of oil and natural gas
properties, the establishment of maximum rates of production from oil and
natural gas wells and the regulation of spacing, plugging and abandonment of
such wells. The statutes and regulations of some states limit the rate at which
oil and natural gas is produced from the Company's properties. The federal and
state regulatory burden on the oil and natural gas industry increases the
Company's cost of doing business and affects its profitability. Because these
rules and regulations are amended or reinterpreted frequently, the Company is
unable to predict the future cost or impact of complying with those laws.

COMPETITION AND MARKETING

      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.

      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. Higher prices for oil and gas may result in 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. However, the Company has not experienced and does not
anticipate difficulty in obtaining supplies, materials, drilling rigs, equipment
or tools.

      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 market for oil and gas is 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.

                                       12
<PAGE>

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
production quotas among themselves for petroleum products from time to time with
the intent of  controlling  the current  global  supply and  consequently  price
levels.  The Company is unable to predict the effect, if any, that OPEC or other
countries will have on the amount of, or the prices  received for, crude oil and
natural gas produced and sold from the Company's wells.

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

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.

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

     As of May 1, 2006, the Company employed 10 people. The Company's  employees
work in management,  engineering,  geology,  land and legal and  accounting.  In
addition,  3 contract workers were responsible for the supervision and operation
of the Company's field activities and providing well services.


                                       13
<PAGE>

ITEM 2.  DESCRIPTION OF PROPERTY
      See Item 1 of this report for information concerning the Company's oil and
gas properties.

            The Company's offices are located at 800 Northeast 63rd Street,
Oklahoma City, Oklahoma and consist of 4,800 square feet which is rented on a
month-to-month basis for $3,800 per month. The building is owned by George G.
Shaw, the Company's Chief Executive Officer and a Director.

ITEM 3.  LEGAL PROCEEDINGS

      In March 2005 Double G Energy, Inc. filed a lawsuit against the Company
and the Company's officers in the District Court for Dallas County, Texas. In
its complaint Double G Energy alleges that: (i) in 2004 it entered into an
agreement with the Company to drill and complete wells on the Company's field in
Pulaski County, Kentucky, (ii) the Company failed to comply with its obligations
under the agreement, and (iii) the Company and its officers made a number of
misrepresentations concerning the drilling program.

      Double G's complaint asked for unspecified actual and punitive damages
against the Company. The Company has denied the allegations in Double G's
complaint and in July 2005 the Texas District Court ordered the Company and
Double G Energy to submit their disputes to binding arbitration.

      In May 2005 Double G Energy filed a lawsuit against the Company in
Kentucky with claims similar to those in the Texas proceeding. In August 2005
the Kentucky court ordered the Company and Double G Energy to submit their
disputes to binding arbitration.

      In December 2005 the Company and Double G Energy reached a settlement
concerning Double G's claims. In accordance with the terms of the settlement
agreement:

o    Double G assigned  to the  Company  all of its  interest in the oil and gas
     properties acquired from the Company.

o    The Company  agreed to pay Double G $1,000,000,  of which $250,000 was paid
     in December  2005 and the  remainder of which will be paid in seven monthly
     installments of $100,000,  beginning  January 31, 2006 with a final payment
     of $50,000 due on August 31, 2006.

      In June 2005 Mankato Investments, LLC filed a petition against the Company
in the District Court of Oklahoma County, Oklahoma. The petition asked for a
determination that Mankato had an interest in four of the Company's oil and gas
properties and that the Company provide Mankato with an accounting of all
revenues and expenses associated with these properties. The Company paid $20,000
in full settlement of Mankato's claims.


                                       14
<PAGE>

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 listed on the OTC Bulletin Board under the
symbol EGSR. The following table shows the high and low sale prices of the
Company's common stock during the periods presented as reported by the NASD. The
closing sale prices reflect inter-dealer prices without adjustment for retail
markups, markdowns or commissions and may not reflect actual transactions.

                                               Closing Sale Price
                                                 Common Stock
            Quarter Ended                    High           Low

            April 30, 2003                   $0.21          $0.05
            July 31, 2003                    $0.46          $0.15
            October 31, 2003                 $0.30          $0.11
            January 31, 2004                 $0.26          $0.15

            April 30, 2004                   $0.52          $0.21
            July 31, 2004                    $0.60          $0.36
            October 31, 2004                 $0.80          $0.48
            January 31, 2005                 $0.77          $0.42

            April 30, 2005                   $0.32          $0.30
            July 31, 2005                    $0.28          $0.27
            October 31, 2005                 $0.40          $0.38
            January 31, 2006                 $0.57          $0.54

      As of May 12, 2006 there were were approximately 1,000 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.

     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

                                       15
<PAGE>

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.

      During the year ended January 31, 2006 neither the Company, any officer or
director of the Company, nor any principal shareholder purchased any shares of
the Company's common stock either from the Company, from third parties in a
private transaction, or as a result of purchases in the open market.

Other Shares Which May Be Issued

      As of May 12th, 2006 the Company had 58,498,881 outstanding shares of
common stock.

      The following table lists additional shares of the Company's common stock
which may be issued as the result of the exercise of outstanding options and
warrants:

                                                         Number of       Note
                                                          Shares      Reference

   Shares issuable upon exercise of warrants:             714,286          A

   Shares issuable pursuant to Equity Line of Credit      Unknown          B

A.   In September 2005, the Company sold 714,286 shares of common stock and
714,286 warrants to one private investor for $200,000. Each warrant entitles the
holder to purchase one share of the Company's common stock at a price of $0.50
per share. The warrants expire on September 30, 2007. As of April 30, 2006 none
of the warrants had been exercised.

B.   On September 20, 2004, the Company entered into an equity line of credit
agreement with Dutchess Private Equities Fund II, L.P. in order to provide a
source of funding for the Company. The equity line of credit agreement
establishes what is sometimes also referred to as an equity drawdown facility.
The number of shares of common stock which will ultimately be issued under the
equity line of credit agreement between the Company and Dutchess Private
Equities is unknown.

      Under the equity line of credit agreement, Dutchess Private Equities has
agreed to provide the Company with up to $10,000,000 of funding during a
thirty-six month period beginning September 24, 2004. During this period, the
Company may request a drawdown under the equity line of credit by selling shares
of its common stock to Dutchess Private Equities and Dutchess Private Equities
will be obligated to purchase the shares. The Company is under no obligation to
request any drawdowns under the equity line of credit.

      The Company may request a drawdown by sending a drawdown notice to
Dutchess Private Equities, stating the amount of the drawdown.

                                       16
<PAGE>

    The amount that the Company can request in any drawdown notice is, at its
election, either:

o    up to 200% of the average  daily volume of the  Company's  common stock for
     the ten trading days prior to the date of the drawdown notice multiplied by
     the average of the three daily closing bid prices for the Company's  common
     stock immediately preceding the date of the drawdown notice; or

o    $50,000;

provided  that the Company may not request  more than  $1,000,000  in any single
drawdown.

      On the day of the drawdown notice, a pricing period of five trading days
will begin. At the end of the pricing period Dutchess Private Equities will
purchase from the Company that number of share determined by dividing the lesser
of:

o    the amount in the drawdown notice, or

o    an amount equal to 20% of the total number of the  Company's  shares traded
     during the pricing period multiplied by the lowest closing bid price of the
     Company's common stock during the pricing period

by ninety-five percent (95%) of the lowest closing bid price of the Company's
common stock during the pricing period.

      However, if any closing bid price of the Company's common stock during the
pricing period is less than ninety percent (90%) of the average closing bid
price of the Company's common stock during the ten trading days prior to the
date of the drawdown notice, the Company may elect, by sending written notice to
Dutchess Private Equities, to withdraw the drawdown, in which case no shares
will be sold during the pricing period.

      The Company may request drawdowns every seven trading days but only if the
shares sold during the prior pricing period have been paid for and issued.

      As of January 31, 2006 the Company had received net proceeds of
approximately $788,247 from the sale of 1,589,698 shares of common stock under
the equity line of credit.

      The shares referred to in Notes A and B are being, or will be, offered for
public sale by means of separate registration statements which have been filed
with the Securities and Exchange Commission.

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

     The following  discussion of financial  condition and results of operations
should be read in conjunction with the consolidated financial statements and the
notes to the consolidated financial statements,  which are included elsewhere in
this report.

