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            [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934
                   For the fiscal year ended December 31, 2003
                                                                  or
              [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
                  For the transition period from ____ to ____.
                         Commission file number 1-12108.

                              GulfWest Energy Inc.
             (Exact name of registrant as specified in its charter)

       Texas                                                87-0444770
(State or other jurisdiction of                         (IRS Employer
incorporation or organization)                           Identification No.)


480 N. Sam Houston Parkway East, Suite 300
            Houston, Texas                                    77060
(Address of principal executive offices)                    (Zip Code)

       Registrant's telephone number, including area code: (281) 820-1919.

           Securities registered pursuant to Section 12(b) of the Act:

                               Title of Each Class
                               -------------------

               Class A Common Stock, par value of $.001 per share

           Securities registered pursuant to Section 12(g) of the Act:

                               Title of Each Class
                               -------------------

               Class A Common Stock, par value of $.001 per share

     Indicate  by check mark  whether the  registrant  (1) has filed all reports
required to be filed by Section 13 or 15(d) of the  Securities  Exchange  Act of
1934  during  the  preceding  12 months  (or for such  shorter  period  that the
registrant was required to file such reports),  and (2) has been subject to such
filing requirements for the past 90 days. Yes X No ____

     Indicate by check mark if disclosure of delinquent  filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or informational  statements
incorporated  by reference  in Part III of this Form 10-K/A or any  amendment to
this Form 10-K/A. [ ]

     Indicate by check mark whether the registrant is an  accelerated  filer (as
defined in Rule 12-b2 of the Act).

                                  Yes _ No _X__

     The  aggregate  market  value of  voting  stock of the  Registrant  held by
non-affiliates, computed by reference to the closing price of such stock on June
30, 2003, was approximately  $3,507,271.  For purposes of this computation,  all
executive  officers,  directors and ten percent (10%)  beneficial  owners of the
Registrant are deemed to be affiliates.  Such determination should not be deemed
an admission  that such  executive  officers,  directors  and ten percent  (10%)
beneficial owners are affiliates.

     Indicate  the  number of  shares  outstanding  of each of the  Registrant's
classes of common stock: Class A Common Stock $.001 par value: 18,492,541 shares
on March 29, 2004.

                      DOCUMENTS INCORPORATED BY REFERENCE:

The  registrant's  definitive  Proxy  Statement  pertaining  to the 2004 Annual
Meeting of  Shareholders  (the "Proxy  Statement")  and filed or to be filed not
later than 120 days after the end of the fiscal year pursuant to Regulation  14A
is incorporated herein by reference into Part III.





                                     PART I

ITEM 1. Business.

Our Business.

     We are primarily engaged in the acquisition,  development, exploitation and
production of crude oil and natural gas. Our focus is on  increasing  production
from our existing  properties  through  further  exploitation,  development  and
exploration,  and on acquiring additional interests in crude oil and natural gas
properties.

     Since  we  made  our  first  significant   acquisition  in  1993,  we  have
substantially  increased our ownership in producing  properties and the value of
our crude oil and natural gas reserves through a combination of acquisitions and
the further  exploitation  and  development of our  properties.  At December 31,
2003, our part of the estimated  proved  reserves these  properties  contain was
approximately  5.0 million  barrels  (MBbl) of oil and 32.7  billion  cubic feet
(Bcf) of  natural  gas with a Present  Value  discounted  10%  (PV-10) of $114.4
million.  At  present,  all of our  properties  are  located  on land in  Texas,
Colorado,  Louisiana  and  Oklahoma,  except  for the  property  on Grand  Lake,
Louisiana.  In the future, we plan to expand by acquiring additional  properties
in those areas, and in similar  properties  located in other areas of the United
States.

     Our gross revenues are derived from the following sources:

     1.   Oil and gas  sales  that are  proceeds  from the sale of crude oil and
          natural gas production to midstream purchasers;

     2.   Operating  overhead  and other income that  consists of earnings  from
          operating  crude oil and  natural  gas  properties  for other  working
          interest owners, and marketing and transporting natural gas. This also
          includes earnings from other miscellaneous activities.

     3.   Well  servicing  revenues that are earnings from the operation of well
          servicing equipment under contract to other operators. During 2003, we
          worked only for our own account.

     Our  operations are  considered to fall within a single  industry  segment,
which is the acquisition, development, production and servicing of crude oil and
natural gas  properties.  See Item 7. " Management's  Discussion and Analysis of
Financial  Condition  and Results of  Operations."  Certain  industry  terms are
italicized and defined in the Glossary beginning on page 28.

     Our common stock is traded over-the-counter (OTC) under the symbol "GULF".

Our Company.

     We were formed as a corporation under the laws of the State of Utah in 1987
as  Gallup  Acquisitions,  Inc.,  and  subsequently  changed  our  name to First
Preference  Fund,  Inc.  and then to  GulfWest  Energy,  Inc.  We became a Texas
corporation by a merger effected in July 1992, in which our name became GulfWest
Oil Company. On May 21, 2001, we changed our name to GulfWest Energy Inc.

     Our  principal  office is located at 480 North Sam  Houston  Parkway  East,
Suite 300, Houston, Texas 77060 and our telephone number is (281) 820-1919.

                                       2

     GulfWest Energy Inc. has nine wholly owned subsidiaries:

     1.   GulfWest  Oil and Gas  Company,  a Texas  corporation,  was  organized
          February  18, 1999 and is the owner of record of  interests in certain
          crude oil and natural gas properties located in Colorado and Texas.

     2.   SETEX Oil and Gas Company, a Texas  corporation,  was organized August
          11, 1998 and is the  operator of crude oil and natural gas  properties
          in which we own the majority working interest.

     3.   LTW Pipeline Co., a Texas  corporation,  was organized April 19, 1999,
          is the owner and operator of certain natural gas gathering systems and
          pipelines  that we own, and markets the natural gas produced  from our
          properties.

     4.   RigWest  Well  Service,  Inc.,  a  Texas  corporation,  was  organized
          September 5, 1996 and operates  well  servicing  equipment for our own
          account.

     5.   Southeast  Texas Oil and Gas Company,  L.L.C.,  a Texas  company,  was
          acquired  by us on  September  1,  1998 and is the  owner of record of
          interests in certain crude oil and natural gas  properties  located in
          three Texas counties.

     6.   DutchWest Oil Company,  a Texas  corporation,  was organized  July 28,
          1997 and is the owner of record of interests in certain  crude oil and
          natural gas properties located along the Gulf Coast of Texas.

     7.   GulfWest  Development  Company,  a Texas  corporation,  was  organized
          November  9, 2000 and is the owner of record of  interests  in certain
          crude oil and natural gas  properties  located in Texas,  Oklahoma and
          Mississippi.

     8.   GulfWest Texas Company, a Texas corporation,  was organized  September
          23,  1996 and was the  owner of  interests  in  certain  crude oil and
          natural gas properties  located in the Vaughn Field,  Crockett County,
          Texas.  Effective  April 1, 2000,  these  properties  were assigned to
          GulfWest Oil and Gas Company to facilitate financing.

     9.   GulfWest Oil and Gas Company (Louisiana) LLC, a Louisiana company, was
          formed  July 31,  2001 and is the  owner of  record  of  interests  in
          certain  crude  oil and  natural  gas  properties  in  Louisiana.  Our
          Business Strategy.

     We have pursued a business strategy of acquiring interests in crude oil and
natural gas producing  properties where production and reserves can be increased
through  engineering  and  development   activities.   Such  activities  include
workovers,  development  drilling,  recompletions,  replacement  or  addition of
equipment  and  waterflood  or  other  secondary  recovery  techniques.  We have
expanded our business  plan to include an increased but  controlled  emphasis on
development  drilling for  additional  crude oil and natural gas  reserves.  Key
elements of our business strategy include:

     Continued Acquisition Program. We acquired properties in four crude oil and
natural  gas  fields  in Texas  and  Louisiana  in the year  2001.  We intend to
continue to pursue interests in crude oil and natural gas properties (i) held by
small, under-capitalized operators and (ii) being divested by larger independent
and major oil and gas companies.
                                       3

     Development and Exploitation of Existing Properties.  We intend to increase
the  development  of  properties in which we currently own interest by expanding
our  engineering and geological  field studies.  Our intent is to increase crude
oil and natural gas  production  and  reserves of our  existing  assets  through
relatively low-risk development  activities,  such as workovers,  recompletions,
horizontal drilling from existing wellbores and infield drilling, as well as the
more  efficient  use of  production  facilities  and the  expansion  of existing
waterflood operations.

     Significant  Operating Control.  Currently,  we are the operator of all the
wells,  except two, in which we own working  interests.  This operating  control
enables us to better manage the nature,  timing and costs of development of such
wells, and marketing of the resulting production.

     Ownership of Workover  Rigs. We currently own three  workover  service rigs
and one  swabbing  unit that we  operate  for our own  account.  By  owning  and
operating  this  equipment,  we are  better  able to control  costs,  quality of
operations and availability of equipment and services.

     Greater  Natural Gas  Ownership.  At December 31, 2003,  our reserves  were
comprised of 48% crude oil and 52% natural  gas. We will  continue to expand our
role in the domestic natural gas industry by (i) acquiring  additional interests
in natural gas  properties,  (ii)  increasing the production and reserve base of
our  existing  natural gas  properties,  and (iii)  acquiring  ownership of more
natural gas  gathering  systems and  pipelines.  We are  presently  focusing our
workover and  development  efforts on both crude oil and natural gas reserves to
take advantage of the higher prices of both commodities.  We are also seeking to
expand our ownership of gas gathering  systems and pipelines located in our main
field  areas.   Our  goal  is  to  have  greater  control  of  our  natural  gas
transportation  and  marketing,  and an expanded role in the  transportation  of
natural gas produced by other parties in our area of operations.

     Expanded  Exploration  and  Exploitation  Role.  Historically,  we have not
drilled  exploratory  wells due to the cost and risk  associated  with  drilling
prospective  locations.  However,  since  the  end of  1998,  we  have  acquired
producing  properties that have included significant acreage for prospective oil
and gas  exploration.  These  include  producing  wells and acreage in Crockett,
Grimes, Hardin, Jim Wells, Kimble, Madison, Palo Pinto, Refugio, Sutton, Wharton
and Zavala, Counties, Texas; Adams, Arapaho, Elbert and Weld Counties, Colorado;
Creek County, Oklahoma; and, Cameron Parish, Louisiana.  These acquisitions have
added  existing  natural gas and crude oil  production to our asset base and, as
importantly,  have provided us with immediate  geological databases for drilling
opportunities.  We have  expanded  our  evaluation  efforts in these  fields and
intend to increase our  development of reserves,  not only through  workovers of
existing wells, but by drilling additional wells.


Our Employees.

     At December 31, 2003, we had 34 full time employees,  of whom 22 were field
personnel.

Our Executive Officers.

     See Item 10 of this report,  which  information is  incorporated  herein by
reference.
                                       4

ITEM 2. Our Properties.

     At December  31, 2003,  we owned a total of 684 gross  wells,  of which 266
were producing,  351 were shut-in or temporarily abandoned and 67 were injection
or saltwater  wells.  We owned an average 94% working  interest in the 266 gross
(249.90 net) producing wells.  Gross wells are the total wells in which we own a
working interest.  Net wells are the sum of the fractional  working interests we
own in gross wells.  Our part of the estimated  proved reserves these properties
contain was  approximately  5.0 million  barrels  (MBbl) of oil and 32.7 billion
cubic feet (Bcf) of natural gas. Substantially all of our properties are located
in Texas, Colorado, Louisiana and Oklahoma.

Proved Reserves.

     The following  table reflects our estimated  proved reserves at December 31
for each of the preceding three years.



                                               2003        2002           2001
                                               ----        ----           ----

                 Crude Oil (MBbl)
                        Developed              3,773       4,026         3,940
                      Undeveloped              1,265       1,496         1,932
                                              --------   ---------     ---------
                                   Total       5,038       5,522         5,872
                                              ========   =========     =========

                      Natural Gas (MMcf)
                               Developed      24,642      25,374        21,204
                             Undeveloped       8,018       8,785        18,054
                                              --------   ---------     ---------
                                   Total      32,660      34,159        39,258
                                              ========   =========     =========
                            Total (MBOE)      10,481      11,215        12,415
                                              ========   =========     =========

     (a)  Approximately  75% of our total proved  reserves  were  classified  as
          proved developed at December 31, 2003.

     (b)  Barrel of Oil Equivalent (BOE) is based on a ratio of 6,000 cubic feet
          of natural gas for each barrel of oil.
                                       5

Standardized Measure of Discounted Future Net Cash Flows.

     The following  table sets forth as of December 31 for each of the preceding
three years, the estimated future net cash flow from and standardized measure of
discounted future net cash flows of our proved reserves,  which were prepared in
accordance  with the  rules and  regulations  of the SEC.  Future  net cash flow
represents  future  gross  cash  flow  from the  production  and sale of  proved
reserves,  net  of  crude  oil  and  natural  gas  production  costs  (including
production   taxes,  ad  valorem  taxes  and  operating   expenses)  and  future
development  costs. The  calculations  used to produce the figures in this table
are based on current  cost and price  factors at December  31 for each year.  We
cannot  assure you that the proved  reserves  will all be  developed  within the
periods used in the calculations or that prices and costs will remain constant.

                                                            2003                  2002                  2001
                                                     --------------------  --------------------  -------------------
                                                     --------------------  --------------------  -------------------

Future cash inflows                                  $     336,795,385     $    308,381,837      $    199,162,921

Future production and development costs-
  Production                                               109,468,727          105,629,872            77,526,278
  Development                                               21,460,459           23,350,811            23,610,596
                                                     --------------------  --------------------  -------------------

Future net cash flows before income taxes                  205,866,199          179,401,154            98,026,047
Future income taxes                                        (46,885,360)         (38,611,577)          (13,281,358)
                                                     --------------------  --------------------  -------------------

Future net cash flows after income taxes                   158,980,839          140,789,577            84,744,689
10% annual discount for estimated timing
  of cash flows                                            (70,653,419)         (63,165,742)          (35,895,306)
                                                     --------------------  --------------------  -------------------

Standardized measure of discounted
 Future net cash flows(1)                            $      88,327,420    $      77,623,835     $      48,849,383
                                                     ====================  ====================  ===================

(1) The average prices of our proved  reserves were $29.51 per Bbl and $5.82 per
Mcf,  $28.72 per Bbl and $4.43 per Mcf, and $17.67 and $2.43 per Mcf at December
31, 2003, 2002 and 2001 respectively.

Significant Properties.

     Summary  information  on our properties  with proved  reserves is set forth
below as of December 31, 2003.