                                       17
<PAGE>

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
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:                  2004            2005           2006
                                  ----            ----           ----
   Production -
      Oil (Bbls)                   950            4,008         2,962
      Gas (Mcf)                143,616          106,276       130,748
   Average sales price -
      Oil (Bbls)              $  28.62         $  39.06      $  50.16
      Gas (Mcf)               $   4.86         $   5.33      $   7.96
   Average production
       costs per MCF          $   3.74         $   2.49      $   3.49


      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.

      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.

      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.

YEAR ENDED JANUARY 31, 2006

      Material changes of certain items in the Company's Statement of Operations
for the year ended January 31, 2006, as compared to the year ended January 31,
2005, are discussed below:

                                       18
<PAGE>

                          Increase (I)
Item                   or Decrease (D) Reason

Oil and Gas Sales          I   Increase in gas and oil prices.

Lease Operating Expense    I   Increase in production  and  operating  costs
                               for gas gathering system

Depreciation, Depletion    I   As of January 31, 2006 the Company's investment
   and Amortization            investment  in  its  proved  developed  oil and
                               gas properties exceeded the present value of the
                               future net cash flows from these  properties by
                               approximately  $520,048. Under generally accepted
                               accounting principles, the net carrying value of
                               proved natural gas and oil properties  cannot
                               exceed the  discounted  future net cash flows
                               from these properties. Accordingly, $520,048 was
                               recorded as additional depreciation and
                               amortization during the year.

Interest Expense           D   Conversion of debt into common stock.


YEAR ENDED JANUARY 31, 2005

    Material changes of certain items in the Company's Statement of Operations
for the year ended January 31, 2005, as compared to the year ended January 31,
2004, are discussed below:

                       Increase (I)
Item                or Decrease (D)Reason

Oil and Gas Sales            I         Increase in the price of oil and gas.

Lease                                  Operating Expenses I Workover of 22 wells
                                       in Kentucky and increase in gas
                                       production.

Settlement                             Expense I Settlement of lawsuit with
                                       former director and his affiliates. See
                                       Note 5 to the financial statements
                                       included as part of this report.

Interest Expense              D        Reduction in interest-bearing liabilities

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


                                       19
<PAGE>

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.

      The Company's results of operations 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.

CAPITAL RESOURCES AND LIQUIDITY

     The Company's material sources and (uses) of cash during the year ended
January 31, 2006 were:

      Cash used in operations                                $ (  74,719)
      Borrowing from related parties                             205,682
      Sale of common stock                                     2,169,773
      Repayment of notes                                         (10,647)
      Loan proceeds                                            1,269,087
      Sale of oil and gas properties                              28,535
      Purchase of equipment and oil and gas properties        (3,195,628)

                                       20
<PAGE>

    The Company's material sources and (uses) of cash during the year ended
January 31, 2005 were:

      Cash used in operations                               $   (376,088)
      Repayment of loans from related parties                 (1,131,010)
      Sale of common stock                                     3,204,014
      Repayment of notes                                        (222,119)
      Sale of oil and gas properties                             318,812
      Purchase of equipment and oil and gas properties        (1,682,892)


      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.

      In August 2003 the Company acquired 31 producing gas wells, a pipeline,
compressor stations and approximately 23,000 leased and 8,500 optioned acres
from three private corporations for $3,000,000 in convertible notes. In March
2004 the Company paid $100,000, plus interest, on one of the notes and holders
of notes in the principal amount of $2,400,000 converted their notes into
4,800,000 shares of the Company's common stock. The remaining note bore interest
at 8.5% per year and was due in August 2023. On August 25, 2005 the Company
issued 1,250,000 shares of its common stock in full payment of the remaining
note which had a principal balance on that date of $479,218.

      Between January 1, 2004 and June 30, 2004 the Company sold 5,000,000
shares of common stock and 5,000,000 warrants to private investors for
$1,500,000. Each warrant entitled the holder to purchase one share of the
Company's common stock at a price of $0.50 per share. The warrants expired on
January 31, 2006. As of January 31, 2006 warrants to purchase 3,506,000 shares
had been exercised and the remaining warrants had expired.

      In August 2005 the Company sold 1,200,000 shares of its common stock to
four private investors for $300,000.

      In August 2005 George G. Shaw, the Company's President, converted $326,000
which he had loaned to the Company into 1,304,000 shares of the Company's common
stock.

     In  September  2005 the  Company  sold  714,286  share of common  stock and
714,286 warrants to one private investor for $200,000. Each warrant entitles the
holder to purchase one share of the  Company's  common stock at a price of $0.50
per share.

                                       21
<PAGE>

      In December 2005 the Company sold 578,000 shares of its common stock to
five private investors for $306,340.

Contractual Obligations

      Except as shown in the following table, as of January 31, 2006, the
Company did not have any material capital commitments, other than funding its
operating losses and repaying outstanding debt. 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.

      Future payments due on the Company's contractual obligations as of January
31, 2006 are as follows:

                       Total         2007     2008-2009    2010-2011  Thereafter

Notes payable       $ 619,087      289,690      390,576         0         0
Operating leases    $  31,983       18,286        9,154     4,543         0
                    ---------   ----------   ----------    ------      -----

Total               $ 651,070      307,976      399,730     4,543
                    =========   ==========   ==========     =====


ITEM 7.  FINANCIAL STATEMENTS

      See the financial statements attached to this report.

ITEM 8.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS.
------------------------------------------------------

      Not Applicable

ITEM 8A.  CONTROLS AND PROCEDURES

     George Shaw, the Company's Chief Executive and Principal Financial Officer,
has  evaluated  the  effectiveness  of the  Company's  disclosure  controls  and
procedures  as of the  end of the  period  covered  by this  report;  and in his
opinion the Company's disclosure controls and procedures are effective to ensure
that material  information  relating to the Company,  including its consolidated
subsidiaries, is made known to him by others within those entities, particularly
during the period in which this report is being prepared,  so as to allow timely
decisions  regarding  required  disclosure.  There  have been no  changes in the
Company's internal controls over financial reporting that occurred subsequent to
the date of evaluation that have matertially  affected, or are reasonably likely
to materially affect,  the Company's internal control over financial  reporting.
As a result,  no corrective  actions with regard to significant  deficiencies or
material weakness in the Company's internal controls were required.

                                       22
<PAGE>

ITEM 8B.  OTHER INFORMATION

      Not Applicable

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

      The Company's executive officers and directors are listed below. 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       75       President,  Principal Financial Officer, Principal
                              Accounting Officer and a Director

G. Scott Shaw        35       Vice President, Secretary and a 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,  Principal  Financial  Officer,  Principal
Accounting  Officer and a director of the Company.  Mr. Shaw has been an officer
and director of the Company  since July 1991.  Mr. Shaw is the  President of the
Company  Corporation  and its  subsidiary the Company  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.

     G. SCOTT SHAW is the Vice  President  and a director of the Company and has
held these positions since August 1996. Mr. Shaw became the Company's  Secretary
in April 2003. Mr. Shaw graduated from Oklahoma State  University in 1993 with a
Bachelor of Science degree in Biology. Mr. Shaw is the son of George G. Shaw.

     The Company does not have a compensation committee.  The Company's Board of
Directors serves as the Company's Audit  Committee.  Prior to his resignation as
an officer  and  director  of the  Company in June 2005,  David W. Young was the
Company's  financial expert.  Since Mr. Young was an officer and director of the
Company, Mr. Young was not independent as that term is defined Section 121(A) of
the Listing  Standards of the American Stock Exchange.  Mr. Young is a certified
public  accountant  and since 1981 Mr.  Young has had his own public  accounting
firm.

                                       23
<PAGE>

      The Company has adopted a Code of Ethics which is applicable to the
Company's principal executive, financial, and accounting officers and persons
performing similar functions. The Code of Ethics is available on the Company's
website located at www.energasresources.com

ITEM 10.  EXECUTIVE COMPENSATION

      The following table shows the compensation during the three years ended
January 31, 2006, paid or accrued, to George G. Shaw, the Company's Chief
Executive Officer during those years. None of the Company's executive officers
received compensation in excess of $100,000 during the three years ended January
31, 2006.
                                                                  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             2006       $36,000
President and Chief
Executive Officer          2005       $36,000
                           2004       $34,000           --              --

(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.

    The following shows the amounts which the Company expects to pay to its
officers during the twelve month period ending January 31, 2007, and the time
which the Company's executive officers plan to devote to the Company's business.
The Company does not have employment agreements with any of its officers.

                                 Proposed              Time to Be Devoted
Name                          Compensation            To Company's Business

George G. Shaw                   $78,000                      100%
G. Scott Shaw                    $60,000                      100%

     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.


                                       24
<PAGE>

STOCK OPTION AND BONUS PLANS

      Incentive Stock Option Plan. The Company's Incentive Stock Option Plan
authorizes the issuance of up to 2,000,000 shares of the Company's common stock
to persons that exercise options granted pursuant to the Plan. Only Company
employees may be granted options pursuant to the Incentive Stock Option Plan.
The option exercise price is determined by the Company's Board of Directors but
cannot be less than the market price of the Company's common stock on the date
the option is granted.

      Non-Qualified Stock Option Plan. The Company's Non-Qualified Stock Option
Plan authorizes the issuance of up to 1,000,000 shares of the Company's common
stock to persons that exercise options granted pursuant to the Plans. The
Company's employees, directors, officers, consultants and advisors are eligible
to be granted options pursuant to the Plans, provided however that bona fide
services must be rendered by such consultants or advisors and such services must
not be in connection with the offer or sale of securities in a capital-raising
transaction. The option exercise price is determined by the Company's Board of
Directors.

      Stock Bonus Plan. The Company's Stock Bonus Plan allows for the issuance
of up to 4,000,000 shares of common stock. Such shares may consist, in whole or
in part, of authorized but unissued shares, or treasury shares. Under the Stock
Bonus Plan, the Company's employees, directors, officers, consultants and
advisors are eligible to receive a grant of the Company's shares, provided
however that bona fide services must be rendered by consultants or advisors and
such services must not be in connection with the offer or sale of securities in
a capital-raising transaction.

      The following table shows the weighted average exercise price of the
outstanding options granted pursuant to the Company's Incentive and
Non-Qualified Stock Option Plans as of January 31, 2006. The Company's Incentive
and Non-Qualified Stock Option Plans were not approved by the Company's
shareholders.
                                                           Number of Securities
                                                           Remaining Available
                           Number                          For Future Issuance
                        of Securities                          Under Equity
                        to be Issued    Weighted-Average    Compensation Plans
                        Upon Exercise   Exercise Price of  (Excluding Securities
                        of Outstanding   of Outstanding       Reflected in
Plan Category            Options  [a]       Options            Column (a))
------------------------------------------------------------------------------

Incentive Stock                 --             --              2,000,000
   Option Plan
Non-Qualified Stock
   Option Plan                  --             --                750,000

     The following  table provides  information as of April 30, 2006  concerning
the stock  options  and stock  bonuses  granted by the  Company  pursuant to the
Plans.  Each option  represents the right to purchase one share of the Company's
common stock.

                                       25
<PAGE>

                                Total        Shares                  Remaining
                                Shares    Reserved for  Shares        Options/
                               Reserved   Outstanding   Issued As      Shares
Name of Plan                  Under Plans   Options    Stock Bonus  Under Plans
------------                  ----------- -----------  -----------  -----------

Incentive Stock Option Plan   2,000,000         --          N/A      2,000,000
Non-Qualified Stock Option
   Plan                       1,000,000         --          N/A        750,000
Stock Bonus Plan              4,000,000        N/A    2,036,981      1,963,019

     The  following  table  summarizes  the  options and stock  bonuses  granted
pursuant to the Plans as of April 30, 2006:

Incentive Stock Options

                                                                  Options
  Shares Subject    Exercise     Date of      Expiration       Exercised as of
    To Option         Price       Grant     Date of Option    June   30, 2005
  --------------    ---------    --------   -------------      --------------

                                      None.

Non-Qualified Stock Options

                                                                  Options
  Shares Subject    Exercise     Date of      Expiration       Exercised as of
    To Option         Price       Grant     Date of Option          2006
  --------------    ---------    --------   -------------      ---------------

     250,000          $0.32      6-30-03       7-15-05            250,000

Stock Bonuses

     Name             Shares Issued as Stock Bonus       Date Issued

George Shaw                      100,000                   10/30/03
Scott Shaw                       100,000                   10/30/03
Employees and consultants      1,836,981                   various dates
                               ---------
                               2,036,981

Other Warrants and Convertible Securities

     See Item 5 of this  report for  information  concerning  other  outstanding
options and warrants.


                                       26
<PAGE>

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

     The following  table shows the ownership of the common stock of the Company
as of April 30,  2006 by (i) each  person who is known to the  Company to be the
beneficial owner of more than 5% the Company's common stock,  (ii) each director
and  executive  officer of the  Company,  and (iii) all  executive  officers and
directors  of the Company 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 executive officers and directors of
the  Company,  except that  George G. Shaw is the father of G. Scott  Shaw.  For
purposes  of the table,  the number of shares and  percent of  ownership  of the
common stock that the named person  beneficially  owns includes  shares that the
person has the right to acquire on or before June 30, 2006 from the  exercise of
stock options or otherwise.

                                                 Shares          Percent of
                                              Beneficially      Outstanding
Name and address                                 Owned            Shares
----------------                              ------------     ------------

George G. Shaw                                 8,118,356 (1)          13.9%
Third Floor, 800 Northeast 63rd Street
Oklahoma City, Oklahoma 73105

G. Scott Shaw                                    718,385              1.2%
800 Northeast 63rd Street
Oklahoma City, Oklahoma 73105

Terry R. and Marguerite S. Tyson               8,792,800             15.0%
16250 County Rd. U
Lipscomb, TX  79056-6304

Patrick J. Retzer                              4,385,609 (2)          7.5%
19547 210th Ave. N.E.
Thief River Falls, MN 56701

Executive Officers and Directors as a group    8,836,741             15.1%
 (two persons)

(1)  Includes  (i)  2,024,916  shares  held by  Energas  Corporation,  of  which
     1,759,680 of these shares are subject to a time-release  escrow  agreement,
     (ii) 3,460,320  shares held by Energas Pipeline Co., Inc. which 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.

                                       27
<PAGE>

(2)  Includes  1,242,286  shares held by the Patrick and Lauri  Living Trust and
     714,286 shares issuable upon the exercise of warrants.

ITEM 12.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

      The Company's offices are located at 800 Northeast 63rd Street, Oklahoma
City, Oklahoma. The office space is occupied under an unwritten month-to-month
lease requiring rental payments of $3,800 per month to George Shaw, the owner of
the building. During the years ended January 31, 2006, 2005 and 2004 the Company
paid rent of $45,600 $45,600 and $61,803, 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, 2006, 2005 and 2004 Energas Pipeline Company
received $14,495, $14,322 and $16,592, respectively, for operating the gathering
system.

      As of April 30, 2005 the Company had borrowed $305,350 from George Shaw.
These loans were non-interest bearing, unsecured, and did not have fixed terms
of repayment. The amounts borrowed from Mr. Shaw were used to fund the Company's
operations. In May 2005 Mr. Shaw converted the $305,350 owed to him into
1,221,400 restricted shares of the Company's common stock.

      As of January 31, 2006 the Company had borrowed $114,324 from Mr. Shaw.
These loans are non-interest bearing, unsecured, and do not have fixed terms of
repayment. The amounts borrowed from Mr. Shaw were used to fund the Company's
operations.

      The Company believes that 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.

      In September 2003 the Company agreed to sell 2,000,000 shares of its
common stock to Terry Tyson, now a principal shareholder of the Company, for
$0.15 a share. For each share purchased the Company agreed to issue one warrant
to Mr. Tyson. For each warrant exercised, the Company agreed to issue a second
warrant to Mr. Tyson. Each warrant entitled Mr. Tyson to purchase one share of
the Company's common stock at a price of $0.20 per share at any time on or
before December 31, 2004 and at a price of $0.30 per share at any time after
December 31, 2004. All warrants expired on September 30, 2005. As of September
30, 2005 Mr. Tyson had purchased 2,000,000 shares from the Company and had
exercised 4,000,000 warrants. Since May 2004 Mr. Tyson has purchased additional
shares of the Company's common stock in open market transactions or from other
shareholders in privately negotiated transactions.

     During the six months  ended June 30,  2004,  the  Company  sold  5,000,000
shares  of  common  stock  and  5,000,000  warrants  to  private  investors  for
$1,500,000.  Each  warrant  entitled  the  holder to  purchase  one share of the
Company's  common  stock  at a price  of $0.50  per  share at any time  prior to
January 31, 2006. As of January 31, 2006 warrants to purchase  3,506,000  shares

                                       28
<PAGE>

had been exercised and the remaining warrants had expired. Terry Tyson purchased
600,000 shares of common stock and 600,000  warrants in this offering,  of which
120,000 warrants were exercised.