                        Productive Wells                            Proved Reserves                            Present
                 --------------------------------------------------------------------------------------- ----------------
                                                                                                               Value (1)
                                                                                                               ---------
                     Gross             Net
                   Productive       Productive         Crude               Natural
                     Wells            Wells             Oil                  Gas             Total             Amount
                 --------------  ---------------------------------     --------------  ----------------   ---------------
                                                      (MBbl)               (MMcf)           (MBOE)              ($M)

Texas                185             181.03          2,969               18,717            6,088           $  67,235
Colorado              35              23.62            355                6,090            1,370              11,303
Oklahoma              28              28.00            150                  -                150               1,301
Louisiana             17              16.88          1,558                7,853            2,867              34,484
Mississippi            1                .37              6                  -                  6                  73
                ------------------------------------------------- ------------------------------------   --------------
          Total      266             249.90          5,038               32,660           10,481           $   114,396
                ================================================= ====================================   ==============

(1) The average prices of our proved  reserves were $29.51 per Bbl and $5.82 per
Mcf at December 31, 2003.
                                       6

     All information set forth herein relating to our proved reserves, estimated
future  net cash flows and  present  values is taken from  reports  prepared  by
Pressler Petroleum Consultants,  independent petroleum engineers.  The estimates
of these  engineers  were based upon their review of  production  histories  and
other  geological,  economic,  ownership  and  engineering  data provided by and
relating  to us. No reports  on our  reserves  have been filed with any  federal
agency.  In  accordance  with the  SEC's  guidelines,  our  estimates  of proved
reserves and the future net revenues from which  present  values are derived are
made  using  year end  crude oil and  natural  gas sales  prices  held  constant
throughout  the  life  of the  properties  (except  to  the  extent  a  contract
specifically provides otherwise). Operating costs, development costs and certain
production-related  taxes were  deducted  in arriving  at  estimated  future net
revenues, but such costs do not include debt service, general and administrative
expenses and income taxes.

     There are  numerous  uncertainties  inherent  in  estimating  crude oil and
natural  gas  reserves  and their  values,  including  many  factors  beyond our
control.  The reserve  data set forth in this  report are based upon  estimates.
Reservoir  engineering is a subjective  process,  which involves  estimating the
sizes of underground  accumulations  of crude oil and natural gas that cannot be
measured in an exact manner.  The accuracy of any reserve estimate is a function
of the quality of available data,  engineering and geological  interpretation of
that  data,  and  judgment.  As a  result,  estimates  of  different  engineers,
including  those used by us, may vary.  In  addition,  estimates of reserves are
subject to revision based upon actual production, results of future development,
exploitation  and exploration  activities,  prevailing crude oil and natural gas
prices,  operating  costs and other  factors.  Such  revisions  may be material.
Accordingly,  reserve estimates are often different from the quantities of crude
oil and natural gas that are ultimately  recovered and are highly dependent upon
the accuracy of the assumptions  upon which they are based. We cannot assure you
that the  estimates  contained  in this report are accurate  predictions  of our
crude oil and natural gas reserves or their  values.  Estimates  with respect to
proved reserves that may be developed and produced in the future are often based
upon  volumetric  calculations  and upon  analogy to similar  types of  reserves
rather than upon actual production history. Estimates based on these methods are
generally  less  reliable  than  those  based  on  actual  production   history.
Subsequent  evaluation of the same reserves based upon  production  history will
result in potentially substantial variations in the estimated reserves.
                                       7

Production, Revenue and Price History.

     The  following  table sets forth  information  (associated  with our proved
reserves)  regarding  production  volumes of crude oil and natural gas, revenues
and expenses  attributable  to such  production  (all net to our  interests) and
certain price and cost  information  for the years ended December 31, 2003, 2002
and 2001.

                              2003               2002                2001
                          -------------    ----------------    ----------------
Production
    Oil (Bbl)                  221,433             278,374             294,276
    Natural gas (Mcf)        1,191,350           1,487,048           1,594,899
                          -------------    ----------------    ----------------
        Total (BOE)            419,991             526,215             560,092

Revenue
    Oil production        $  5,362,657     $     5,859,568     $     6,690,338
    Natural gas production   5,481,803           4,587,601           5,735,765
                          -------------    ----------------    ----------------
         Total             $10,844,460         $10,447,169         $12,426,103

Operating Expenses        $  5,527,841     $     5,430,205     $     5,155,500

Production Data
    Average sales price
        Per barrel of oil $      24.22     $         21.05     $         22.73
        Per Mcf of
             natural gas          4.60                3.09                3.60
        Per BOE                  25.82               19.85               22.19

    Average expenses per BOE
        Lease operating          13.16               10.32               9.20
        Depreciation, depletion
        and amortization          5.30                5.13                4.45
        General and
        administrative    $       5.39                3.28                3.05



Productive Wells at December 31, 2003:

     The  following  table  shows  the  number  of  productive  wells  we own by
location:

                     Gross            Net            Gross             Net
                   Oil Wells       Oil Wells       Gas Wells        Gas Wells
                  ------------    ------------    -------------    ------------
Texas                 109            108.81            76           72.22
Colorado               22             14.37            13            9.25
Oklahoma               28             28.00            -               -
Louisiana              13             12.88             4            4.00
Mississippi             1               .37            -               -
                  ------------    ------------    -------------    ------------
     Total            173            164.43            93           85.47
                  ============    ============    =============    ============
                                       8


Developed Acreage at December 31, 2003.

     The following  table shows the developed  acreage that we own, by location,
which is acreage  spaced or assigned to  productive  wells.  Gross acres are the
total  acres in which we own a  working  interest.  Net acres are the sum of the
fractional working interests we own in gross acres.

                                          Gross Acres             Net Acres
                                     ------------------    --------------------
        Texas                                18,380                 14,255
        Colorado                              5,000                  2,700
        Louisiana                             1,695                  1,256
        Oklahoma                                900                    684
                                     ------------------    --------------------
                        Total                25,975                 18,895
                                     ==================    ====================

Undeveloped Acreage at December 31, 2003.

     The following table shows the undeveloped acreage that we own, by location.
Undeveloped acreage is acreage on which wells have not been drilled or completed
to a point that would permit the  production of  commercial  quantities of crude
oil and natural gas.

                                          Gross Acres             Net Acres
                                      ------------------    --------------------
        Texas                               18,070                  14,749
        Colorado                            10,000                   6,000
        Louisiana                               80                      55
        Oklahoma                               900                     684
                                      ------------------    --------------------
                        Total               29,050                  21,488
                                      ==================    ====================

Drilling Results.

     We did not drill any wells in 2003.  In 2002,  we drilled  one  exploratory
well, in which we own 18% working interest,  that resulted in a dry hole and one
development well, in which we own 100% working interest, that is productive.  We
drilled  three  wells  in 2001,  all of which  were  development  wells  and are
currently productive.  These development wells included two horizontal wells, in
which we own 96% and 89% working interest, drilled by sidetracking from existing
wellbores in the Madisonville  Field,  Texas, and one well, in which we own 100%
working interest, that was deepened in our Leona River Field, Texas.
                                       9

Risk Factors.

     Our success  depends  heavily  upon our ability to market our crude oil and
natural gas production at favorable prices.

     In recent decades, there have been both periods of worldwide overproduction
and  underproduction  of crude oil and natural gas, and periods of increased and
relaxed energy  conservation  efforts.  Such  conditions have resulted in excess
supply  of, and  reduced  demand  for,  crude oil on a  worldwide  basis and for
natural gas on a domestic basis. At other times, there has been short supply of,
and increased demand for, crude oil and, to a lesser extent,  natural gas. These
changes have resulted in dramatic price fluctuations.

     The  degree  to  which  we are  leveraged  could  possibly  have  important
consequences to our shareholders, including the following:

     (i)  Our indebtedness,  acquisitions, working capital, capital expenditures
          or other purposes may be impaired;

     (ii) Funds available for our operations and general  corporate  purposes or
          for capital expenditures will be reduced as a result of the dedication
          of a substantial portion of our consolidated cash flow from operations
          to the payment of the principal and interest on our indebtedness;

     (iii)We may be more  highly  leveraged  than  certain  of our  competitors,
          which may place us at a competitive disadvantage;

     (iv) The agreements governing our long-term indebtedness and bank loans may
          contain restrictive financial and operating covenants;

     (v)  An  event of  default  (not  cured  or  waived)  under  financial  and
          operating  covenants contained in our debt instruments could occur and
          have a material adverse effect;

     (vi) Certain of the  borrowings  under our debt  agreements  have  floating
          rates of interest,  which causes us to be  vulnerable  to increases in
          interest rates; and,

     (vii)Our substantial  degree of leverage could make us more vulnerable to a
          downturn in general economic conditions.

     Our  ability  to make  principal  and  interest  payments  under  long-term
indebtedness and bank loans will be dependent upon our future performance, which
is subject to financial,  economic and other  factors,  some of which are beyond
our control.

     We cannot  assure you that our  current  level of  operating  results  will
continue or improve.  We believe that we will need to access capital  markets in
the  future in order to  provide  the  funds  necessary  to repay a  significant
portion of our indebtedness. We cannot assure you that any such refinancing will
be possible or that we can obtain any additional financing, particularly in view
of our  anticipated  high levels of debt. If no such  refinancing  or additional
financing were available, we could default on our debt obligations.
                                       10



     We have incurred net losses in the past and there can be no assurance  that
we will be profitable in the future.

     Our future operating results may fluctuate  significantly  depending upon a
number  of  factors,  including  industry  conditions,  prices  of crude oil and
natural gas, rates of production,  timing of capital  expenditures  and drilling
success.  These variables could have a material  adverse effect on our business,
financial  condition,  results of operations  and the market price of our common
stock.

     Estimates of crude oil and natural gas reserves depend on many  assumptions
that may turn our to be inaccurate.

     Estimates  of our proved  reserves  for crude oil and  natural  gas and the
estimated  future net revenues  from the  production  of such reserves rely upon
various  assumptions,  including  assumptions  as to crude oil and  natural  gas
prices,  drilling  and  operating  expenses,  capital  expenditures,  taxes  and
availability  of funds.  The  process of  estimating  crude oil and  natural gas
reserves is complex and imprecise.

     Actual  future  production,  crude oil and natural  gas  prices,  revenues,
taxes,   development   expenditures,   operating   expenses  and  quantities  of
recoverable crude oil and natural gas reserves may vary  substantially  from the
estimates we obtain from reserve  engineers.  Any significant  variance in these
assumptions could materially  affect the estimated  quantities and present value
of reserves we have set forth.  In addition,  our proved reserves may be subject
to downward or upward revision due to factors that are beyond our control,  such
as production history, results of future exploration and development, prevailing
crude oil and natural gas prices and other factors.

     Approximately  25% of our total  estimated  proved reserves at December 31,
2003 were proved undeveloped reserves, which are by their nature less certain.

     Recovery of such reserves  requires  significant  capital  expenditures and
successful  drilling  operations.  The  reserve  data set  forth in the  reserve
engineer reports assumes that substantial  capital  expenditures are required to
develop such reserves.  Although cost and reserve estimates  attributable to our
crude oil and  natural  gas  reserves  have been  prepared  in  accordance  with
industry  standards,  we cannot be sure that the  estimated  costs are accurate,
that development will occur as scheduled or that the results of such development
will be as estimated.

     You should not interpret  the present  value  referred to in this report or
documents  incorporated  herein by reference as the current  market value of our
estimated crude oil and natural gas reserves.

     In accordance with SEC  requirements,  the estimated  discounted future net
cash flows from proved  reserves are  generally  based on prices and costs as of
the date of the  estimate.  Actual  future  prices  and costs may be  materially
higher or lower.

     The estimates of our proved reserves and the future net revenues from which
the present  value of our  properties  is derived were  calculated  based on the
actual  prices of our  various  properties  on a  property-by-property  basis at
December 31, 2003. The average  prices of all properties  were $29.51 per barrel
of oil and $5.82 per thousand cubic feet (Mcf) of natural gas at that date.

     Actual  future  net cash  flows  will  also be  affected  by  increases  or
decreases in  consumption by crude oil and natural gas purchasers and changes in
governmental  regulations or taxation. The timing of both the production and the
incurring of expenses in connection with the development and production of crude
oil and natural gas properties affect the timing of actual future net cash flows
                                       11


from proved reserves. In addition, the 10% discount factor, which is required by
the SEC to be used in calculating discounted future net cash flows for reporting
purposes, is not necessarily the most appropriate discount factor. The effective
interest rate at various times and the risks associated with our business or the
oil and gas  industry in general  will affect the  accuracy of the 10%  discount
factor.

     Except to the extent that we acquire properties  containing proved reserves
or  conduct  successful  development  or  exploitation  activities,  our  proved
reserves will decline as they are produced.

     In  general,  the  volume of  production  from  crude oil and  natural  gas
properties  declines as reserves are depleted.  Our future crude oil and natural
gas  production  is highly  dependent  upon our success in finding or  acquiring
additional reserves.

     The  business of  acquiring,  enhancing  or  developing  reserves  requires
considerable capital.

     Our ability to make the necessary capital  investment to maintain or expand
our asset base of crude oil and  natural gas  reserves  could be impaired to the
extent that cash flow from operations is reduced and external sources of capital
become limited or  unavailable.  In addition,  we cannot be sure that our future
acquisition and development activities will result in additional proved reserves
or that we will be able to drill productive wells at acceptable costs.

     Crude oil and natural gas drilling and production activities are subject to
numerous risks, many of which are beyond our control.

     These risks include (i) the possibility that no commercially productive oil
or gas  reservoirs  will  be  encountered;  and,  (ii)  that  operations  may be
curtailed,  delayed  or  canceled  due to title  problems,  weather  conditions,
governmental requirements, mechanical difficulties, or delays in the delivery of
drilling rigs and other equipment that may limit our ability to develop, produce
and market our  reserves.  We cannot  assure you that new wells we drill will be
productive or that we will recover all or any portion of our  investment in such
new wells.

     Drilling for crude oil and natural gas may not be profitable.

     Any wells that we drill may be dry wells or wells that are not sufficiently
productive  to be  profitable  after  drilling.  Such wells will have a negative
impact on our profitability.  In addition,  our properties may be susceptible to
drainage from production by other operators on adjacent properties.

     Our industry  experiences  numerous  operating risks that could cause us to
suffer substantial losses.

     Such  risks  include   fire,   explosions,   blowouts,   pipe  failure  and
environmental  hazards,  such as oil  spills,  natural  gas leaks,  ruptures  or
discharges of toxic gases.  We could also suffer losses due to personnel  injury
or loss of life;  severe damage to or destruction of property;  or environmental
damage that could result in clean-up responsibilities, regulatory investigation,
penalties or suspension of our operations. In accordance with customary industry
practice, we maintain insurance policies against some, but not all, of the risks
described  above. Our insurance  policies may not adequately  protect us against
loss or liability. There is no guarantee that insurance policies that protect us
against the many risks we face will  continue  to be  available  at  justifiable
premium levels.

     As owners and operators of crude oil and natural gas properties,  we may be
liable under federal,  state and local environmental  regulations for activities
involving water pollution, hazardous waste transport, storage, disposal or other
activities.
                                       12


     Our past growth has been  attributable  to  acquisitions of producing crude
oil and natural gas properties  with proved  reserves.  There are risks involved
with such acquisitions.

     The  successful   acquisition  of  properties  requires  an  assessment  of
recoverable reserves,  future crude oil and natural gas prices, operating costs,
potential  environmental  and other  liabilities,  and other factors  beyond our
control.  Such assessments are necessarily inexact and their accuracy uncertain.
In  connection  with such an  assessment,  we  perform  a review of the  subject
properties that we believe to be generally  consistent with industry  practices.
Such a review,  however, will not reveal all existing or potential problems, nor
will it  permit  us, as the  buyer,  to become  sufficiently  familiar  with the
properties  to fully  assess  their  capabilities  or  deficiencies.  We may not
inspect every well and, even when an inspection is  undertaken,  structural  and
environmental problems may not necessarily be observable.

     When  we  acquire  properties,  in  most  cases,  we are  not  entitled  to
contractual indemnification for pre-closing liabilities, including environmental
liabilities.