      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

Exhibit
  No.   Description of Exhibit                                Page Number

3.1     Certificate of Incorporation                               *

3.2     Bylaws                                                     *

3.3     Certificate of Domestication in Delaware                   *

4.1     Form of Certificate of Common Stock                        *

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

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

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

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

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

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

                                       29
<PAGE>

Exhibit
  No.    Description of Exhibit                                Page Number

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.        *

21.     Registrant's Subsidiaries                                   *

23.     Consent of Accountants                                    _____

31.     Rule 13a-14(a)/15d-14(a) certifications                   _____

32.     Section 1350 certifications                               _____

*  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 the Company's report
   on Form 8-K dated June 27, 2005.

      During the three months ended January 31, 2006 the Company did not file
any reports on Form 8-K.

ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES

      Murrell, Hall, McIntosh & Co., PLLP served as the Company's independent
public accountants during the fiscal years ended January 31, 2006 and 2005. The
following table shows the aggregate fees billed to the Company during the years
ended January 31, 2006 and 2005 by Murrell, Hall, McIntosh & Co., PLLP.

                                               2006             2005
                                               ----             ----

      Audit Fees                            $75,831.35      $7,766.75
      Audit-Related Fees                            --             --
      Financial Information Systems                 --             --
      Design and Implementation Fees                --             --
      Tax Fees                                      --             --
      All Other Fees                                --             --

                                       30
<PAGE>

    Audit fees represent amounts billed for professional services rendered for
the audit of the Company's annual financial statements and the reviews of the
financial statements included in the Company's 10-Q reports during the fiscal
year. Before Murrell, Hall, McIntosh & Co., PLLP was engaged by the Company to
render audit services, the engagement was approved by the Company's Board of
Directors.


























<PAGE>



             Report of Independent Registered Public Accounting Firm



To the Board of Directors
Energas Resources, Inc.

We have audited the accompanying consolidated balance sheet of Energas
Resources, Inc. and its subsidiaries as of January 31, 2006, and the related
consolidated statements of operations, changes in stockholders' equity, and cash
flows for the years ended January 31, 2006 and 2005. 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 the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
consolidated financial statements are free of material misstatement. The Company
is not required to have, nor were we engaged to perform, an audit of its
internal control over financial reporting. Our audit included consideration of
internal control over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of the Company's internal control
over financial reporting. Accordingly, we express no such opinion. An audit also
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the consolidated financial statements, assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Energas Resources,
Inc. and its subsidiaries as of January 31, 2006, and the consolidated results
of its operations and its consolidated cash flows for the years ended January
31, 2006 and 2005 in conformity with accounting principles generally accepted in
the United States of America.

The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As discussed in Note 2 to the
financial statements, the Company has suffered recurring losses from operations
and had a working capital deficit of $(651,341) at January 31, 2006, which raise
substantial doubt about its ability to continue as a going concern. Management's
plans regarding those matters also are described in Note 2. The financial
statements do not include any adjustments that might result from the outcome of
this uncertainty.

/s/ Murrell, Hall, McIntosh & Co., PLLP

April 28, 2006
Oklahoma City, Oklahoma


<PAGE>
                             ENERGAS RESOURCES, INC.
                           CONSOLIDATED BALANCE SHEET
                                January 31, 2006


                                     ASSETS

Current Assets
  Cash                                                          $ 580,109
  Accounts receivable                                             192,356
  Prepaid expenses                                                  8,484
  Equipment held for resale                                       185,000
  Oil and gas properties held for resale                           97,438
                                                                ---------
     Total Current Assets
                                                                1,063,387
                                                               ----------
Property and Equipment
 Oil and gas properties, using full cost accounting
 Proved properties                                              6,545,443
 Unproved properties                                              144,483
 Pipelines, of which $729,637 were under construction           1,481,585
                                                              -----------
                                                                8,171,511
 Less accumulated depreciation, depletion, and
 amortization, including impairment of $520,048                (1,697,867)
                                                              -----------
                                                                6,473,644
 Other, net of accumulated depreciation of $74,720                  5,967
                                                               ----------
                                                                6,479,611
                                                               ----------
Total Assets                                                   $7,542,998
                                                              ===========

      LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)

Current Liabilities
 Accounts payable and accrued expenses                        $   612,262
 Due to shareholders and related parties                          189,324
 Settlement Payable                                               650,000
 Other current liablilites                                         11,992
 Current portion of long-term debt                                251,150
   Total Current Liabilities                                      1,714,728

Long-term Debt less current portion shown above                   367,937

Asset Retirement Obligation                                        96,756

Stockholders' Equity (Deficit) Common stock, $.001
  par value 100,000,000 shares authorized 58,231,966
  shares issued and outstanding at January 31, 2006                58,232
Additional paid in capital                                     18,103,125
Retained earnings (deficit)                                   (12,797,780)
                                                              -----------
Total Stockholders' Equity                                      5,363,577
                                                              -----------
Total Liabilities and Stockholders' Equity                     $7,542,998
                                                              ===========


     See accompanying summary of accounting policies and notes to financial
statements.


                                      F-1
<PAGE>

                             ENERGAS RESOURCES, INC.
                      CONSOLIDATED STATEMENTS OF OPERATIONS


                                                    Years ending January 31,
                                                    2006                 2005
                                                    ----                 ----
Revenue
  Oil and gas sales                             $1,183,118           $ 653,475
  Pipeline revenue                                  14,134              15,015
                                                 ---------           ---------
  Total Revenue                                  1,197,252             668,490

Operating Expenses
  Lease operating expense                          517,534             324,150
  General and administrative expense             1,141,348           1,142,971
  Depreciation, depletion and amortization       1,065,710             283,941
                                                 ---------           ---------
  Total Operating Expenses                       2,724,592           1,751,062
                                                 ---------           ---------

Operating (Loss)                                (1,527,340)         (1,082,572)
                                                -----------         ----------

Other (Expenses) Income
  Other Income                                         347              16,675
  Settlement expense                               (21,500)            (31,264)
  Interest expense                                 (35,008)            (67,014)
                                                -----------         ----------
  Total Other (Expense)                            (56,161)            (81,603)
                                                 ----------         ----------

Net (Loss) before Income Taxes                  (1,583,501)         (1,164,175)

Provision for income taxes                              --                  --
                                                 ---------         -----------

Net (Loss)                                     $(1,583,501)        $(1,164,175)
                                               ============        ============

Net (Loss) per Share, Basic and Diluted        $     (0.03)              (0.03)
                                               ============        ============

Weighted average of number of shares
   outstanding                                   52,513,509         41,251,753
                                               ============        ===========







                 See accompanying summary of accounting policies
                       and notes to financial statements.


                                      F-2
<PAGE>

                             ENERGAS RESOURCES, INC.
                 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
                    FOR THE YEARS ENDED JANUARY 31, 2006 AND
                                JANUARY 31, 2005

<TABLE>
<S>                                    <C>       <C>              <C>            <C>            <C>
                                                               Additional                        Total
                                        Common Stock            Paid-In       Accumulated    Shareholders'
                                    Shares        Amount        Capital        Deficit      Equity (Deficit)

Balance, January 31, 2004         33,163,001    $  33,163     $ 8,644,157    $ (10,050,104)   $  (1,372,784)

Net loss                                  --           --              --       (1,164,175)      (1,164,175)
Private placement of stock         5,000,000        5,000       1,495,000               --        1,500,000
Conversion of notes payable
  to stock                         4,800,000        4,800       2,395,200               --        2,400,000
Stock issued in settlement of
  litigation                         350,000          350          69,650               --           70,000
Options issued in settlement of
  litigation                              --           --          31,500               --           31,500
Stock issued for equity line of
  credit                             959,786          960         562,154               --          563,114
Stock issued for consulting
  services                         1,150,000        1,150         585,350               --          586,500
Warrants exercised for common
  stock                            3,975,000        3,975       1,136,925               --        1,140,900
Stock bonus                          250,000          250          37,250               --           37,500
Employee stock plan                   12,848           13           7,987               --            8,000
                                   ---------       ------       ---------    -------------     ------------

Balance, January 31, 2005         49,660,635       49,661      14,965,173      (11,214,279)       3,800,555

Net loss                                  --           --              --       (1,583,501)      (1,583,501)

Stock issued for equity line of
  credit                             629,912          630         224,503               --         225,133
Options exercised for common
  stock                               40,000           40          12,760               --          12,800
Warrants exercised for common
  stock                            2,251,000        2,251       1,123,249                        1,125,500
Private placement of stock         2,492,286        2,492         803,848               --         806,340
Conversion of notes payable to
  stock                            1,250,000        1,250         473,750               --         475,000
Conversion related party note
  payable to stock                 1,304,000        1,304         324,696               --         326,000
Stock issued for consulting
  services                           100,000          100          39,900               --          40,000
Employee stock plan                  504,133          504         135,246               --         135,750
                                ------------      -------       ---------     ------------      ----------
Balance, January 31, 2006         58,231,966       58,232      18,103,125      (12,797,780)      5,363,577
                                ============     =========     ==========     ============      ==========
</TABLE>

     See accompanying summary of accounting policies and notes to financial
statements.