     We  generally  acquire  interests  in  properties  on an "as is" basis with
limited  remedies  for  breaches of  representations  and  warranties.  In those
circumstances   in  which  we  have  contractual   indemnification   rights  for
pre-closing  liabilities,  we cannot  assure you that the seller will be able to
fulfill its  contractual  obligations.  In addition,  the competition to acquire
producing crude oil and natural gas properties is intense and many of our larger
competitors have financial and other resources  substantially greater than ours.
We cannot  assure  you that we will be able to acquire  producing  crude oil and
natural  gas  properties  that  have  economically   recoverable   reserves  for
acceptable prices.

     We  may  acquire  royalty,  overriding  royalty  or  working  interests  in
properties that are less than the controlling interest.

     In such  cases,  it is likely  that we will not  operate,  nor  control the
decisions affecting the operations,  of such properties. We intend to limit such
acquisitions  to  properties  operated by  competent  parties  with whom we have
discussed their plans for operation of the properties.

     We will need  additional  financing  in the future to  continue to fund our
developmental and exploitation activities.

     We have made and will continue to make substantial capital  expenditures in
our  exploitation and development  projects.  We intend to finance these capital
expenditures with cash flow from operations,  existing financing arrangements or
new  financing.  We cannot  assure you that such  additional  financing  will be
available.  If it is not available,  our development and exploitation activities
may have to be curtailed,  which could adversely affect our business,  financial
condition and results of operations, as was the case in 2003.

     The  marketing of our natural gas  production  depends,  in part,  upon the
availability, proximity and capacity of natural gas gathering systems, pipelines
and processing facilities.

     We could be  adversely  affected by changes in existing  arrangements  with
transporters  of our  natural  gas  since  we do not own  most of the  gathering
systems and pipelines  through which our natural gas is delivered to purchasers.
Our  ability to  produce  and market  our  natural  gas could also be  adversely
affected  by   federal,   state  and  local   regulation   of   production   and
transportation.
                                       13



     The crude oil and natural gas industry is highly  competitive in all of its
phases.

     Competition  is  particularly  intense with respect to the  acquisition  of
desirable  producing  properties,  the  acquisition of crude oil and natural gas
prospects  suitable  for  enhanced  production   efforts,   and  the  hiring  of
experienced personnel. Our competitors in crude oil and natural gas acquisition,
development,  and  production  include the major oil  companies,  in addition to
numerous independent crude oil and natural gas companies, individual proprietors
and drilling programs.

     Many of these  competitors  possess  and  employ  financial  and  personnel
resources  substantially  in excess of those which are  available to us and may,
therefore,  be able to pay more for desirable producing properties and prospects
and to define,  evaluate,  bid for, and  purchase a greater  number of producing
properties and prospects than our financial or personnel  resources will permit.
Our ability to generate  reserves in the future will be dependent on our ability
to  select  and  acquire  suitable  producing  properties  and  prospects  while
competing with these companies.

     The domestic oil industry is extensively  regulated at both the federal and
state levels.  Although we believe we are presently in compliance with all laws,
rules and regulations,  we cannot assure you that changes in such laws, rules or
regulations,  or the  interpretation  thereof,  will not have a material adverse
effect on our financial condition or the results of our operations.

     Legislation affecting the oil and gas industry is under constant review for
amendment or  expansion,  frequently  increasing  the  regulatory  burden on the
industry.  There are numerous  federal and state  agencies  authorized  to issue
rules  and  regulations  affecting  the oil and gas  industry.  These  rules and
regulations are often difficult and costly to comply with and carry  substantial
penalties for noncompliance.

     State statutes and  regulations  require  permits for drilling  operations,
drilling  bonds,  and  reports  concerning  operations.  Most  states  also have
statutes  and  regulations  governing   conservation   matters,   including  the
unitization or pooling of properties,  and the establishment of maximum rates of
production from wells. Some states have also enacted statutes  prescribing price
ceilings for natural gas sold within their states.

     Our industry is also  subject to numerous  laws and  regulations  governing
plugging and  abandonment of wells,  discharge of materials into the environment
and other matters  relating to  environmental  protection.  The heavy regulatory
burden on the oil and gas industry  increases the costs of our doing business as
an oil and gas company, consequently affecting our profitability.

     Our board of directors is authorized,  without further  shareholder action,
to issue  preferred  stock in one or more series and to  designate  the dividend
rate, voting rights and other rights,  preferences and restrictions of each such
series.

     As of March 29, 2004, there was a total of 19,000 shares of preferred stock
issued and  outstanding  in three  series,  including  8,000 shares of Series D,
9,000  shares  of Series E and  2,000  shares  of Series F. The 8,000  shares of
Series D  Preferred  Stock are held by a former  director,  the 9,000  shares of
Series E Preferred Stock are held by a current  director and the 2,000 shares of
Series F are held by our largest  lender.  Our preferred  stock is senior to our
common stock  regarding  liquidation.  The holders of the preferred stock do not
have voting rights or preemptive  rights nor are they subject to the benefits of
any retirement or sinking fund.

     The  Series D  preferred  stock is not  entitled  to  dividends,  nor is it
redeemable,  however it is convertible  to common stock at anytime.  None of the
8,000  outstanding  shares of Series D preferred stock has been converted.  On a
fully  converted  basis,  the 8,000  shares of Series D  preferred  stock  would
convert to 500,000 shares of common stock.
                                       14


     The Series E preferred  stock is entitled to receive  dividends at the rate
of $12.50 per share per annum,  payable  quarterly,  as declared by the board of
directors,  until June 30, 2004 when the  dividend  rate shall be  increased  to
$30.00 per share per annum.  The board of directors  did not declare  payment of
dividends during 2003. The Series E preferred stock is redeemable in whole or in
part at any time,  at the  option of the  issuer,  at a price of $500 per share,
plus all accrued and undeclared or unpaid  dividends;  except that, prior to our
redemption  of the  remaining,  the  holders  of record  shall be given a 60-day
written notice of the issuer's  intent to redeem and the  opportunity to convert
the Series E  preferred  stock to common  stock.  The  conversion  price for the
Series E preferred  stock is based on $2.00 per share of common  stock.  None of
the 9,000  outstanding  shares of Series E preferred  stock has been redeemed or
converted.  On a fully converted  basis,  the 9,000 shares of Series E preferred
stock would convert to 2,250,000 shares of common stock.

     The Series F preferred  stock is entitled to receive  dividends at the rate
of $12.50 per share per annum,  payable  quarterly,  as declared by the board of
directors,  until May 30,  2006 when the  dividend  rate shall be  increased  to
$30.00 per share per annum.  The Series F preferred stock is redeemable in whole
or in part at any  time,  at the  option of the  issuer,  at a price of $500 per
share, plus all accrued and undeclared or unpaid  dividends;  except that, after
two years from the date of the original issuance, June 1, 2003, and prior to our
redemption  of the  remaining  shares,  the  holders of record  shall be given a
60-day  written notice of the issuer's  intent to redeem and the  opportunity to
convert the Series F preferred stock to common stock.  The conversion  price for
the Series F preferred  stock is based on $1.00 per share of common stock.  None
of the 2,000 outstanding shares of Series F preferred stock has been redeemed or
converted.  On a fully converted  basis,  the 2,000 shares of Series F preferred
stock would convert to 1,000,000 shares of common stock.

     We do not pay dividends on our common stock.

     Our board of directors  presently intends to retain all of our earnings for
the expansion of our business,  therefore we do not anticipate distributing cash
dividends on our common  stock in the  foreseeable  future.  Any decision of our
board of  directors  to pay  cash  dividends  will  depend  upon  our  earnings,
financial position, cash requirements and other factors.

     The  holders  of our common  stock do not have  cumulative  voting  rights,
preemptive rights or rights to convert their common stock to other securities.

     We are  authorized to issue  40,000,000  shares of common stock,  $.001 par
value per share. As of March 29, 2004,  there were  18,492,541  shares of common
stock issued and outstanding.  Since the holders of our common stock do not have
cumulative  voting  rights,  the holder(s) of a majority of the shares of common
stock present,  in person or by proxy,  will be able to elect all of the members
of our board of directors. The holders of shares of our common stock do not have
preemptive rights or rights to convert their common stock into other securities.
At December 31, 2003, we had  outstanding  warrants and options for the purchase
of  3,067,000  shares of common  stock at prices  ranging from $.75 to $1.81 per
share,  including  employee stock options to purchase 1,102,000 shares at prices
ranging  from  $.75 to $1.81  per  share.  If we issue  additional  shares,  the
existing  shareholders'  percentage  ownership  of our  company  may be  further
diluted.

     Actual results may differ from forward-looking statements.

     We make  forward-looking  statements  throughout this report.  Whenever you
read a statement that is not simply a statement of historical fact, such as when
we describe what we "believe,"  "expect" or "anticipate"  will occur,  and other
similar statements,  you must remember that our expectations may not be correct,
even though we believe they are  reasonable.  These  forward-looking  statements
generally relate to our plans and objectives for future operations and are based
upon our management's  reasonable  estimates of future results and trends. We do
not  guarantee  that the  transactions  and  events  described  will  happen  as
described (or that they will happen at all). In connection with  forward-looking
statements,  you should  carefully  review the  factors set forth in this report
under "Risk Factors."
                                       15


ITEM 3. Legal Proceedings.

     From time to time, we are involved in litigation relating to claims arising
out of our  operations  or from  disputes  with vendors in the normal  course of
business.  As of March 29,  2004,  we were not engaged in any legal  proceedings
that are expected,  individually or in the aggregate, to have a material adverse
effect on us.

ITEM 4. Submission of Matters to a Vote of Security Holders.

     We did not submit any matters to a vote of our security  holders during the
fourth quarter of the fiscal year ended December 31, 2003.

                                       16



                                     PART II

ITEM 5. Market for Our Common Stock and Related Stockholder Matters.

     Our common stock is traded  over-the-counter  under the symbol "GULF".  The
high and low trading prices for the common stock for each quarter in 2003,  2002
and 2001 are set forth  below.  The  trading  prices  represent  prices  between
dealers,  without  retail  mark-ups,  mark-downs,  or  commissions,  and may not
necessarily represent actual transactions.

                                                       High             Low
                                                       ----             ---
                  2003
                  ----
                  First Quarter                       $ .45             $.42
                  Second Quarter                        .47              .35
                  Third Quarter                         .47              .43
                      Fourth Quarter                    .47              .32

                  2002
                  ----
                  First Quarter                       $ .66             $.55
                  Second Quarter                        .60              .46
                  Third Quarter                         .51              .20
                      Fourth Quarter                    .44              .32

                  2001
                  ----
                  First Quarter                       $1.46             $.39
                  Second Quarter                       1.01              .53
                  Third Quarter                         .96              .48
                  Fourth Quarter                        .72              .58


     We are authorized to issue  40,000,000  shares of Class A common stock, par
value $.001 per share (the "common  stock").  As of March 29,  2004,  there were
18,492,541   shares  of  common  stock  issued  and   outstanding  and  held  by
approximately 580 beneficial owners. Our common stock is traded over-the-counter
(OTC)  under the  symbol  "GULF".  Fidelity  Transfer  Company,  1800 South West
Temple,  Suite 301, Box 53, Salt Lake City,  Utah 84115,  (801)  484-7222 is the
transfer agent for the common stock.

     Holders of common stock are entitled,  among other things,  to one vote per
share on each matter  submitted to a vote of  shareholders  and, in the event of
liquidation,  to share ratably in the  distribution  of assets  remaining  after
payment of liabilities (including preferential  distribution and dividend rights
of holders of  preferred  stock).  Holders  of common  stock have no  cumulative
rights, and, accordingly, the holders of a majority of the outstanding shares of
the common stock have the ability to elect all of the directors.

     Holders of common stock have no preemptive or other rights to subscribe for
shares.  Holders  of  common  stock are  entitled  to such  dividends  as may be
declared by the Board out of funds legally  available  therefore.  We have never
paid cash  dividends on the common stock and do not  anticipate  paying any cash
dividends in the foreseeable future.
                                       17


Preferred Stock.

     Our board of directors is authorized,  without further  shareholder action,
to issue  preferred  stock in one or more series and to  designate  the dividend
rate, voting rights and other rights,  preferences and restrictions of each such
series.  As of March 29, 2004,  there was a total of 19,000  shares of preferred
stock issued and  outstanding in three series,  including 8,000 shares of Series
D, 9,000  shares of Series E and 2,000  shares of Series F. The 8,000  shares of
Series D  Preferred  Stock are held by a former  director,  the 9,000  shares of
Series E Preferred Stock are held by a current  director and the 2,000 shares of
Series F are held by our largest  lender.  Our preferred  stock is senior to our
common stock  regarding  liquidation.  The holders of the preferred stock do not
have voting rights or preemptive  rights nor are they subject to the benefits of
any retirement or sinking fund.

     The  Series D  preferred  stock is not  entitled  to  dividends,  nor is it
redeemable,  however it is convertible  to common stock at anytime.  None of the
8,000  outstanding  shares of Series D preferred stock has been converted.  On a
fully  converted  basis,  the 8,000  shares of Series D  preferred  stock  would
convert to 500,000 shares of common stock.

     The Series E preferred  stock is entitled to receive  dividends at the rate
of $12.50 per share per annum,  payable  quarterly,  as declared by the board of
directors,  until June 30, 2004 when the  dividend  rate shall be  increased  to
$30.00 per share per annum.  The board of directors  did not declare  payment of
dividends during 2003. The Series E preferred stock is redeemable in whole or in
part at any time,  at the  option of the  issuer,  at a price of $500 per share,
plus all accrued and undeclared or unpaid  dividends;  except that, prior to our
redemption  of the  remaining  shares,  the  holders of record  shall be given a
60-day  written notice of the issuer's  intent to redeem and the  opportunity to
convert the Series E preferred stock to common stock.  The conversion  price for
the Series E preferred  stock is based on $2.00 per share of common stock.  None
of the 9,000 outstanding shares of Series E preferred stock has been redeemed or
converted.  On a fully converted  basis,  the 9,000 shares of Series E preferred
stock would convert to 2,250,000 shares of common stock.

     The Series F preferred  stock is entitled to receive  dividends at the rate
of $12.50 per share per annum,  payable  quarterly,  as declared by the board of
directors,  until May 30,  2006 when the  dividend  rate shall be  increased  to
$30.00 per share per annum.  The Series F preferred stock is redeemable in whole
or in part at any  time,  at the  option of the  issuer,  at a price of $500 per
share, plus all accrued and undeclared or unpaid  dividends;  except that, after
two years from the date of the original issuance, June 1, 2003, and prior to our
redemption  of the  remaining  shares,  the  holders of record  shall be given a
60-day  written notice of the issuer's  intent to redeem and the  opportunity to
convert the Series F preferred stock to common stock.  The conversion  price for
the Series F preferred  stock is based on $1.00 per share of common stock.  None
of the 2,000 outstanding shares of Series F preferred stock has been redeemed or
converted.  On a fully converted  basis,  the 2,000 shares of Series F preferred
stock would convert to 1,000,000 shares of common stock.

Outstanding Options and Warrants.


     At March 29, 2004, we had outstanding warrants and options for the purchase
3,067,000 shares of common stock at prices ranging from $.75 to $1.81 per share,
including  employee stock options to purchase 1,102,000 shares at prices ranging
from $.75 to $1.81 per share.
                                       18

Recent Sales of Unregistered Securities.