                                      F-3
<PAGE>

                             ENERGAS RESOURCES, INC.
                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                              Years ending
                                                              January 31,
                                                       ------------------------
                                                           2006         2005
                                                       ------------------------

Cash Flows From Operating Activities
    Net (Loss)                                        $(1,583,501)   (1,164,175)
    Adjustments to reconcile net loss to net cash
      provided by operating activities
         Depreciation, depletion and amortization         545,662       283,941
         Full cost pool impairment                        520,048
         Stock issued for salaries                        135,750        45,500
         Stock issued for consulting                       40,000       586,500
         Stock issued for settlement                           --        70,000
         Stock options issued for settlement                   --        31,500
        (Increase) Decrease in
            Accounts receivable                            20,856       (60,882)
            Prepaid expense                                (8,484)
        Increase (Decrease) in
             Accounts payable and accrued expenses        227,907      (215,908)
             Other assets                                  17,086       (17,086)
             Notes payable                                     --        (1,500)
         Asset retirement obligation                        9,957        66,022
                                                        ---------     ---------
      Net Cash Flows (Used By) Operating Activities       (74,719)     (376,088)
Cash Flows From Investing Activities
    Proceeds from sale of oil and gas properties           28,535       318,812
    (Investment in) oil and gas properties             (2,044,420)   (1,682,892)
    (Purchase of) property and equipment               (1,151,208)           --
                                                      -----------    -----------
        Net Cash (Used by) Investing Activities        (3,167,093)   (1,364,080)

Cash Flows from Financing Activities
    Advances from (Repayments of) related party and
       stockholders                                       205,682    (1,131,010)
     Sale of common stock                               2,169,773     3,204,014
     Payments on Notes Payable                            (10,647)     (222,119)
     Loan proceeds                                      1,269,087            --
                                                       ----------    ----------
        Net Cash Provided by Financing Activities       3,633,895    1,850,885

Increase in Cash                                          392,083      110,717
Cash at Beginning of Year                                 188,026       77,309
                                                        ---------    ---------
Cash at End of Period                                  $  580,109   $ 188,026
                                                       ==========    =========
Supplemental Information:
    Interest Paid in Cash                              $    7,264   $       --
    Non-Cash Transactions:
        Long-term debt converted into 2,554,000 and
        4,800,000 shares of common stock                  801,000    2,400,000
        Advances from shareholder settled for
            350,000 common stock                       $       --   $   70,000
            250,000 stock options                      $       --   $   31,500
            40,000 options for common stock            $   12,800   $       --
        Stock issued for consulting fees               $   40,000   $  586,500
        Stock issued for salaries                      $  135,750   $   45,500
        Asset Retirement Obligation                    $    8,224   $   66,022

     See accompanying summary of accounting policies and notes to financial
statements.


                                      F-4
<PAGE>

                             ENERGAS RESOURCES, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                      YEARS ENDED JANUARY 31, 2006 AND 2005

1.  NATURE OF OPERATIONS

Energas Resources, Inc. (the "Company") was originally incorporated in 1989 in
British Columbia, Canada as a public company listed on the Canadian Venture
Exchange. In 2001, the Company registered as a Delaware corporation becoming a
United States domestic corporation. In 2002, its registration statement filed
with the Securities and Exchange Commission became effective and its stock is
traded in the Over the Counter (OTC) market.

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 subsidiaries, A.T. Gas Gathering Systems,
Inc. ("AT GAS"), and TGC, Inc. ("TGC"). In addition, the Company owns and
operates natural gas gathering systems, located in Oklahoma and Kentucky, which
serve wells operated by the Company for delivery to a mainline transmission
system. The majority of the Company's operations are maintained and occur
through AT GAS and TGC. AT GAS is a company incorporated in the state of
Oklahoma, U.S.A. and TGC is a company incorporated in the state of Kentucky.

2.  GOING CONCERN

The Company is in the process of acquiring and developing petroleum and natural
gas properties with adequate production and reserves to operate profitability.
As of January 31, 2006, it had a working capital deficiency of $(651,341) and
incurred losses for the fiscal years ended January 31, 2006 and 2005 of
$(1,583,501) and $(1,164,175) respectively. The Company's ability to continue as
a going concern is dependent upon obtaining financing and achieving profitable
levels of operations. The Company is currently seeking additional funds and
additional mineral interests through private placements of equity and debt
instruments. There can be no assurance that its efforts will be successful.

The consolidated financial statements do not give effect to any adjustments that
might be necessary if the Company is unable to continue as a going concern.

3.  SIGNIFICANT ACCOUNTING POLICIES

Basis of consolidation - The consolidated financial statements include the
accounts of the Company and its wholly-owned subsidiaries, AT Gas and TGC. All
significant inter-company 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

                                      F-5
<PAGE>

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 delivered to 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.

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 an assessment of such
properties indicates that properties are impaired, the amount of impairment is
added to the capitalized cost base to be amortized.

Under the full cost method, the net book value of natural gas and oil
properties, less related deferred income taxes, may not exceed a calculated
"ceiling". The ceiling is the estimated after-tax future net revenue from proved
natural gas and oil properties, discounted at 10% per annum plus the lower of
cost or fair market value of unproved properties. In calculating future net
revenues, prices and costs in effect at the time of the calculation are held
constant indefinitely, except for changes that are fixed and determinable by
existing contracts. The net book value is compared to the ceiling on an annual
basis. The excess, if any, of the net book value above the ceiling is required
to be written off as an expense. During the year ended January 31, 2006 an
impairment expense of $520,048 was recorded.

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 estimated
undiscounted net cash flows to be generated by the asset.

                                      F-6
<PAGE>

Equipment - Equipment is recorded at cost and depreciated on the Straight-line
basis over the following periods:

                  Computer equipment         5-7 years
                  Truck                        7 years
                  Office equipment           5-7 years
                  Computer software            5 years
                  Gathering systems           30 years


Asset Retirement Obligations - In accordance with the provisions of SFAS No. 143
Accounting for Asset Retirement Obligations the Company records the fair value
of its liability for asset retirement obligations in the period in which it is
incurred and a corresponding increase in the carrying amount of the related
long-lived assets. Over time, the liability is accreted to its present value at
the end of each reporting period, and the capitalized cost is depreciated over
the useful life of the related assets. Upon settlement of the liability, the
Company will either settle the obligation for its recorded amount or incur a
gain or loss upon settlement. The Company's asset retirement obligations relate
to the plugging and abandonment of its natural gas properties.

Accounts Receivable - Management periodically assesses the collectibility of the
Company's accounts receivable. Accounts determined to be uncollectible are
charged to operations when that determination is made.

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 share in the earnings of
the entity. For the years ended January 31, 2006 and 2005, no options or
warrants were considered common stock equivalents as their effect would be
anti-dilutive.

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. The Company has not yet adopted the provisions of
SFAS No. 123 Revised Share-Based Payment.

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.

                                      F-7
<PAGE>

Concentration of credit risk - The Company maintains its cash in bank deposit
accounts which, at times, may exceed federally insured limits. The Company has
not experienced any losses in such accounts and believes it is not exposed to
any significant risk. The amount of cash deposits as of January 31, 2006 in
excess of FDIC limits was $468,617.

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.

Reclassifications - Certain prior period amounts have been reclassified to
conform to current period presentation.

New Accounting Pronouncements - In November 2004, the FASB issued SFAS No. 151,
Inventory Costs - an amendment of ARB No. 43, Chapter 4. Statement No. 151
requires that certain abnormal costs associated with the manufacturing, freight,
and handling costs associated with inventory be charged to current operations in
the period in which they are incurred. The financial statements are unaffected
by implementation of this new standard.