     During 2002 and 2003, and to March 29, 2004, we granted warrants or options
exercisable  for shares of common stock not registered  under the Securities Act
of 1933, as amended,  and exempt under Section 4(2) of the Act. All the grantees
were current employees,  consultants or accredited investors not affiliated with
the  company.  No  underwriters  were used,  and no  underwriting  discounts  or
commissions were paid in connection with the grants.

                                             Exercisable  Exercise
                                             -----------  --------
             Derivative  Grantee(s)            Shares       Price  Consider-
                                                                      ation
             ----------    ----------          ------       -----  -------------
  Date
  ----

02/25/02  Warrant    Director(1)          270,000     $   .75  Compensation
04/30/02  Warrant    Employee             100,000     $   .75  Compensation
07/15/02  Warrant    Accredited Investor   75,000     $   .75  Loan transaction
10/31/02  Option     Employee              35,000     $   .75  Compensation
11/06/02  Warrant    Director             625,000     $   .75  Loan transaction
12/02/02  Warrant    Accredited Investor   75,000     $   .75  Loan transaction
01/24/03  Warrant    Accredited Investor  100,000     $   .75  Loan transaction
02/12/03  Warrant    Accredited Investor   50,000     $   .75  Loan transaction
04/01/03  Option     Employee              35,000     $   .75  Compensation

(1) 200,000, 50,000 and 20,000 warrants originally issued to an officer/director
(currently  a director)  in 1996 at exercise  prices of $3.00,  $5.00 and $5.75,
respectively, were re-priced to $.75 per share.
                                       19


ITEM 6. Selected Financial Data.

     The following  table sets forth selected  historical  financial data of our
company as of December 31, 2003,  2002, 2001, 2000 and 1999, and for each of the
periods then ended. See "Item 1. Business" and "Item 7. Management's  Discussion
and  Analysis of  Financial  Condition  and Results of  Operations."  The income
statement  data for the years ended  December  31,  2003,  2002 and 2001 and the
balance  sheet data at December  31, 2003 and 2002 are derived  from our audited
financial  statements  contained elsewhere herein. The income statement data for
the  years  ended  December  31,  2000 and 1999 and the  balance  sheet  data at
December 31, 2001, 2000 and 1999 are derived from our Annual Report on Form 10-K
for  those  periods.   You  should  read  this  data  in  conjunction  with  our
consolidated  financial  statements  and the notes  thereto  included  elsewhere
herein.

                                    --------------------------------------------------------------------------------------------
                                                                      Year Ended December 31,
                                          2003               2002               2001               2000              1999
                                    -----------------  -----------------  -----------------  ----------------- -----------------
Income Statement Data
- ---------------------

Operating Revenues                  $  11,010,723      $  10,839,797      $  12,990,581      $    8,984,175    $     2,812,639

Net income (loss) from
     operations                           917,571            927,655          3,451,875           2,464,017         (1,464,094)

Net income (loss)                     (3,024,426)        (4,502,313)         1,044,291             352,774         (2,269,506)

Dividends on preferred stock             (127,083)          (112,500)           (56,250)              -               (450,684)

Net income (loss) available to
     common shareholders               (3,151,509)        (4,614,813)           988,401             352,774         (2,720,190)

Net income (loss), per share
     of common stock                $        (.17)     $        (.25)     $         .05      $          .02    $          (.34)

Weighted average number
     of shares of common
     stock outstanding                  18,492,541        18,492,541         18,464,343          17,293,848          7,953,147

Balance Sheet Data
- ------------------

Current assets                      $    1,742,689     $    2,353,046     $   2,205,862      $    2,934,804    $     1,357,465

Total assets                            52,428,774         53,088,941        51,379,209          32,374,128         20,009,793

Current liabilities                     44,619,652         43,998,566        12,492,365           7,594,986          4,650,691

Long-term obligations                    1,393,607            137,808        26,541,957          18,077,371         11,304,318

Other liabilities                          591,467          1,128,993             -                   -                  -

Stockholders' Equity                $    5,824,648     $    7,823,574    $   12,344,887      $    6,701,771    $     4,054,784
                                       20

ITEM 7. Management's  Discussion and Analysis of Financial Condition and Results
of Operations.

Overview.

     We are engaged  primarily in the  acquisition,  development,  exploitation,
exploration  and  production  of crude  oil and  natural  gas.  Our  focus is on
increasing  production  from our existing  crude oil and natural gas  properties
through  the  further   exploitation,   development  and  exploration  of  those
properties,  and on acquiring  additional interests in crude oil and natural gas
properties. Our gross revenues are derived from the following sources:

     1.   Oil and gas  sales  that are  proceeds  from the sale of crude oil and
          natural gas production to midstream purchasers;

     2.   Operating  overhead  and other income that  consists of earnings  from
          operating  crude oil and  natural  gas  properties  for other  working
          interest owners, and marketing and transporting natural gas. This also
          includes earnings from other miscellaneous activities.

     3.   Well  servicing  revenues that are earnings from the operation of well
          servicing equipment under contract to other operators. During 2003, we
          worked only for our own account.

     The  following is a discussion  of our  consolidated  financial  condition,
results of operations,  financial  condition and capital  resources.  You should
read this discussion in conjunction with our Consolidated  Financial  Statements
and the Notes thereto contained elsewhere herein. See "Financial Statements."

Results of Operations.

     The factors which most  significantly  affect our results of operations are
(1) the sales price of crude oil and natural  gas,  (2) the level of total sales
volumes of crude oil and natural gas, (3) the cost and  efficiency  of operating
our own properties, (4) depletion and depreciation of oil and gas property costs
and related equipment (5) the level of and interest rates on borrowings, (6) the
level and success of new  acquisitions  and development of existing  properties,
and (7) the adoption of changes in accounting rules.

     We  consider  depletion  and  depreciation  of oil and gas  properties  and
related  support  equipment  to be  critical  accounting  estimates,  based upon
estimates of oil and gas reserves.

     The  estimates  of oil and gas  reserves  utilized  in the  calculation  of
depletion  and   depreciation   are  estimated  in  accordance  with  guidelines
established  by  the  Securities  and  Exchange  Commission  and  the  Financial
Accounting  Standards  Board,  which require that reserve  estimates be prepared
under existing economic and operating conditions with no provision for price and
cost  escalations  over  prices  and  costs  existing  at year  end,  except  by
contractual arrangements.

     We emphasize that reserve estimates are inherently imprecise.  Accordingly,
the  estimates  are  expected  to change  as more  current  information  becomes
available.  Our policy is to amortize  capitalized oil and gas costs on the unit
of  production  method,  based upon these  reserve  estimates.  It is reasonably
possible the estimates of future cash inflows, future gross revenues, the amount
of oil  and gas  reserves,  the  remaining  estimated  lives  of the oil and gas
properties,  or any  combination of the above may be increased or reduced in the
near term. If reduced, the carrying amount of capitalized oil and gas properties
may be reduced materially in the near term.
                                       21



     Comparative  results of operations for the periods  indicated are discussed
below.

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

Revenues

     Oil and Gas Sales.  Our  operating  revenues from the sale of crude oil and
natural gas increased by 4% from  $10,447,000  in 2002 to  $10,844,000  in 2003.
This  increase  was due to higher  sales prices but offset by normal oil and gas
production declines and lower production volumes. We were unable to offset those
declines and maintain or increase production through development efforts because
of limited development capital.

     Well  Servicing  Revenues.  There were no revenues from our well  servicing
operations in 2003 compared to $39,000 in 2002 since we ceased  performing  work
for other operators and concentrated on our own properties.

     Operating  Overhead  and  Other  Income.  Revenues  from  these  activities
decreased  53% from  $354,000 in 2002 to $166,000 in 2003,  primarily due to (1)
the loss of an oil and gas  marketing  contract and (2) lower  pipeline  volumes
resulting in less transportation revenue.

Costs and Expenses

     Lease  Operating  Expenses.  Lease  operating  expenses  increased  2% from
$5,430,000 in 2002 to $5,528,000 in 2003 due to increased vendor prices.

     Cost of Well Servicing Operations. There were no well servicing expenses in
2003 compared to $56,000 in 2002 since we did not work for other operators.

     Depreciation, Depletion and Amortization (DD and A). DD and A decreased 17%
from $2,698,000 in 2002 to $2,226,000 in 2003, due to lower production  volumes.
We also recorded income of $262,000 related to the cumulative effect of adopting
SFAS 143.

     Accretion Expense.  We recorded accretion expense of $77,000 as a result of
adopting SFAS 143 "Asset Retirement Obligation", effective January 1, 2003.

     General and  Administrative (G and A) Expenses.  G and A expenses increased
31% from  $1,728,000 in 2002 to  $2,262,000  in 2003 due to expenses  associated
with financing efforts that were not culminated.

     Interest Income and Expense.  Interest expense increased 6% from $3,159,000
in 2002 to $3,363,000 in 2003 due to penalty interest paid to our largest lender
under a provision in the loan agreement.

     Other  Financing  Costs.  In 2003,  we recorded an expense of $1,000,000 to
account for the issuance of 2,000 shares of our  preferred  stock to our largest
lender under a financial agreement.

     Unrealized Gain (Loss) on Derivative Instruments. The estimated future fair
value of derivative  instruments  at December 31, 2003 resulted in an unrealized
gain of $537,000 in 2003 compared to an unrealized loss of $1,597,000 in 2002.

     Dry Holes,  Abandoned  Property and Impaired Assets.  The cost of abandoned
property in 2003 was $538,000  because the lack of capital to complete  projects
resulted in the loss of leases.  This  compared to combined  costs of dry holes,
abandoned property and impaired assets of $617,000 in 2002.
                                       22

     Dividends on Preferred Stock. In 2003, dividends on preferred stock due was
$127,000,  however the board of directors did not declare any dividends be paid.
In 2002, dividends on preferred stock due was $112,000 and paid was $112,000.

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

Revenues

     Oil and Gas Sales.  Our  operating  revenues from the sale of crude oil and
natural gas decreased by 16% from  $12,426,000  in 2001 to  $10,447,000 in 2002.
This  decrease  resulted  from normal oil and gas  production  declines  and the
inability  to offset  those  declines  through  development  efforts  because of
limited development capital.

     Well  Servicing  Revenues.  Revenues  from  our well  servicing  operations
decreased by 77% from $169,000 in 2001 to $39,000 in 2002. This decrease was due
to  performing  less work for third  parties and the sale of one of our workover
rigs.

     Operating  Overhead  and  Other  Income.  Revenues  from  these  activities
decreased 10% from  $395,000 in 2001 to $354,000 in 2002,  primarily as a result
of the termination of a gas transportation sales contract with a local utility.

Costs and Expenses

     Lease  Operating  Expenses.  Lease  operating  expenses  increased  5% from
$5,155,000 in 2001 to $5,430,000 in 2002 due to increased vendor prices.

     Cost of Well Servicing  Operations.  Well servicing  expenses decreased 69%
from  $182,000  in 2001 to $56,000 in 2002 due to less work  under  contract  to
third parties and the sale of one workover rig.

     Depreciation,  Depletion and Amortization (DD and A). DD and A increased 8%
from  $2,491,000 in 2001 to $2,698,000 in 2002, due to our proved reserves being
calculated slightly lower at the end of 2001.

     General and  Administrative (G and A) Expenses.  G and A expenses increased
only slightly from $1,710,000 in 2001 to $1,728,000 in 2002.

     Interest Income and Expense. Interest expense increased 15% from $2,757,000
in 2001 to $3,159,000 in 2002 due to increased debt  associated with the funding
of acquisitions  in August,  2001,  capital used in our development  program and
issuance of warrants associated with working capital loans.

     Unrealized Gain (Loss) on Derivative Instruments. The estimated future fair
value of derivative  instruments  at December 31, 2002 resulted in an unrealized
loss of $1,597,000 in 2002 compared to an unrealized gain of $4,215,000 in 2001.
Also in 2001, an unrealized  loss of  $3,747,000,  resulting from the cumulative
effect of adopting SFAS No. 133 "Accounting for Derivative Instruments and Other
Hedging Activities," was recorded.

     Dry Holes, Abandoned Property,  Impaired Assets. The costs of a dry hole in
Louisiana of $339,000,  abandoned  property in Oklahoma of $222,000 and impaired
assets in  Mississippi of $55,000  totaled  $617,000 in 2002 compared to none in
2001.

     Dividends  on  preferred  stock due was  $112,000  and paid was $112,000 in
2002. Dividends on preferred stock due was $56,000 and paid was $28,000 in 2001.
                                       23

Year Ended December 31, 2001 Compared to Year Ended December 31, 2000

Revenues

     Oil and Gas Sales.  Our  operating  revenues from the sale of crude oil and
natural gas increased by 47% from $8,446,000 in 2000 to $12,426,000 in 2001, due
to increased oil and gas production from  development  projects and acquisitions
of additional properties.

     Well  Servicing  Revenues.  Revenues  from  our well  servicing  operations
decreased by 10% from  $188,000 in 2000 to $169,000 in 2001.  This  decrease was
due to higher rig  utilization  on  operated  properties  where we have  working
interest partners and less work for third parties.

     Operating  Overhead  and  Other  Income.  Revenues  from  these  activities
increased 13% from $350,000 in 2000 to $395,000 in 2001. Major components of the
increase included operating overhead $82,000,  gathering and marketing $211,000,
sale of exploratory leases $96,000 and miscellaneous income $6,000.

Costs and Expenses

     Lease  Operating  Expenses.  Lease  operating  expenses  increased 53% from
$3,378,000 in 2000 to $5,155,000  in 2001.  This increase in operating  expenses
was due to the  acquisitions  of  additional  properties,  expanded  oil and gas
production, and increased vendor prices.

     Cost of Well Servicing  Operations.  Well servicing  expenses decreased 14%
from $212,000 in 2000 to $182,000 in 2001.  This decrease in expenses was due to
less utilization of our equipment under contract to third parties.

     Depreciation, Depletion and Amortization (DD and A). DD and A increased 86%
from  $1,342,000  in 2000 to  $2,491,000 in 2001,  due to  significantly  higher
production   resulting  from  successful   field   development   activities  and
acquisitions.

     General and  Administrative (G and A) Expenses.  G and A expenses increased
8% from $1,588,000 in 2000 to $1,710,000 in 2001 due to the increased  number of
properties being managed.

     Interest  Expense  and  Dividends  on  Preferred  Stock.  Interest  expense
increased  29% from  $2,135,000  in 2000 to  $2,757,000 in 2001 due to increased
debt  associated  with the funding of our  additional  acquisitions  and capital
development program.

     Unrealized Gain (Loss) on Derivative Instruments. The estimated future fair
value of derivative  instruments  at December 31, 2001 resulted in an unrealized
gain of $4,215,000 in 2001.  Also in 2001,  an  unrealized  loss of  $3,747,000,
resulting from the cumulative  effect of adopting SFAS No. 133  "Accounting  for
Derivative Instruments and Other Hedging Activities," was recorded. There was no
unrealized gain or loss in 2000.

     Dividends on preferred  stock due was $56,000 and paid was $28,000 in 2001.
No dividends were due or paid in 2000.
                                       24

Financial Condition and Capital Resources.