In December 2004, the FASB issued a revision of SFAS No. 123, Share-Based
Payment. The statement establishes standards for the accounting for transactions
in which an entity exchanges its equity investments for goods and services. It
also addresses transactions in which an entity incurs liabilities in exchange
for goods or services that are based on the fair value of the entity's equity
instruments or that may be settled by the issuance of those equity instruments.
The statement does not change the accounting guidance for share-based payments
with parties other than employees. The statement is effective for the quarter
beginning January 1, 2006. The Company does not expect this statement to have a
material effect on the Company's financial position or results of operations.

In December 2004, the FASB issued SFAS No. 153, Exchanges of Non-monetary
Assets-amendment of APB Opinion No. 29. Statement 153 eliminates the exception
to fair value for exchanges of similar productive assets and replaces it with a
general exception for exchanged transactions that do not have a commercial
substance, defined as transactions that are not expected to result in
significant changes in the cash flows of the reporting entity. This statement is
effective for exchanges of non-monetary assets occurring after June 15, 2005.
The Company does not expect this statement to have a material effect on the
Company's financial position or results of operations.

In March 2005,  the FASB  issued  FASB  Interpretation  No. 47,  Accounting  for
Conditional  Asset  Retirement  Obligations  ("FIN 47").  FIN 47  clarifies  the
definition  and  treatment  of  conditional  asset  retirement   obligations  as
discussed  in SFAS No.  143,  Accounting  for Asset  Retirement  Obligations.  A
conditional  asset  retirement  obligation  is  defined  as an asset  retirement
activity in which the timing and/or method of settlement are dependent on future
events  that may be outside  the  control of the  company.  FIN 47 states that a


                                      F-8
<PAGE>

company must record a liability when incurred for conditional  asset  retirement
obligations if the fair value of the obligation is reasonably estimable.  FIN 47
is intended to provide more information  about long-lived assets and future cash
outflows  for  these  obligations  and  more  consistent  recognition  of  these
liabilities.  FIN 47 is effective  for fiscal  years  ending after  December 15,
2005.  We do not believe that our financial  position,  results of operations or
cash flows will be materially impacted by implementation of FIN 47.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error
Corrections, which changes the accounting for and reporting of a change of
accounting principle. It requires retrospective application of a change of
accounting principle unless impracticable. SFAS No. 154 is effective for fiscal
years beginning after December 15, 2005 and is not expected to have a material
impact on the Company's financial statements when adopted

In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid
Financial Instruments, which amends FASB Statements No. 133 and 140. SFAS No.
155 clarifies certain issues relating to embedded derivatives and beneficial
interests in securitized financial assets. The provisions of SFAS 155 are
effective for all financial instruments acquired or issued after fiscal years
beginning after September 15, 2006. We are currently assessing the impact that
the adoption of SFAS 155 will have on our financial statements


4.  ACQUISITIONS AND RELATED DEBT

In August 2003 the Company acquired 31 producing wells with a gathering system,
compressor stations, plus developed and undeveloped acreage. All of the acquired
properties are located in the Appalachian Basin of eastern Kentucky. The
properties were acquired from three private corporations for $3,000,000 in
convertible notes. The notes bear interest at 8.5% per year and are due in
August 2023. All or any part of the unpaid principal or interest may be
converted into shares of the Company's common stock on the basis of one share of
common stock for every dollar of note principal or interest converted. As an
inducement to convert, the terms of the agreements were subsequently modified to
allow for conversion of unpaid principal and accrued interest into the Company's
common stock on the basis of one share of common stock for every $.50 of note
principal or interest converted. In March 2004, two of the three note holders
exercised their option to convert under these new terms resulting in $2,400,000
of principal converted into 4,800,000 shares of the Company's common stock.

On August 25, 2005 the Company issued 1,250,000 shares of its common stock
valued at $475,000 to McCrome International, Inc. the third note holder, plus
cash of $21,695. This was full payment of a Promissory Note held by McCrome
International in the principal amount of $479,218, plus interest of $17,477.

On December 16, 2005 in settlement of the arbitration case with Double G Energy,
the Company  entered into an agreement with Double G Energy to repurchase all of
Double G Energy's  interests in the Company's wells in Pulaski County,  Kentucky
for  $1,000,000.  Payment terms of the agreement were for an initial  payment of
$250,000 at the date of settlement; $100,000 per month January 2006 through July

                                      F-9
<PAGE>

2006;  final  payment of $50,000 in August 2006. As of January 31, 2006 payments
of $350,000 had been made by the Company.

5.  SETTLEMENT OF LITIGATION

On April 2, 2004, the Company settled two lawsuits with a shareholder and his
related companies for a total of $500,000 in cash, 350,000 shares of the
Company's common stock and 250,000 options with an exercise price of $0.32 with
an expiration date of June 15, 2005. This settlement paid in full a note in the
amount of $280,000, advances from a shareholder in the amount of $261,975 and
accrued interest payable in the amount of $87,901, resulting in a loss of
$31,624 on this settlement as detailed below:

               Consideration given:
               Cash                         $ 500,000
               Oil Lease                       60,000
               Stock                           70,000
               Options                         31,500
                                            ---------
                    Total consideration       661,500
               Liabilities retired:
               Notes Payable                  280,000
               Due Shareholder                261,975
               Accrued Interest                87,901
                                            ---------
                                              629,876

               Settlement Expense            $ 31,624
                                             ========

During the year ended January 2006 the Company guaranteed a contract between one
of the Company's contract pumpers and a third party. The pumper defaulted on the
contract and on January 18, 2006 the Company paid $21,500 to settle the
guarantee with the third party.

6.  EMPLOYEE LOAN

As of January 31, 2005, the Company had a non-interest bearing loan to an
employee totaling $17,086 which was paid back during the year ended January 31,
2006.

7.  SALE OF OIL AND GAS PROPERTIES

In October 2005 the Company sold its 50% interest in 1,019.12 acres in the Rusty
Creek prospect in Niobrara County, Wyoming for $28,535.

During the fiscal year ended January 31, 2005, the Company sold an 80% working
interest for bore hole assignments only in 20 wells (no acreages) in the Pulaski
County field in Kentucky for $100,000.

During February through May 2004, the Company sold 83.25% Working Interest in
1,350 acres in Harper County, Kansas for $37,440.


                                      F-10
<PAGE>

The proceeds from these sales were treated as a reduction in the carrying amount
of oil and gas properties in accordance with the requirements of the full cost
method of accounting for oil and gas properties.

8.  EQUITY LINE OF CREDIT

On September 20, 2004, the Company entered into an equity line of credit
agreement with Dutchess Private Equities Fund II, L.P. The purpose of the equity
line of credit is to provide a possible source of funding for the Company's oil
and gas exploration activities or for working capital.

Under the equity line of credit agreement, Dutchess Private Equities has agreed
to provide the Company with up to $10,000,000 of funding prior to October 14,
2007. During this period, the Company may request a drawdown under the equity
line of credit by selling shares of its common stock to Dutchess Private
Equities, and Dutchess Private Equities will be obligated to purchase the
shares. The minimum and maximum amounts the Company can draw down at any one
time are determined using a formula contained in the equity line of credit
agreement. The Company is under no obligation to request any drawdown under the
equity line of credit. As of January 31, 2006, the company has drawn a sum of
$788,247, which was repaid by the issuance of 1,589,698 shares of the Company's
common stock.

9.  RELATED PARTY

The Company sells gas from its Atoka County properties to an affiliated company,
Energas Corporation. During the years ended January 31, 2006 and 2005, these
sales were approximately $199,000 and $145,000 respectively. Energas Corporation
deducts a marketing fee of $0.10 per MCF from the price paid by the end
purchaser. The total marketing fee for the years ended January 31, 2006 and 2005
was approximately $2,650 and $3,000, respectively.

On August 12, 2005 George G. Shaw, the Company's President, converted $326,000
which he had loaned to the Company into 1,304,000 restricted shares of the
Company's common stock.

10. INCOME TAXES

As of  January  31,  2006,  the  Company  has  approximately  $8,677,000  of net
operating losses expiring through 2026 that 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, 2006,
the  Company  had  an  unused  Canadian  net  operating  loss  carry-forward  of
approximately  $395,000 USD,  expiring  through 2008.  These net operating  loss
carry-forwards  may  result in  future  income  tax  benefits  of  approximately
$3,629,000;  however, because realization is uncertain at this time, a valuation
reserve in the same amount has been  established.  Deferred income taxes reflect

                                      F-11
<PAGE>

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.

A  reconciliation  of the  provision  (benefit) for income
taxes with the amounts  determined by applying the U.S.  federal income tax rate
to income before income taxes is as follows:

                                                        Year Ended January 31,
                                                        2006            2005
                                                        ----            ----

    Computed at the federal statutory rate of 34%    $ (538,000)      (396,000)

    State tax (benefit) at statutory rates            (  95,000)      ( 70,000)

    Change in valuation allowance                       633,000        466,000
                                                     ----------       --------

    Income tax expense                               $       --       $     --
                                                     ----------       --------

Significant components of the Company's deferred tax liabilities and assets as
of January 31, 2006 and 2005 are as follows:

                                                         2005           2004
   Deferred tax liabilities
      Timing difference in full cost pool            $(309,000)     $ (187,000)
                                                     =========      ==========

   Deferred tax assets
      Net operating losses                           3,874,000       3,119,000

   Valuation allowance for deferred tax assets      (3,565,000)     (2,932,000)
                                                    -----------     ----------
                                                   $        --     $        --
                                                   ============    ===========


The valuation allowance increased $633,000 and $203,000 for the years ending
January 31, 2006 and 2005, respectively.

The ability of the Company to utilize NOL carryforwards to reduce future federal
taxable income and federal income tax of the Company is subject to various
limitations under the Internal Revenue Code of 1986, as amended. The utilization
of such carryforwards may be limited upon the occurrence of certain ownership
changes, including the issuance or exercise of rights to acquire stock, the
purchase or sale of stock by 5% stockholders, as defined in the Treasury
regulations, and the offering of stock by the Company during any three-year
period resulting in an aggregate change of more than 50% in the beneficial
ownership of the Company.


                                      F-12
<PAGE>

11.  LONG-TERM DEBT

The Company has the following notes payable as of January 31, 2006

Note payable to a bank, secured by oil and gas
Properties, interest at Prime Rate plus 1 and
1/4 %, (7.5% at January 31, 2006), monthly
interest payments starting November 5, 2005
and monthly principal payments of $16,667 starting
on February 5, 2006                                    $   452,587         -

Note payable to a private corporation, secured by
Equipment, interest at 8%, due in 36 monthly
installments including principal and interest of
$5,218 beginning February 1, 2006                          166,500

Note payable to a private corporation, secured by
oil and gas properties, interest at 8.5%, convertible
to common stock at a rate of one share for each
dollar owed, due in 240 monthly installments
including principal and interest in the amount
of $4,339 beginning September 1, 2003                           --
                                                       -----------

                                                           619,087
          Less: Current Portion                           (251,150)
                                                       -----------
                                                      $    367,937
                                                      ============

Maturities of long-term debt for the next five years ending January 31, are as
follows:

                  2007              $ 251,150
                  2008                255,395
                  2009                112,542
                  2010                     --
                  2011                     --
                  Thereafter               --
                                    ---------
                                    $ 619,087
                                    =========

On August 25, 2005 the Company issued 1,250,000 shares of its common stock
valued at $475,000 plus cash of $21,695. This was full payment of a Promissory
Note held by McCrome International in the principal amount of $479,218 plus
interest of $17,477.


                                      F-13
<PAGE>

12. EARNINGS PER SHARE

SFAS 128 requires a reconciliation of the numerator and denominator of the basic
and diluted earnings per share (EPS) computations. The following securities were
not included in the calculation of diluted earnings per share because their
effect was anti-dilutive:

The following reconciles the components of the EPS computation:

                                                      2006              2005
                                                      ----              ----
Basic (loss) per share computation Numerator:
  Net loss                                        $ (1,583,501)    $ (1,164,175)

Denominator:
  Weighted average common shares outstanding        52,513,509       41,251,753
Basic (loss) per share                            $      (0.03)    $      (0.03)

Diluted (loss) per share Numerator:
  Net loss                                        $ (1,583,501)    $ (1,164,175)

Denominator:
  Weighted average common shares outstanding        52,513,509       41,251,753
Diluted (loss) per share                          $      (0.03)    $      (0.03)


13. ASSET RETIREMENT OBLIGATION

As described in Note 1, effective June 1, 2003, the Company adopted SFAS 143,
Accounting for Asset Retirement Obligations. Upon adoption of SFAS 143, the
Company recorded an asset retirement obligation liability of $20,770 and an
increase to net properties and equipment of $20,770.

The following table provides a roll forward of the asset retirement obligations:

                                               Year Ended          Year Ended
                                             January 31, 2006   January 31, 2005

  Asset retirement obligation beginning
        balance                                $   86,799          $   20,770
    Liabilities incurred                            3,026              60,000
    Liabilities settled                                --                 --
    Accretion expense                               6,931              6,029
                                               ----------          ---------
  Asset retirement obligation ending balance   $   96,756          $  86,799
                                               ==========         ==========


                                      F-14
<PAGE>

14.  STOCK OFFERING

Beginning January 12, 2004, the Company offered for sale, in a private offering,
500 units at a price of $3,000 per unit. Each unit consists of 10,000 shares of
the Company's common stock and 10,000 warrants to purchase shares of the
Company's common stock at $0.50 per share. The Company completed the offering in
May 2004, resulting in total proceeds to the Company of $1,500,000.

Beginning April 25, 2005, the Company offered for sale in a private offering,
1,200,000 shares of the Company's restricted common stock at $0.25 per share. As
of July the Company has received stock subscriptions for 1,072,000 shares with
proceeds totaling $268,000. The Company completed the offering August 11, 2005,
resulting in total proceeds to the Company of $300,000.

On September 27, 2005, the Company completed a private offering of 714,286
shares of the Company's common stock and 714,286 warrants to purchase the
Company's common stock at $0.50 per share. The completed offering resulted in
total proceeds to the Company of $200,000.

On January 18, 2006, the Company completed a private offering of 578,000 shares
of the Company's common stock at $0.53 per share. The completed offering
resulted in total proceeds to the company of $306,340.

15. OPTIONS AND WARRANTS

The Company has issued stock options and stock warrants as follows:

                   Outstanding    Granted    Exercised  Outstanding
         Exercise   January 31,      or         or      January 31,   Expiration
          Price       2005       (Cancelled) Expired      2006           Date
         -------  ------------   ----------  ---------  ----------    ----------

Options: $   0.32     170,000          --     170,000         --      06/15/05

Warrants $   0.32     100,000          --     100,000         --      06/30/05
         $   0.50   3,895,000          --   3,895,000         --      01/31/06
         $   0.50          --     714,286          --    714,286      10/01/07


16.  OPERATING LEASES

The Company currently has three leases that are under contract. The Company
leases a compressor for the Laurel County Kentucky gathering system at $4,304
per month through April 2006 and then becomes month to month thereafter. In
addition, the Company has two office equipment leases through April 2010. All
leases are warrantied with full maintenance.


                                      F-15
<PAGE>

Additionally, the minimum annual rental commitments as of January 31, 2006 under
noncancellable leases are as follows: 2007 - $18,286; 2008 - $5,375; 2009 -
$3,779; 2010 - $3,6,34; and 2011 - $909.

17.   MAJOR PURCHASERS

The Company's natural gas and oil production is sold under contracts with
various purchasers. Natural gas sales to one purchaser approximated 59% of total
natural gas and oil revenues for the fiscal year ended January 31, 2006.

See Note 9 regarding sales to Related Parties.


18.  FINANCIAL INSTRUMENTS

The carrying amount of cash, receivables, deposits, accounts payable, and
accrued expenses approximates fair value due to the short maturity of those
instruments. The carrying amounts for convertible debentures and notes payable
approximate fair value because the interest rates have remained generally
unchanged since the issuance of the convertible debentures and due to the
variable nature of the interest rates of the notes payable.

19.  CONTINGENCIES

In the normal course of its operations, the Company may, from time to time, be
named in legal actions seeking monetary damages. While the outcome of these
matters cannot be estimated with certainty, management does not expect, based
upon consultation with legal counsel, that they will have a material effect on
the Company's business or financial condition or results of operations.

20.  STOCK-BASED COMPENSATION

The Company has a stock compensation program under which some employees receive
a portion of their compensation in fully vested, marketable shares of the
Company's common stock. The number of shares issued is determined by the daily
average market price of the stock on a monthly basis. Compensation expense
recognized under this program for the years ended January 31, 2006 and 2005 were
$135,750 for 504,133 shares and $8,000 for 12,848 shares respectively.