     At December 31, 2003, our current  liabilities  exceeded our current assets
by  $42,876,963.  We had a loss available to common  shareholders  of $3,151,509
compared to a loss  available to common  shareholders  of $4,614,813 at December
31, 2002.  This loss included  non-cash items of $537,526 for unrealized gain on
derivative  instruments,  a loss of $358,737 for abandonment of properties and a
$262,452 gain from the recording of Asset Retirement Obligations  ("ARO's"),  as
required by SFAS 143, at January 1, 2003.

     In 2004, we will continue the  recapitalization  of debt and funding of our
capital  development  program that we began in 2003.  Following are the steps we
are taking and plan to take to achieve that purpose:

     (a) The first step is to close the refinancing of our largest debt of $27.8
million  held  by  Concert  Capital  Resources  LP  ("CCR")  and  loaned  to our
wholly-owned  subsidiary,  GulfWest Oil and Gas Company. We have entered into an
agreement  with a new lending source that,  subject to due diligence,  will fund
approximately  $14  million to purchase  the $27.8  million  note.  The new debt
financing will also provide for the payment of closing costs.  CCR has agreed to
sell the note to our new  financier  for a $14  million  cash  payment  and a $4
million subordinated note from us.

     (b) Secondly, we are continuing to work with our financial advisor to raise
an additional $4 to $5 million through the sale of our preferred stock. Proceeds
from  this  equity  sale  will be used  for  working  capital  and  fund our new
development projects. The refinancing of the CCR debt and sale of new equity are
both currently scheduled to close in April, 2004.

     (c) Effective December 1, 200l and amended August 16, 2002, we entered into
an Oil and Gas Property Acquisition,  Exploration and Development Agreement (the
"Summit  Agreement") with Summit  Investment  Group-Texas,  L.L.C., an unrelated
party,  ("Summit").  Under  the  agreement,  Summit  provided  payments  in  the
aggregate of $1,200,000 in advanced funds for our use in the  acquisition of oil
and  gas  leases  and  other  mineral  and  royalty  interests,  and  production
activities, and was to recoup and recover those advanced funds.

     In a subsequent event on March 5, 2004, we entered into an Option Agreement
for the  Purchase of Oil and Gas Leases  (the  "Addison  Agreement")  with W. L.
Addison  Investments  L.L.C.,  a private company owned by Mr. J. Virgil Waggoner
and Mr.  John E. Loehr,  two of our  directors,  (`Addison").  Under the Addison
Agreement,  Addison agreed to pay Summit,  on our behalf,  the  non-recouped and
outstanding advanced funds amounting to $1,200,000,  thereby retiring the Summit
Agreement.  For consideration of such payment,  Addison acquired certain oil and
gas leases and wellbores from Summit but agreed to grant us a 180-day redemption
option  (which may be  extended  by mutual  consent)  to  purchase  the same for
$1,200,000,  plus  interest  at the prime  rate plus 2%. We  tendered  Addison a
promissory note in the amount of $600,000,  with interest at the prime rate plus
2%, to  substitute  for an account  payable to  Summit,  pursuant  to the Summit
Agreement,  in the same amount.  The note will be considered  paid in full if we
exercise the redemption  option and pay the  $1,200,000,  plus interest.  Summit
retained the right to participate  up to a 25% working  interest in the drilling
of any wells on the leases  acquired  by Addison.  In the event we exercise  the
redemption option,  Addison may, at its sole option,  retain up to a 25% working
interest in the leases.

     (d) Finally,  after completing the above, we will pursue the  consolidation
of all of our debt,  including  other  asset and  bridge  loans.  Our goal is to
simplify our financial  structure and provide  adequate  capitalization  for the
development of our oil and gas assets.
                                       25

Inflation and Changes in Prices.

     While the general level of inflation  affects certain costs associated with
the petroleum  industry,  factors  unique to the industry  result in independent
price  fluctuations.  Such price  changes have had, and will  continue to have a
material   effect  on  our   operations;   however,   we  cannot  predict  these
fluctuations.

     The following  table indicates the average crude oil and natural gas prices
received over the last three years by quarter.  Average prices per barrel of oil
equivalent,   computed  by  converting  natural  gas  production  to  crude  oil
equivalents  at the rate of 6 Mcf per barrel,  indicate the composite  impact of
changes in crude oil and natural gas prices.

                                         Average Prices
                   ------------------------------------------------------------
                       Crude Oil                                   Per
                          And               Natural             Equivalent
                        Liquids               Gas                 Barrel
                   -----------------     ----------------      ----------------
                       (per Bbl)           (per Mcf)

2003
- ----
First                 $  24.53            $ 5.36              $  28.08
Second                   23.53              4.47                 25.04
Third                    23.85              4.32                 24.86
Fourth                   24.99              4.56                 25.02

2002
- ----
First                 $  19.40            $ 2.81                 18.31
Second                   20.75              3.16                 19.83
Third                    22.04              2.87                 19.67
Fourth                   22.38              3.56                 22.11

2001
- ----
First                 $  24.15            $ 5.27              $  27.87
Second                   24.14              3.88                 23.71
Third                    23.25              3.08                 21.08
Fourth                   19.94              2.62                 17.96

ITEM 7a. Qualitative and Quantitative Disclosures About Market Risk.

     Information with respect to qualitative  disclosures about material risk is
contained in Item 1 "Risk Factors".

     Information  with respect to quantitative  disclosures  about material risk
follow:

     All of our financial  instruments  are for purposes other than trading.  We
only enter derivative financial  instruments in conjunction with our oil and gas
hedging activities.

     Hypothetical  changes in interest rates and prices chosen for the following
stimulated   sensitivity  effects  are  considered  to  be  reasonably  possible
near-term changes generally based on consideration of past fluctuations for each
risk  category.  It is not  possible to  accurately  predict  future  changes in
interest rates and product prices.  Accordingly,  these hypothetical changes may
not be an indicator of probable future fluctuations.
                                       26

Interest Rate Risk

     We are exposed to interest rate risk on debt with variable  interest rates.
At December 31, 2003, we carried  variable rate debt of $37,955,334.  Assuming a
one percentage  point change at December 31, 2003 on our variable rate debt, the
annual pretax income (loss) would change by $379,553.

Commodity Price Risk

     We hedge a portion of its price risks  associated  with its oil and natural
gas sales which are  classified  as derivative  instruments.  As of December 31,
2003,  these derivative  instruments'  liabilities had a fair value of $591,467.
Fair value was  estimated  based upon the net present  value of expected  future
cash flows,  comparing  prices for oil and gas in the hedge contract with quoted
oil and gas futures  prices.  A hypothetical  change in oil and gas prices could
have an effect on oil and gas futures  prices,  which are used to  estimate  the
fair value of our  derivative  instrument.  However,  it is not  practicable  to
estimate  the  resultant  change,  in any,  in the fair value of our  derivative
instrument.

ITEM 8. Financial Statements and Supplementary Data.

     Information  with  respect  to this Item 8 is  contained  in our  financial
statements beginning on Page F-1 of this Annual Report.


ITEM 9.  Changes  In and  Disagreements  With  Accountants  and  Accounting  and
Financial Disclosure.

     None

ITEM 9A. Controls and Procedures

     Within  ninety  days  of  the  date  of  this  Report,  we  carried  out an
evaluation,  under the  supervision  and with the  participation  of management,
including  the Chief  Executive  Officer  and Chief  Financial  Officer,  of our
disclosure  controls and procedures (as defined in Rules 13a-14 and 15d-14 under
the  Securities  Exchange Act of 1934).  Based upon that  evaluation,  the Chief
Executive  Officer and Chief  Financial  Officer  concluded  that our disclosure
controls  and  procedures  are  effective  in timely  alerting  them to material
information  required to be included in periodic filings with the Securities and
Exchange Commission.  There were no significant changes in our internal controls
or in other  factors that could  significantly  affect these  internal  controls
subsequent to the date of our most recent evaluation.
                                       27

                                    PART III


ITEM 10. Directors and Executive Officers of the Registrant.

     The following  table sets forth  information on our directors and executive
officers:

                                                             Year First Elected
Name                     Age  Position                      Director or Officer
- ----                     ---  --------                      -------------------

J. Virgil Waggoner(1)(2) 76  Chairman of the Board                 1997

Thomas R. Kaetzer        45  Chief Executive Officer               1998
                               President and Director

Jim C. Bigham            68  Executive Vice President              1991
                               and Secretary

Richard L. Creel         55  Vice President of Finance             1998
                               and Controller
Marshall A. Smith III    56  Director                              1989

John E. Loehr(1)(2)      58  Director                              1992

M. Scott Manolis(1)(2)   50  Director                              2003

     (1)  Member  of  the  Audit  Committee.
     (2)  Member  of  the  Compensation Committee.

     J. Virgil  Waggoner has served as a director of GulfWest  since December 1,
1997 and was elected Chairman of the Board in May, 2002. Mr.  Waggoner's  career
in the  petrochemical  industry  began in 1950 and  included  senior  management
positions with Monsanto Company and El Paso Products Company,  the petrochemical
and plastics unit of El Paso Company. He served as president and chief executive
officer of Sterling Chemicals,  Inc. from the firm's inception in 1986 until its
sale and his retirement in 1996. He is currently chief executive  officer of JVW
Investments, Ltd., a private company.

     Thomas R. Kaetzer was appointed  senior vice president and chief  operating
officer of  GulfWest  on  September  15,  1998 and on  December  21, 1998 became
president and a director.  On March 20, 2001, he was appointed  chief  executive
officer.  Mr.  Kaetzer  has 17  years  experience  in the oil and gas  industry,
including 14 years with Texaco Inc., which involved the evaluation, exploitation
and  management  of oil  and  gas  assets.  He has  both  onshore  and  offshore
experience  in  operations  and  production   management,   asset   acquisition,
development,  drilling and workovers in the  continental  U.S.,  Gulf of Mexico,
North Sea,  Colombia,  Saudi Arabia,  China and West Africa.  Mr.  Kaetzer has a
Masters Degree in Petroleum Engineering from Tulane University and a Bachelor of
Science Degree in Civil Engineering from the University of Illinois.

     Jim C.  Bigham has served as  secretary  since 1991 and as  executive  vice
president of GulfWest since 1996. Prior to joining GulfWest,  he held management
and sales  positions in the real estate and printing  industries.  Mr. Bigham is
also a retired  United States Air Force Major.  During his military  career,  he
served  in  both  command  and  staff  officer  positions  in  the  operational,
intelligence and planning areas.
                                       28

     Richard L. Creel has served as controller of GulfWest since May 1, 1997 and
was  elected  vice  president  of  finance  on May 28,  1998.  Prior to  joining
GulfWest, Mr. Creel served as Branch Manager of the Nashville,  Tennessee office
of Management Reports and Services, Inc. He has also served as controller of TLO
Energy  Corp.  He has  extensive  experience  in general  accounting,  petroleum
accounting, and financial consulting and income tax preparation.

     Marshall A. Smith III founded  GulfWest and served as an officer in various
capacities,  including  president,  chief executive  officer and chairman of the
board,  from July 1989 until his resignation in May 2002. He is currently a paid
consultant and remains a director.

     John E. Loehr has served as a director of GulfWest since 1992, was chairman
of the board  from  September  1,  1993 to July 8, 1998 and was chief  financial
officer from November 22, 1996 to May 28, 1998. He is also  currently  president
and sole  shareholder of ST Advisory  Corporation,  an investment  company,  and
vice-president of Star-Tex Trading Company,  also an investment  company. He was
formerly president of Star-Tex Asset Management,  a  commodity-trading  advisor,
and a position he held from 1988 until 1992 when he sold his ownership interest.
Mr.  Loehr is a CPA and a member of the American  Institute of Certified  Public
Accountants.

     M. Scott  Manolis is newly  nominated to the board.  He is the chairman and
chief  executive  officer  of  Intermarket   Management,   LLC  and  Intermarket
Brokerage,   LLC.  He  has  over  twenty  years  experience  in  commodity  risk
management, commodity finance and commodity-based investments. Prior to founding
Intermarket,  Mr. Manolis  concurrently served as managing director of Commodity
Strategies  for Refco Group,  LTD. and Managing  Director of Global  Derivatives
Strategies for  Forstmann-Leff  International  (an asset  management firm wholly
owned by Refco Group, LTD), where he directed commodity-based investments. Prior
to that, he served as a vice  president and director of the Commodity  Portfolio
Management Group at Jefferies and Company. He received a B. S. in Economics from
the University of South Dakota in 1979.

     Our  directors  are elected  annually and hold office until the next annual
meeting  of  shareholders  and  until  their  successors  are duly  elected  and
qualified.  The board of directors  met 4 times  during the calendar  year ended
December 31, 2003.

Committees of the Board of Directors.

     Our  board  of  directors  has   established  an  audit   committee  and  a
compensation  committee.  The  functions  of  these  committees,  their  current
members, and the number of meetings held during 2003 are described below.

     The audit  committee  was  established  to review  and  appraise  the audit
efforts of our independent  auditors,  and monitor our accounts,  procedures and
internal  controls.  The committee is comprised of Mr. John E. Loehr (Chairman),
Mr. J. Virgil  Waggoner and Mr. M. Scott  Manolis.  The  committee  met twice in
2003.

     The function of the  compensation  committee is to fix the annual  salaries
and other  compensation  for our officers and key  employees.  The  committee is
comprised  of Mr. J. Virgil  Waggoner  (Chairman),  Mr. John E. Loehr and Mr. M.
Scott Manolis. The committee met twice in 2003.
                                       29



Compensation of Directors.

     The  shareholders  approved an amended and restated  Employee  Stock Option
Plan on May 28, 1998,  which  included a provision for the payment of reasonable
fees in cash or stock to  directors.  No fees were paid to  directors in 2003 or
2002.

ITEM 11. Executive Compensation.

     Information  regarding  executive  compensation is  incorporated  herein by
reference to our Proxy Statement.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management.

     Information  regarding  security ownership of certain beneficial owners and
management is incorporated herein by reference to our Proxy Statement.

ITEM 13. Certain Relationships and Related Transactions.

     Information  regarding certain  relationships  and related  transactions is
incorporated herein by reference to our Proxy Statement.

ITEM 14. Principal Accounting Fees and Services.

     Information   regarding   principal   accounting   fees  and   services  is
incorporated herein by reference to our Proxy Statement.
                                       30


GLOSSARY OF INDUSTRY TERMS AND ABBREVIATIONS

The following are definitions of certain industry terms and  abbreviations  used
in this report:

Bbl. Barrel.

BOE. Barrel of oil  equivalent,  based on a ratio of 6,000 cubic feet of natural
gas for each barrel of oil.

Gross Acres or Gross  Wells.  The total  acres or wells,  as the case may be, in
which a working interests is owned.

Horizontal Drilling. High angle directional drilling with lateral penetration of
one or more productive reservoirs.

Mcf. One thousand cubic feet.

Net Acres or Net Wells.  The sum of the fractional  working  interests  owned in
gross acres or gross wells.

Overriding  Royalty  Interest.  The right to receive a share of the  proceeds of
production from a well, free of all costs and expenses, except transportation.

Present Value. The pre-tax present value,  discounted at 10%, of future net cash
flows  from  estimated  proved  reserves,  calculated  holding  prices and costs
constant at amounts in effect on the date of the report  (unless  such prices or
costs are subject to change pursuant to contractual provisions) and otherwise in
accordance  with the  Commission's  rules for  inclusion  of oil and gas reserve
information in financial statements filed with the Commission.

Proceeds of Production.  Money received  (usually  monthly) from the sale of oil
and gas produced from producing properties.

Producing Properties. Properties that contain one or more wells that produce oil
and/or gas in paying quantities (i.e., a well for which proceeds from production
exceed operating expenses).

Productive  Well.  A well that is  producing  oil or gas or that is  capable  of
production.

Prospect.  A lease or group of leases containing  possible reserves,  capable of
producing  crude  oil,  natural  gas,  or  natural  gas  liquids  in  commercial
quantities,  either at the time of acquisition,  or after vertical or horizontal
drilling, completion of workovers, recompletions, or operational modifications.

Proved Reserves. Estimated quantities of crude oil, natural gas, and natural gas
liquids  that  geological  and  engineering  data  demonstrate  with  reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic conditions; i.e., prices and costs as of the date the estimate is made.
Reservoirs  are  considered  proved if either actual  production or a conclusive
formation test supports economic production.

     The area of a reservoir considered proved includes:

     a.   That  portion  delineated  by  drilling  and  defining  by  gas-oil or
          oil-water contacts, if any; and
                                       31

     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.

     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.

     Proved Reserves do not include:

     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 and other sources.

Proved Developed Reserves. 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 should be included as proved developed only after testing by
a pilot project or after operation of an installed program has confirmed through
production response that increased recovery will be achieved.

Proved Undeveloped Reserves. 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 shall be
limited to those drilling units offsetting  productive units that are reasonably
certain of production  when drilled.  Proved  reserves for other units that have
not been drilled can be claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing  productive  formation.
Under no  circumstances  should  estimates  for proved  undeveloped  reserves be
attributable to any acreage for which an application of fluid injection or other
improved  recovery  technique is contemplated,  unless such techniques have been
proven effective by actual tests in the area and in the same reservoir.

Recompletion.  The completion for production of an existing  wellbore in another
formation from that in which the well has previously been completed.

Reservoir.  A porous and permeable  underground  formation  containing a natural
accumulation  of producible oil or gas that is confined by  impermeable  rock or
water barriers and is individual and separate from other reservoirs.

Royalty.  The right to a share of production  from a well, free of all costs and
expenses, except transportation.
                                       32

Royalty Interest.  An interest in an oil and gas property entitling the owner to
a share of oil and natural gas production free of costs of production.

Standardized  Measure. The present value,  discounted at 10%, of future net cash
flows from estimated proved  reserves,  after income taxes,  calculated  holding
prices and costs constant at amounts in effect on the date of the report (unless
such prices or costs are subject to change  pursuant to contractual  provisions)
and otherwise in accordance with the Commission's rules for inclusion of oil and
gas reserve information in financial statements filed with the Commission.

Waterflood.  An engineered,  planned effort to inject water into an existing oil
reservoir  with the intent of  increasing  oil reserve  recovery and  production
rates.

Working Interest.  The operating  interest under a lease, the owner of which has
the right to explore for and produce oil and gas covered by such lease. The full
working  interest  bears 100 percent of the costs of  exploration,  development,
production,  and operation, and is entitled to the portion of gross revenue from
the proceeds of production which remains after proceeds allocable to royalty and
overriding royalty interests or other lease burdens have been deducted.

Workover.  Rig work  performed  to restore an  existing  well to  production  or
improve its production from the current existing reservoir.
                                       33

                                    PART III

ITEM 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.

     (a)  The following documents are filed as part of this Report:

          (1)  Financial Statements: Consolidated Balance Sheets at December 31,
               2003 and 2002.  Consolidated  Statements  of  Operations  for the
               years  ended  December  31,  2003,  2002 and  2001.  Consolidated
               Statements of  Stockholders'  Equity for the years ended December
               31, 2003,  2002 and 2001.  Consolidated  Statements of Cash Flows
               for the years ended  December 31, 2003,  2002 and 2001.  Notes to
               Consolidated  Financial  Statements,  December 31, 2003, 2002 and
               2001.

          (2)  Financial  Statement  Schedule:   Schedule  II  -  Valuation  and
               Qualifying Accounts

          (3)  Exhibits:

               Number   Description
               ------   -----------

               *3.1     Articles of  Incorporation  of the Registrant and
                        Amendments thereto.

               *3.2     Bylaws of the Registrant.

               %10.1    GulfWest Oil Company 1994 Stock Option and Compensation
                        Plan, amended and restated as of April 1, 2001 and
                        approved by the shareholders on May 18, 2001.

              ----------
               *        Previously  filed  with our  Registration  Statement
                        (on Form  S-1,  Reg.  No.  33-53526),  filed  with the
                        Commission on October 21, 1992.
               %        Previously filed with our Proxy Statement on Form DEF
                        14A, filed with the Commission on April 16, 2001.

               22.1     Subsidiaries of the Registrant (included on page 3 of
                        this Annual Report.

               25       Power of Attorney (included on signature page of this
                        Annual Report).
               31.1     Certification of Chief Executive  Officer pursuant to
                        Exchange Rule 13a-14(a) as adopted pursuant to Section
                        302 of the Sarbanes-Oxley Act of 2002; filed herewith.

               31.2     Certification of Chief Financial  Officer pursuant to
                        Exchange Rule 13a-14(a) as adopted pursuant to Section
                        302 of the Sarbanes-Oxley Act of 2002; filed herewith.

               32       Certification pursuant to 18.U.S.C Section 1350 pursuant
                        to Section 906 of the  Sarbanes-Oxley Act of 2002;
                        filed herewith.

     (b)  Reports on Form 8-K.

          None.
                                       34

                               S I G N A T U R E S

     Pursuant  to the  requirements  of  Section  13 or 15(d) of the  Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

                                                   GULFWEST ENERGY INC.

Date: March 29, 2004                               By \s\ Thomas R. Kaetzer
                                                   ----------------------------
                                                   Thomas  R.   Kaetzer,
                                                   President

                                POWER OF ATTORNEY

     Know all men by these presents,  that each person whose  signature  appears
below  constitutes  and  appoints  Thomas  R.  Kaetzer  as his true  and  lawful
attorney-in-fact and agent, with full power of substitution,  for him and in his
name, place, and stead, in any and all capacities to sign any and all amendments
or  supplements  to this Annual Report on Form 10-K,  and to file the same,  and
with all exhibits thereto and other documents in connection therewith,  with the
Securities  and Exchange  Commission,  granting unto said  attorney-in-fact  and
agent full power and  authority  to do and perform  each and every act and thing
requisite  and  necessary  to be done as fully to all intents and purposes as he
might or could do in  person,  hereby  ratifying  and  confirming  all that said
attorney-in-fact and agent or his substitute or substitutes,  may lawfully do or
cause to be done by virtue hereof.

     Pursuant to the  requirements of the Securities  Exchange Act of 1934, this
report  has been  signed  below  by the  following  persons,  on  behalf  of the
registrant, and in the capacities and on the dates indicated.

   Signature                         Title                          Date
- ----------------------               ----------------------     ---------------

\s\ J. Virgil Waggoner               Chairman of the Board       March 29, 2004
- ----------------------
J. Virgil Waggoner

\s\ Thomas R. Kaetzer                President, Chief Executive  March 29, 2004
- -------------------------            Officer and Director
Thomas R. Kaetzer

\s\ Jim C. Bigham Executive          Vice President March 29, 2004
- ---------------------------            and Secretary
Jim C. Bigham

\s\ Richard L. Creel                 Vice President of Finance,  March 29, 2004
- ----------------------------         Controller
Richard L. Creel

\s\ Marshall A. Smith III            Director                    March 29, 2004
- -------------------------
Marshall A. Smith III

\s\ John E. Loehr                    Director                    March 29, 2004
- -----------------
John E. Loehr

\s\ M. Scott Manolis                 Director                    March 29, 2004
- --------------------
M. Scott Manolis
                                       35









                              GULFWEST ENERGY INC.

                                FINANCIAL REPORT

                                DECEMBER 31, 2003







                                 C O N T E N T S



                                                                         Page



INDEPENDENT AUDITOR'S REPORT
    ON THE FINANCIAL STATEMENTS                                          F-1


FINANCIAL STATEMENTS

    Consolidated balance sheets                                          F-2

    Consolidated statements of operations                                F-4

    Consolidated statements of stockholders' equity                      F-5

    Consolidated statements of cash flows                                F-7

    Notes to consolidated financial statements                           F-8


INDEPENDENT AUDITOR'S REPORT ON
    THE FINANCIAL STATEMENT SCHEDULE                                     F-30


FINANCIAL STATEMENT SCHEDULE

    Schedule II - Valuation and Qualifying Accounts                      F-31

    All other Financial Statement Schedules have
      been omitted because they are either
      inapplicable or the information required is
      included in the financial statements or
      the notes thereto.



                          INDEPENDENT AUDITOR'S REPORT



To the Stockholders and
     Board of Directors
GULFWEST ENERGY INC.



We have audited the accompanying  consolidated balance sheets of GulfWest Energy
Inc. (a Texas  Corporation)  and  Subsidiaries as of December 31, 2003 and 2002,
and the related consolidated statements of operations,  stockholders' equity and
cash flows for each of the three years in the period  ended  December  31, 2003.
These consolidated  financial statements are the responsibility of the Company's
management.  Our  responsibility is to express an opinion on these  consolidated
financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the  United  States of  America.  Those  standards  require  that we plan and
perform the audit to obtain reasonable  assurance about whether the consolidated
financial  statements  are free of  material  misstatement.  An  audit  includes
examining,  on a test basis,  evidence supporting the amounts and disclosures in
the  consolidated  financial  statements.  An audit also includes  assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation.  We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the consolidated  financial statements referred to above present
fairly,  in all  material  respects,  the  consolidated  financial  position  of
GulfWest Energy Inc. and  Subsidiaries as of December 31, 2003 and 2002, and the
consolidated  results of their  operations  and their cash flows for each of the
three years in the period ended December 31, 2003, 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 shown in the consolidated
financial  statements,  the Company incurred a net loss of $3,151,509 during the
year ended  December  31,  2003,  and,  as of that date,  had a working  capital
deficiency of $42,876,963.  Those conditions raise  substantial  doubt about the
Company's ability to continue as a going concern.  Management's  plans regarding
those  matters  described in Note 2,  "Operations  and  Management  Plans".  The
consolidated  financial  statements  do not include any  adjustments  that might
result from the outcome of this uncertainty.

As explained in Note 1 to the Financial  Statements,  effective January 1, 2003,
the Company changed its accounting method for Asset Retirement Obligations.


\s\WEAVER AND TIDWELL, L.L.P
- ------------------------------
WEAVER AND TIDWELL, L.L.P.
Dallas, Texas
March 19, 2004

                                      F-1

                      GULFWEST ENERGY INC. AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                           DECEMBER 31, 2003 AND 2002


                                     ASSETS


                                                                                   ----------------      -----------------
                                                                                        2003                   2002
                                                                                   ----------------      -----------------
CURRENT ASSETS
     Cash and cash equivalents                                                     $     483,618         $     687,694
     Accounts receivable - trade, net of allowance
          for doubtful accounts of $-0- in 2003 and 2002                               1,099,802             1,361,446
     Prepaid expenses                                                                    159,269               303,906
                                                                                   ----------------      -----------------
               Total current assets                                                    1,742,689             2,353,046
                                                                                   ----------------      -----------------


OIL AND GAS PROPERTIES,
     using the successful efforts method of accounting                                58,472,886            56,786,043


OTHER PROPERTY AND EQUIPMENT                                                           2,132,220             2,121,410
     Less accumulated depreciation, depletion and amortization                       (10,017,931)           (8,498,497)
                                                                                   ----------------      -----------------

     Net oil and gas properties and other property and equipment                      50,587,175            50,408,956
                                                                                   ----------------      -----------------


OTHER ASSETS
     Deposits                                                                             20,142                37,442
     Debt issue cost, net                                                                 78,768               289,497
                                                                                   ----------------      -----------------
               Total other assets                                                         98,910               326,939
                                                                                   ----------------      -----------------

TOTAL ASSETS                                                                       $  52,428,774         $  53,088,941
                                                                                   ================      =================















The Notes to Consolidated Financial Statements are an integral part of  these statements.
                                      F-2












                                          LIABILITIES AND STOCKHOLDERS' EQUITY


                                                                                   ----------------      -----------------
                                                                                        2003                   2002
                                                                                   ----------------      -----------------
CURRENT LIABILITES
     Notes payable                                                                 $  8,182,165          $  4,936,088
     Notes payable - related parties                                                  1,465,000             1,290,000
     Current portion of long-term debt                                               29,396,092            33,128,447
     Current portion of long-term debt - related parties                                130,152               256,967
     Accounts payable - trade                                                         5,002,675             3,928,477
     Accrued expenses                                                                   443,568               458,587
                                                                                   ----------------      -----------------
               Total current liabilities                                             44,619,652            43,998,566
                                                                                   ----------------      -----------------

NONCURRENT LIABILITIES
     Long-term debt, net of current portion                                              35,801               126,552
     Long-term debt - related parties                                                     -                    11,256
     Asset retirement obligations                                                     1,357,206                  -
                                                                                   ----------------      -----------------
               Total noncurrent liabilities                                           1,393,007               137,808
                                                                                   ----------------      -----------------

OTHER LIABILITES
     Derivative instruments                                                               591,467            1,128,993
                                                                                   ----------------      -----------------

               Total Liabilities                                                       46,604,126           45,265,367
                                                                                   ----------------      -----------------

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS' EQUITY
     Preferred stock                                                                          190                  170
     Common stock                                                                          18,493               18,493
     Additional paid-in capital                                                        29,283,692           28,258,212
     Retained deficit                                                                 (23,477,727)         (20,453,301)
                                                                                   ----------------      -----------------
               Total stockholders' equity                                               5,824,648            7,823,574
                                                                                   ----------------      -----------------


TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                                         $   52,428,774        $  53,088,941
                                                                                   ================      =================









The Notes to Consolidated Financial Statements are an integral part of  these statements.
                                      F-3

                     GULFWEST ENERGY INC. AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF OPERATIONS
              FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001


                                                                    2003                   2002                 2001
                                                               ----------------      -----------------    -----------------
                                                               ----------------      -----------------    -----------------

OPERATING REVENUES
     Oil and gas sales                                         $   10,844,460        $   10,447,169       $    12,426,103
     Well servicing revenues                                                                 39,116               169,167
     Operating overhead and other income                              166,263               353,512               395,311
                                                               ----------------      -----------------    -----------------
          Total Operating Revenues                                 11,010,723            10,839,797            12,990,581
                                                               ----------------      -----------------    -----------------
OPERATING EXPENSES
     Lease operating expenses                                       5,527,841             5,430,205             5,155,500
     Cost of well servicing operations                                                       56,295               182,180
     Depreciation, depletion and amortization                       2,226,123             2,697,784             2,491,385
     Accretion expense                                                 76,823
     General administrative                                         2,262,425             1,727,858             1,709,641
                                                               ----------------      -----------------    -----------------
          Total Operating Expenses                                 10,093,212             9,912,142             9,538,706
                                                               ----------------      -----------------    -----------------
INCOME FROM OPERATIONS                                                917,511               927,655             3,451,875
                                                               ----------------      -----------------    -----------------
OTHER INCOME AND EXPENSE
     Interest expense                                              (3,363,330)           (3,159,381)           (2,756,912)
     Other financing costs                                         (1,000,000)
     Gain (loss) on sale of assets                                    (19,848)              (56,647)             (118,254)
     Unrealized gain (loss) on derivative instruments                 537,526            (1,596,575)            4,215,017
     Dry holes, abandoned property and impaired assets               (358,737)             (617,365)
                                                               ----------------      -----------------    -----------------
          Total Other Income and (Expense)                         (4,204,389)            5,429,968             1,339,851
                                                               ----------------      -----------------    -----------------
INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE
  EFFECT OF CHANGE IN
  ACCOUNTING PRINCIPLES                                            (3,286,878)           (4,502,313)            4,791,726