21. SUBSEQUENT EVENTS

Construction  on the  transmission  pipeline  in  Laurel  County,  Kentucky  was
completed in March,  2006.  The start up process took about 6 weeks to stabilize
the  hook  up of the  first  four  wells,  the  gathering  systems,  compressor,
dehydrator,  launcher & receiver stations, meter tap, water breakouts and tanks.
The  gathering  system was filled with natural  gas,  then the 4 miles of 6 inch
pipeline was filled and compressed to 250 pounds  pressure per square inch. This
process  took over 3 million  cubic feet of gas to fill and compress the system.
It is now operating  and our new  petroleum  engineer is making plans to produce

                                      F-16
<PAGE>

more gas for the  pipeline to sell.  The pipeline is setup to handle a volume of
5,000 mcfd at this time,  but can easily be  upgraded  to handle  10,000 mcfd if
needed.

Select Engineering of Tulsa, Oklahoma was the engineering company for planning
and building our transmission pipeline in Eastern Kentucky.

23.  SFAS 69 SUPPLEMENTAL DISCLOSURES (UNAUDITED)

Net Capitalized Costs

The Company's aggregate capitalized costs related to natural gas and oil
producing activities are summarized as follows:

                                          January 31,           January 31,
                                               2006                 2005
                                          ------------------------------------
Natural gas and oil properties
and related lease equipment:
     Proved                             $  6,545,443           $  4,206,710
     Unproved                                144,483                234,093
     Pipeline facilities                   1,481,585                330,377
                                        ------------           ------------
                                           8,171,511              4,771,180
Accumulated depreciation and depletion    (1,697,867)              (656,975)
                                        ------------           ------------

     Net capitalized costs               $ 6,473,644           $ 4,114,205
                                         ===========           ===========

Unproved properties not subject to amortization consisted mainly of leasehold
acquired through acquisitions. The Company will continue to evaluate its
unproved properties; however, the timing of the ultimate evaluation and
disposition of the properties has not been determined.

Costs Incurred

Costs incurred in natural gas and oil property acquisition, exploration and
development activities that have been capitalized are summarized as follows:

                                                    Years Ended January 31,
                                                  2006                 2005
                                                  ----                 ----

Acquisition of properties proved and unproved  $ 1,000,000        $        --
Development costs                                1,044,420            931,350
Acquisition of pipelines                         1,151,208                 --
                                               -----------        -----------
                                               $ 3,195,628        $   931,350
                                               ===========        ===========

Results of Operations for Natural Gas and Oil Producing Activities

The  Company's  results  of  operations  from  natural  gas  and  oil  producing
activities  are presented  below for the fiscal years ended January 31, 2006 and
2005. The following  table includes  revenues and expenses  associated  directly


                                      F-17
<PAGE>

with the Company's natural gas and oil producing activities. It does not include
any interest costs and general and administrative  costs and, therefore,  is not
necessarily indicative of the contribution to consolidated net operating results
of the Company's natural gas and oil operations.

                                                Years Ended January 31,
                                                2006             2005
                                                ----             ----

        Production revenues                 $  1,183,118      $  653,475
        Production costs                        (517,534)       (324,150)
        Impairment                              (520,048)
        Depletion expense                       (432,593)       (278,342)
                                            -------------     ----------
                                                (287,057)         50,983
        Imputed income tax provision (1)              --         (20,393)
                                            -------------     ----------
        Results of operation for natural
          gas/oil producing activity        $   (287,057)     $   30,590
                                            ============      ==========

(1)  The imputed income tax provision is hypothetical (at the statutory rate)
     and determined without regard to the Company's deduction for general and
     administrative expenses, interest costs and other income tax credits and
     deductions, nor whether the hypothetical tax provision will be payable.

Natural Gas and Oil Reserve Quantities

The following schedule contains estimates of proved natural gas and oil reserves
attributable to the Company. Proved reserves are estimated quantities of natural
gas and oil 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 which are
expected to be recovered through existing wells with existing equipment and
operating methods. Reserves are stated in thousand cubic feet (mcf) of natural
gas and barrels (bbl) of oil. Geological and engineering estimates of proved
natural gas and oil reserves at one point in time are highly interpretive,
inherently imprecise and subject to ongoing revisions that may be substantial in
amount. Although every reasonable effort is made to ensure that the reserve
estimates are accurate, due to their nature reserve estimates are generally less
precise than other estimates presented in connection with financial statement
disclosures.

                                             Gas - mcf         Oil - bbls
                                          -------------      -------------
Proved reserves:
     Balance, January 31, 2004                4,394,959            73,790
          Purchase of reserves-in-place              --                --
          Improved recovery                          --                --
          Extensions and discoveries                 --                --
          Revisions of previous estimates    (2,107,212)          (39,384)
          Production                           (106,276)           (4,008)
                                           ------------        ----------
     Balance, January 31, 2005                2,181,471            30,398
                                           ------------       -----------

                                      F-18
<PAGE>


Purchase of reserves-in-place
          Extensions and discoveries               --            13,744
          Revisions of previous estimates    (285,814)               --
          Production                         (130,748)           (2,962)
                                          -----------        ----------
     Balance, January 31, 2006              1,764,909            41,180
                                          ===========        ==========
Proved developed reserves:
     Balance, January 31, 2005              1,316,669            30,398
     Balance, January 31, 2006                875,876            33,959

Standardized Measure of Discounted Future Net Cash Flows:

The following schedule presents the standardized measure of estimated discounted
future net cash flows from the Company's proved reserves for the fiscal years
ended January 31, 2006 and 2005. Estimated future cash flows are based on
independent reserve data. Because the standardized measure of future net cash
flows was prepared using the prevailing economic conditions existing at January
31, 2006 and 2005, it should be emphasized that such conditions continually
change. Accordingly, such information should not serve as a basis in making any
judgment on the potential value of the Company's recoverable reserves or in
estimating future results of operations.
                                             Years Ended January 31,
                                              2006           2005
                                              ----           ----

Future production revenues (1)            $15,629,436    $13,685,443
Future production costs                    (4,468,354)    (3,783,015)
Future development costs                   (1,535,000)      (524,597)
                                      --------------- --------------
Future cash flows before income taxes       9,626,082      9,377,831
Future income tax                          (1,398,751)    (2,213,632)
                                         ------------   ------------
Future net cash flows                       8,227,331      7,164,199
Effect of discounting future annual
    cash flows at 10%                      (3,235,272)    (2,826,564)
                                         ------------   ------------
Standardized measure of discounted
    net cash flows                       $  4,992,059   $  4,337,635
                                         ============   ============

(1)  The weighted average natural gas and oil wellhead prices used in computing
     the Company's reserves were $7.84 per mcf and $55.80 per bbl at January 31,
     2006 as compared to $5.95 per mcf and $35.25 per bbl at January 31, 2005.

The following schedule contains a comparison of the standardized measure of
discounted future net cash flows to the net carrying value of proved natural gas
and oil properties at January 31, 2006 and 2005:

                                      F-19
<PAGE>

                                                    Years Ended January 31,
                                                     2006             2005
                                                     ----             ----
Standardized measure of discounted future
     net cash flows                               $ 4,992,059    $ 4,377,635
Proved natural gas & oil property net of
     Accumulated depreciation, depletion and
     amortization, including impairment of
     $520,048                                       4,992,059      3,843,749
                                                 ------------    -----------
Standardized measure of discounted future
     net cash flows in excess of net carrying
     value of proved natural gas & oil properties$         --    $  533,886
                                                  ===========    ==========



                                      F-20
<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 12th day of May, 2006.

                            ENERGAS RESOURCES, INC.


                            By:   /s/ George G. Shaw
                                ---------------------------------------
                                George G. Shaw, President, Principal Accounting
                                Officer and Principal Financial Officer


      In accordance with the Exchange Act, this Report has been signed by the
following persons on behalf of the Registrant in the capacities and on the dates
indicated.

                                     Title                    Date

/s/ George G. Shaw
-------------------------
George G. Shaw                      Director             May 12, 2006



/s/ G. Scott Shaw
--------------------------
G. Scott Shaw Director May 12, 2006








<PAGE>







                             ENERGAS RESOURCES, INC.

                                   FORM 10-KSB

                                    EXHIBITS