INCOME TAXES
                                                               ----------------      -----------------    -----------------
INCOME (LOSS) BEFORE CUMULATIVE
     EFFECT OF CHANGE IN ACCOUNTING
     PRINCIPLES                                                    (3,286,878)           (4,502,313)            4,791,726

CUMULATIVE EFFECT OF CHANGE IN
     ACCOUNTING PRINCIPLES, NET OF INCOME TAXES                       262,452                                  (3,747,435)
                                                               ----------------      -----------------    -----------------
NET INCOME (LOSS)                                              $   (3,024,426)       $   (4,502,313)      $     1,044,291
DIVIDENDS ON PREFERRED STOCK
     (PAID 2003-$-0-; 2002-$112,500; 2001-
     $28,125)                                                        (127,083)             (112,500)              (56,250)
                                                               ----------------      -----------------    -----------------
NET INCOME (LOSS) AVAILABLE TO COMMON
     SHAREHOLDERS                                              $   (3,151,509)       $   (4,614,813)      $       988,041
                                                               ================      =================    =================
NET INCOME (LOSS) PER SHARE, BASIC
     BEFORE CUMULATIVE EFFECT OF CHANGE
      IN ACCOUNTING PRINCIPLES                                 $        (.18)        $        (.25)       $           .25

CUMULATIVE EFFECT OF CHANGE IN
     ACCOUNTING PRINCIPLES                                               .01                                         (.20)
                                                               ----------------      -----------------    -----------------
NET INCOME (LOSS) PER SHARE BASIC                              $        (.17)        $        (.25)       $           .05
                                                               ================      =================    =================
NET INCOME (LOSS) PER SHARE, DILUTED BEFORE CUMULATIVE
EFFECT OF CHANGE IN
     ACCOUNTING PRINCIPLES                                     $        (.18)        $        (.25)       $           .23
CUMULATIVE EFFECT OF CHANGE IN
     ACCOUNTING PRINCIPLES                                               .01                                         (.18)
                                                               ----------------      -----------------    -----------------
NET INCOME (LOSS) PER SHARE, DILUTED                           $        (.17)        $        (.25)       $           .05
                                                               ================      =================    =================

                                      F-4





                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
              FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001






                                                                              -------------------------------
                                                                                     Number of Shares
                                                                              -------------------------------
                                                                              -------------- -- -------------
                                                                                Preferred          Common
                                                                                  Stock            Stock
                                                                              --------------    -------------
BALANCE, December 31, 2000                                                                        18,445,041
                                                                                      8,000
  Issuance of 9,000 shares of Series E preferred stock for the
    acquisition of assets                                                             9,000
  Issuance of 47,500 shares of common stock for the acquisition of
    assets                                                                                            47,500
  Issuance of warrants for the acquisition of assets
  Net income
  Dividends paid on preferred stock
                                                                              --------------    -------------


BALANCE, December 31, 2001                                                           17,000       18,492,541
                                                                              ==============    =============
  Issuance of warrants for additional financing
  Net loss
  Dividends paid on preferred stock
                                                                              --------------    -------------

BALANCE, December 31, 2002                                                           17,000       18,492,541
                                                                              ==============    =============
  Issuance of warrants for additional financing
  Issuance of preferred stock related to current financing                            2,000
  Net loss
                                                                              --------------    -------------

BALANCE, December 31, 2003                                                           19,000       18,492,541
                                                                              ==============    =============














The Notes to Consolidated Financials are an integral part of these statements.
                                      F-5















        Preferred                           Common                Additional                     Retained
          Stock                             Stock               Paid-In Capital                  Deficit
- -------------------------- ------------------------     ------------------------    ---------------------------
$           80             $               18,445       $           23,537,900      $          (16,854,654)

            90                                                       4,499,910

                                               48                       35,402
                                                                        91,500
                                                                                                  1,044,291
                                                                                                    (28,125)
- -------------------------- ------------------------     ------------------------    ---------------------------

$          170             $               18,493       $           28,164,712      $           (15,838,488)
========================== ========================     ========================    ===========================
                                                                        93,500
                                                                                                 (4,502,313)
                                                                                                   (112,500)
- -------------------------- ------------------------     ------------------------    ---------------------------

$          170             $               18,493       $           28,258,212      $           (20,453,301)

========================== ========================     ========================    ===========================
                                                                        25,500
            20                                                         999,980
                                                                                                 (3,024,426)

- -------------------------- ------------------------     ------------------------    ---------------------------
$          190             $               18,493       $           29,283,692      $           (23,477,727)

========================== ========================     ========================    ===========================
















The Notes to Consolidated Financials are an integral part of these statements.
                                      F-6


                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
              FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001


                                                                             2003               2002                2001
                                                                        ---------------    ----------------    ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
     Net income (loss)                                                  $  (3,024,426)     $   (4,502,313)     $    1,044,291
     Adjustments to reconcile net income (loss) to net cash
          Provided by operating activities:
               Depreciation, depletion and amortization                     2,226,123           2,697,784           2,491,385
               Accretion expense                                               76,823
               Common stock and warrants issued and charged to
                 operations                                                    25,500              93,500
               Other financing costs                                        1,000,000
               Loss on sale of assets                                          19,848              56,647             118,254
               Dry holes, abandoned property, impaired assets                 358,737             617,365
               Unrealized (gain) loss on derivative instruments              (537,526)          1,596,575           (4,215,017)
               Cumulative effect of accounting change                        (262,452)                               3,747,435
               Provision for bad debts                                         29,201
               (Increase)   decrease  in  accounts   receivable  -
                 trade, net                                                   232,443            (109,437)             765,939
               (Increase) decrease in prepaid expenses                        144,637            (179,825)             (40,730)
               Increase   (decrease)   in  accounts   payable  and
                 accrued expenses                                           1,235,503           1,043,994              797,800
                                                                        ---------------    ----------------    ---------------
                    Net cash provided by operating activities               1,524,411           1,314,290            4,709,357
                                                                        ---------------    ----------------    ---------------

CASH FLOWS FROM INVESTING ACTIVITIES:
     Deposits                                                                                                          (9,804)
     Proceeds from sale of property and equipment                              38,561             675,440             394,423
     Purchase of property and equipment                                    (1,067,924)         (5,861,969)         (6,962,650)
                                                                        ---------------    ----------------    ---------------
                    Net cash used in investing activities                  (1,029,363)         (5,186,529)         (6,578,031)
                                                                        ---------------    ----------------    ---------------

CASH FLOWS FROM FINANCING ACTIVITIES:
     Payments on debt                                                      (1,672,288)         (3,410,778)         (6,577,928)
     Proceeds from debt issuance                                              973,164           7,394,181           8,530,269
     Debt issue cost                                                                                                  (29,544)
     Dividends paid                                                                              (112,500)            (28,125)
                                                                        ---------------    ----------------    ---------------
                    Net cash provided by (used in) financing
                      activities                                            (699,124)           3,870,903           1,894,672
                                                                        ---------------    ----------------    ---------------

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                            (204,076)              (1,336)             25,998

CASH AND CASH EQUIVALENTS,
     Beginning of year                                                       687,694              689,030             663,032
                                                                        ---------------    ----------------    ---------------

CASH AND CASH EQUIVALENTS,
     End of year                                                        $    483,618       $      687,694             689,030
                                                                        ===============    ================    ===============

CASH PAID FOR INTEREST                                                  $  3,216,034       $    3,004,015      $    2,811,677

                                                                        ===============    ================    ===============













The Notes to Consolidated Financial Statements are an integral part of these statements.
                                      F-7


                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 1. Summary of Significant Accounting Policies

          The  following  is a summary of the  significant  accounting  policies
          consistently   applied  by  management  in  the   preparation  of  the
          accompanying consolidated financial statements.

          Organization/Concentration of Credit Risk

                    GulfWest Energy Inc. and our  subsidiaries  intend to pursue
               the  acquisition  of quality  oil and gas  prospects,  which have
               proved developed and undeveloped  reserves and the development of
               prospects with third party industry partners.

                    The accompanying  consolidated  financial statements include
               our  company  and its  wholly-owned  subsidiaries:  RigWest  Well
               Service, Inc.  ("RigWest"),  GulfWest Texas Company ("GWT"), both
               formed in 1996;  DutchWest Oil Company formed in 1997;  SETEX Oil
               and Gas Company ("SETEX") formed August 11, 1998; Southeast Texas
               Oil and Gas Company,  L.L.C.  ("Setex LLC") acquired September 1,
               1998;  GulfWest Oil and Gas Company formed February 18, 1999; LTW
               Pipeline Co. formed April 19, 1999; GulfWest  Development Company
               ("GWD") formed  November 9, 2000 and GulfWest Oil and Gas Company
               (Louisiana) LLC, formed July 31, 2001. All material  intercompany
               transactions and balances are eliminated upon consolidation.

                    We  grant  credit  to  independent  and  major  oil  and gas
               companies for the sale of crude oil and natural gas. In addition,
               we grant credit to joint owners of oil and gas properties,  which
               we,  through our  subsidiary,  SETEX,  operate.  Such amounts are
               secured by the underlying  ownership interests in the properties.
               We also grant credit to various third parties through RigWest for
               well servicing operations.

                    We  maintain  cash  on  deposit  in   non-interest   bearing
               accounts,  which, at times,  exceed federally  insured limits. We
               have not  experienced  any losses on such accounts and believe we
               are not  exposed  to any  significant  credit  risk  on cash  and
               equivalents.

          Statement of Cash Flows

                    We  consider  all  highly  liquid   investment   instruments
               purchased with remaining maturities of three months or less to be
               cash equivalents for purposes of the  consolidated  statements of
               cash flows.

               Non-Cash Investing and Financing Activities:

                    During the twelve month period ended  December 31, 2003,  we
               adopted Statement of Financial Accounting Standard No. 143 "Asset
               Retirement  Obligations" (SFAS 143). As a result of adopting SFAS
               143,  effective  January 1, 2003, we recorded an asset retirement
               obligation  liability of $1,280,383,  an increase in the carrying
               value of our oil and gas properties of $1,058,445, a reduction in
               accumulated  depletion  of $484,390  and an  adjustment  to prior
               income of $262,452.  This liability was increased  during 2003 by
               recognizing $76,823 in accretion expense.  Also, we decreased the
               current  portion of long term  debt-related  parties by  applying
               $17,300  in  deposits  and  reclassified  $176,320  from  accrued
               expenses to current portion of long term debt.

                    During the twelve month period ended  December 31, 2002,  we
               acquired $74,653 in property and equipment  through notes payable
               to  financial  institutions.  We also  acquired  $182,742  of oil
               producing  properties in exchange of accounts  receivable  from a
               related party. In addition, we sold property and equipment, which
               included an account  receivable of $42,000.  This  receivable was
               collected in January 2003.
                                      F-8



                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Summary of Significant Accounting Policies - continued

          Statement of Cash Flows - Non-cash Investing and Financing  Activities
          - continued

                    During the twelve month period ended  December 31, 2001,  we
               acquired   $15,068,774   in  property   and   equipment   through
               $10,441,824  in  notes  payable  to  financial  institutions  and
               related  parties,  by issuing  9,000  shares of  preferred  stock
               valued at  $4,500,000,  by issuing  47,500 shares of common stock
               valued at  $35,450  and by  issuing  150,000  warrants  valued at
               $91,500.  Also,  debt issue  costs  increased  $170,000  in notes
               payable.

          Use of Estimates in the Preparation of Financial Statements

                    The  preparation  of  consolidated  financial  statements in
               conformity with generally accepted accounting principles requires
               management  to make  estimates  and  assumptions  that affect the
               reported  amounts of assets and  liabilities  and  disclosure  of
               contingent assets and liabilities at the date of the consolidated
               financial  statements  and the  reported  amounts of revenues and
               expenses during the reporting period. Actual results could differ
               from those estimates.

          Oil and Gas Properties

                    We use the  successful  efforts method of accounting for oil
               and gas producing activities.  Costs to acquire mineral interests
               in oil and gas properties,  to drill and equip  exploratory wells
               that find  proved  reserves,  and to drill and equip  development
               wells are capitalized.  Costs to drill  exploratory wells that do
               not find proved  reserves,  and geological and geophysical  costs
               are expensed.

                    As we  acquire  significant  oil  and  gas  properties,  any
               unproved property that is considered individually  significant is
               periodically  assessed  for  impairment  of value,  and a loss is
               recognized  at the time of  impairment by providing an impairment
               allowance.  Capitalized costs of producing oil and gas properties
               and support equipment,  after considering estimated dismantlement
               and  abandonment   costs  and  estimated   salvage  values,   are
               depreciated and depleted by the unit-of-production method.

                    On the sale of an entire  interest in an unproved  property,
               gain or loss on the sale is recognized, taking into consideration
               the amount of any  recorded  impairment  if the property has been
               assessed  individually.  If a  partial  interest  in an  unproved
               property is sold,  the amount  received is treated as a reduction
               of the cost of the interest retained. On the sale of an entire or
               partial  interest  in  a  proved   property,   gain  or  loss  is
               recognized,  based upon the fair values of the interests sold and
               retained.

          Other Property and Equipment

                    The  following  tables set forth  certain  information  with
               respect to our other  property  and  equipment.  We  provide  for
               depreciation and amortization using the straight-line method over
               the following estimated useful lives of the respective assets:

                       Assets                                      Years
                       ---------------------------------        -------------
                            Automobiles                             3-5
                            Office equipment                         7
                            Gathering system                         10
                            Well servicing equipment                 10
                                      F-9

                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 1. Summary of Significant Accounting Policies - continued

          Other Property and Equipment - continued

                    Capitalized   costs   relating  to  other   properties   and
               equipment:

                                                                   2003                    2002
                                                           ---------------------   ---------------------
                      Automobiles                          $     420,776           $      420,776
                      Office equipment                           148,172                  137,362
                      Gathering system                           529,486                  529,486
                      Well servicing equipment                 1,033,786                1,033,786
                                                           ---------------------   ---------------------
                                                               2,132,220                2,121,410

                      Less accumulated depreciation           (1,268,330)              (1,037,076)
                                                           ---------------------   ---------------------

                      Net capitalized cost                 $     863,890           $    1,084,334
                                                           =====================   =====================

          Revenue Recognition

                    We recognize oil and gas revenues on the sales method as oil
               and  gas  production  is  sold.  Differences  between  sales  and
               production  volumes  during the years ended  December  31,  2003,
               2002, and 2001 were not significant.  Well servicing revenues are
               recognized  as the  related  services  are  performed.  Operating
               overhead  income is  recognized  based upon  monthly  contractual
               amounts for lease  operations  and other income is  recognized as
               earned.

          Trade Accounts Receivable

                    Trade accounts  receivable are reported in the  consolidated
               balance  sheet  at the  outstanding  principal  adjusted  for any
               chargeoffs.  An allocation for doubtful accounts is recognized by
               management  based upon a review of  specific  customer  balances,
               historical losses and general economic conditions.

          Fair Value of Financial Instruments

                    At December  31, 2003 and 2002,  our  financial  instruments
               consist of notes  payable  and  long-term  debt.  Interest  rates
               currently  available to us for notes payable and  long-term  debt
               with similar terms and remaining  maturities are used to estimate
               fair  value  of  such  financial  instruments.  Accordingly,  the
               carrying amounts are a reasonable estimate of fair value.

          Debt Issue Costs

                    Debt issue costs incurred are capitalized  and  subsequently
               amortized  over the term of the related  debt on a  straight-line
               basis.

          Earnings (Loss) Per Share

                    Earnings  (loss)  per share are  calculated  based  upon the
               weighted-average  number of outstanding  common  shares.  Diluted
               earnings   (loss)  per  share  are  calculated   based  upon  the
               weighted-average  number of outstanding  common shares,  plus the
               effect of dilutive stock options, warrants, convertible preferred
               stock and convertible debentures.
                                      F-10

                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 1. Summary of Significant Accounting Policies - continued

          Earnings (Loss) Per Share - continued

                    We have adopted Statement of Financial  Accounting Standards
               (SFAS) No. 128  "Earnings  Per Share",  which  requires that both
               basic earnings  (loss) per share and diluted  earnings (loss) per
               share be  presented on the face of the  statement of  operations.
               Basic earnings (loss) per share are based on the weighted-average
               number of outstanding  common  shares.  Diluted  earnings  (loss)
               per-share are based on the weighted-average number of outstanding
               common shares and the effect of all  potentially  diluted  common
               shares.

          Impairments

                    Impairments,   measured   using  fair  market   value,   are
               recognized  whenever events or changes in circumstances  indicate
               that  the  carrying  amount  of  long-lived  assets  (other  than
               unproved  oil  and gas  properties  discussed  above)  may not be
               recoverable and the future  undiscounted cash flows  attributable
               to the asset are less than its carrying value.

          Stock Based Compensation

                    In October 1995, SFAS No. 123,  "Stock Based  Compensation,"
               (SFAS 123) was issued.  This  statement  requires  that we choose
               between two different methods of accounting for stock options and
               warrants.  The  statement  defines a  fair-value-based  method of
               accounting for stock options and warrants but allows an entity to
               continue  to  measure  compensation  cost for stock  options  and
               warrants  using the  accounting  prescribed by APB Opinion No. 25
               (APB 25),  "Accounting for Stock Issued to Employees." Use of the
               APB 25 accounting  method results in no  compensation  cost being
               recognized  if options are  granted at an  exercise  price at the
               current market value of the stock or higher.  We will continue to
               use the  intrinsic  value method under APB 25 but are required by
               SFAS 123 to make pro forma  disclosures  of net income (loss) and
               earnings  (loss) per share as if the fair  value  method had been
               applied in its 2003, 2002 and 2001 financial statements.

                    During 2003,  2002 and 2001, we issued  options and warrants
               totaling:  2003 - 35,000 (all  exercisable);  2002 - 405,000 (all
               exercisable); and 2001 - 184,000 (all exercisable), respectively,
               to employees  and directors as  compensation.  If we had used the
               fair value method required by SFAS 123, our net income (loss) and
               per share information would approximate the following amounts:

                                          2003                           2002                           2001
                               ---------------------------    ----------------------------    --------------------------

                               As Reported      ProForma      As Reported      ProForma       As Reported     ProForma
                               ------------    -----------    ------------    ------------    -----------    -----------
         SFAS 123
         compensation cost     $                $     7,350   $               $    38,300     $              $   99,360
         APB 25
         compensation cost     $                $             $               $               $              $
         Net income (loss)     $(3,151,509)     $(3,158,859)  $(4,614,813)    $(4,653,113)    $  988,041     $  888,681
         Income (loss) per
         common share-basic    $      (.17)     $      (.17)  $      (.25)    $      (.25)    $      .05     $      .05
         Income (loss) per
         common share-diluted  $     (.17)      $      (.17)  $      (.25)    $      (.25)    $      .05     $      .04
                                      F-12


                     GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 1. Summary of Significant Accounting Policies - continued

          Stock Based Compensation - continued

               The  effects  of  applying  SFAS 123 as  disclosed  above are not
          indicative of future amounts.  We anticipate  making  additional stock
          based employee compensation awards in the future.

               We use the Black-Sholes option-pricing model to estimate the fair
          value of the options and warrants (to employee and  non-employees)  on
          the grant date. Significant assumptions include (1) risk free interest
          rate  2003 - 3.0%;  2002 - 3.0%;  2001 - 4.5%;  (2)  weighted  average
          expected  life  2003 -  3.4;  2002 -  3.6;  2001 - 5.0;  (3)  expected
          volatility of 2003 - 147.43; 2002 - 101.73%;  2001 - 103.27%;  and (4)
          no expected dividends.

          Implementation of New Financial Accounting Standards

               Effective  January 1, 2001,  we adopted SFAS No. 133  "Accounting
          for Derivative  Instruments and Other Hedging Activities",  as amended
          by SFAS No. 137 and No. 138. As a result of a financing agreement with
          an  energy  lender,  we were  required  to  enter  into an oil and gas
          hedging  agreement  with  the  lender.  It has  been  determined  this
          agreement  meets the definition of SFAS 133 "Accounting for Derivative
          Instruments  and  Hedging  Activities"  and  is  accounted  for  as  a
          derivative instrument.

               The estimated change in fair value of the derivatives is reported
          in Other Income and Expense as  unrealized  (gain) loss on  derivative
          instruments.  The estimated fair value of the  derivatives is reported
          in Other Assets (or Other Liabilities) as derivative instruments.

               The estimated fair value of the derivative instruments at January
          1, 2001, the date of initial application of SFAS 133, of $3,747,435 is
          reported in the Statement of Operations as the cumulative  effect of a
          change in accounting principle.

               In June, 2001, SFAS No. 141 "Business  Combinations" and SFAS No.
          142 "Goodwill and Other  Intangible  Assets were issued.  We presently
          have no goodwill  or  intangible  assets and are thus not  affected by
          SFAS No. 142.

               Effective  January 1, 2002, we adopted SFAS No. 144,  "Accounting
          for the  Impairment or Disposal of Long-Lived  Assets." This statement
          requires  the   following   three-step   approach  for  assessing  and
          recognizing the impairment of long-lived  assets: (1) consider whether
          indicators  of impairment  of  long-lived  assets are present;  (2) if
          indicators of impairment are present, determine whether the sum of the
          estimated undiscounted future cash flows attributable to the assets in
          question  is  less  than  their  carrying  amount;  and  (3) if  less,
          recognize  an  impairment  loss  based on the  excess of the  carrying
          amount of the assets over their  respective fair values.  In addition,
          SFAS No. 144  provides  more  guidance on  estimating  cash flows when
          performing a recoverability  test, requires that a long-lived asset to
          be disposed of other than by sale (such as abandoned) be classified as
          "held  and  used"  until  it is  disposed  of,  and  establishes  more
          restrictive  criteria  to  classify  an asset as "held for sale".  The
          adoption  of SFAS  No.  144  did not  have a  material  impact  on our
          financial  statements since it retained the fundamental  provisions of
          SFAS No. 121, "Accounting for the Impairment or Disposal of Long-Lived
          Assets and for  Long-Lived  Assets to be Disposed  Of," related to the
          recognition and measurement of the impairment of long-lived  assets to
          be "held and used".
                                      F-12


                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 1. Summary of Significant Accounting Policies - continued

     Implementation of New Financial Accounting Standards - continued

               In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
          Associated with Exit or Disposal  Activities."  SFAS No. 146 addresses
          financial  accounting and reporting for costs  associated with exit or
          disposal  activities  and  nullifies  EITF Issue No. 94-3,  "Liability
          Recognition for Certain Employee  Termination Benefits and Other Costs
          to  Exit  an  Activity   (including   Certain  Costs   Incurred  in  a
          Restructuring)."  SFAS No. 146  requires  that a liability  for a cost
          associated  with an exit or disposal  activity be recognized  when the
          liability is incurred.  Under EITF Issue No. 94-3, a liability  for an
          exit  cost as  defined  was  recognized  at the  date  of an  entity's
          commitment  to an exit plan.  SFAS No. 146 also  establishes  that the
          fair  value  is the  objective  for  the  initial  measurement  of the
          liability.  SFAS No. 146 is effective for exit and disposal activities
          that are initiated after December 31, 2002. This statement will impact
          the timing of our recognition of liabilities for costs associated with
          exit or disposal activities.

               Beginning in 2003,  Statement of Financial  Accounting  Standards
          No. 143, "Asset  Retirement  Obligations"  ("SFAS 143") requires us to
          recognize an estimated  liability for the plugging and  abandonment of
          our  oil  and  gas  wells  and  associated  pipelines  and  equipment.
          Consistent  with industry  practice,  historically  we had assumed the
          cost of  plugging  and  abandonment  would be offset by salvage  value
          received.  This  statement  requires us to record a  liability  in the
          period in which our asset retirement  obligation  ("ARO") is incurred.
          After initial  recognition  of the  liability,  we must  capitalize an
          additional  asset  cost  equal  to the  amount  of the  liability.  In
          addition to any  obligation  that arises after the  effective  date of
          SFAS 143, upon initial  adoption we must recognize (1) a liability for
          any existing ARO's, (2) capitalized cost related to the liability, and
          (3)  accumulated  depreciation,  depletion  and  amortization  on that
          capitalized cost adjusting for the salvage value of related equipment.

               The  estimated  liability is based on  historical  experience  in
          plugging and  abandoning  wells,  estimated  remaining  lives of those
          wells based on  reserves  estimates  and federal and state  regulatory
          requirements.   The   liability   is   discounted   using  an  assumed
          credit-adjusted  risk-free  rate of 7.5%.  Revisions to the  liability
          could occur due to changes in estimates  of plugging  and  abandonment
          costs,  changes in the risk-free rate or remaining lives of the wells,
          or if federal or state  regulators  enact new plugging and abandonment
          requirements.  At the  time of  abandonment,  we will be  required  to
          recognize  a gain or loss on  abandonment  if the actual  costs do not
          equal the estimated costs.

               The adoption of SFAS 143 resulted in a January 1, 2003 cumulative
          effect adjustment to record (i) a $1,058,445  increase in the carrying
          value of proved  properties,  (ii) a $484,390  decrease in accumulated
          depreciation,  depletion and amortization, (iii) a $1,280,383 increase
          in noncurrent liabilities, and (iv) a $262,452 gain, net of tax.

Note 2.  Operations and Management Plans

               At December  31,  2003,  our  current  liabilities  exceeded  our
          current  assets  by  $42,876,963.  We had a loss  available  to common
          shareholders  of  $3,151,509  compared to a loss  available  to common
          shareholders  of $4,614,813  at December 31, 2002.  This loss included
          non-cash  items  of  $537,526  for   unrealized   gain  on  derivative
          instruments,  a loss of $358,737 for  abandonment  of properties and a
          $262,452  gain  from the  recording  of Asset  Retirement  Obligations
          ("ARO's"), as required by SFAS 143, at January 1, 2003.

               In  2004,  we will  continue  the  recapitalization  of debt  and
          funding  of our  capital  development  program  that we began in 2003.
          Following are the steps we are taking and plan to take to achieve that
          purpose:
                                      F-13



                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 2. Operations and Management Plans - continued

     (a) The first step is to close the refinancing of our largest debt of $27.8
million  held  by  Concert  Capital  Resources  LP  ("CCR")  and  loaned  to our
wholly-owned  subsidiary,  GulfWest Oil and Gas  Company.  We have entered into an
agreement  with a new lending source that,  subject to due diligence,  will fund
approximately  $14  million to purchase  the $27.8  million  note.  The new debt
financing will also provide for the payment of closing costs.  CCR has agreed to
sell the note to our new  financier  for a $14  million  cash  payment  and a $4
million subordinated note from us.

     (b) Secondly, we are continuing to work with our financial advisor to raise
an additional $4 to $5 million through the sale of our preferred stock. Proceeds
from  this  equity  sale  will be used  for  working  capital  and  fund our new
development projects. The refinancing of the CCR debt and sale of new equity are
both currently scheduled to close in April, 2004.

     (c) Effective December 1, 200l and amended August 16, 2002, we entered into
an Oil and Gas Property Acquisition,  Exploration and Development Agreement (the
"Summit  Agreement") with Summit  Investment  Group-Texas,  L.L.C., an unrelated
party,  ("Summit").  Under  the  agreement,  Summit  provided  payments  in  the
aggregate of $1,200,000 in advanced funds for our use in the  acquisition of oil
and  gas  leases  and  other  mineral  and  royalty  interests,  and  production
activities, and was to recoup and recover those advanced funds.

     In a subsequent event on March 5, 2004, we entered into an Option Agreement
for the  Purchase of Oil and Gas Leases  (the  "Addison  Agreement")  with W. L.
Addison  Investments  L.L.C.,  a private company owned by Mr. J. Virgil Waggoner
and Mr.  John E. Loehr,  two of our  directors,  (`Addison").  Under the Addison
Agreement,  Addison agreed to pay Summit,  on our behalf,  the  non-recouped and
outstanding advanced funds amounting to $1,200,000,  thereby retiring the Summit
Agreement.  For consideration of such payment,  Addison acquired certain oil and
gas leases and wellbores from Summit but agreed to grant us a 180-day redemption
option  (which may be  extended  by mutual  consent)  to  purchase  the same for
$1,200,000,  plus  interest  at the prime  rate plus 2%. We  tendered  Addison a
promissory note in the amount of $600,000,  with interest at the prime rate plus
2%, to  substitute  for an account  payable to  Summit,  pursuant  to the Summit
Agreement,  in the same amount.  The note will be considered  paid in full if we
exercise the redemption  option and pay the  $1,200,000,  plus interest.  Summit
retained the right to participate  up to a 25% working  interest in the drilling
of any wells on the leases  acquired  by Addison.  In the event we exercise  the
redemption option,  Addison may, at its sole option,  retain up to a 25% working
interest in the leases.

     (d) Finally,  after completing the above, we will pursue the  consolidation
of all of our debt,  including  other  asset and  bridge  loans.  Our goal is to
simplify our financial  structure and provide  adequate  capitalization  for the
development of our oil and gas assets.

                                      F-14



                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 3. Cost of Oil and Gas Properties

          The following tables set forth certain information with respect to our
     oil and gas producing activities for the periods presented:

     Capitalized Costs Relating to Oil and Gas Producing Activities:

                                                                          2003                      2002
                                                                     ----------------          ----------------
              Unproved oil and gas properties                        $    261,650              $     439,926
              Proved oil and gas properties                            54,669,482                 52,847,625
              Support equipment and facilities                          3,541,754                  3,498,492
                                                                     ----------------          ----------------
                                                                       58,472,886                 56,786,043
              Less accumulated depreciation, depletion and
              Amortization                                             (8,749,601)                (7,461,421)
                                                                     ----------------          ----------------
              Net capitalized costs                                  $ 49,723,285              $  49,324,622
                                                                     ================          ================

     Results of Operations for Oil and Gas Producing Activities:


                                                                      2003                2002               2001
                                                                  ---------------    ----------------    ---------------
              Oil and gas sales                                   $  10,844,466      $  10,447,169       $ 12,426,103

              Production costs                                       (5,527,841)        (5,430,205)        (5,155,500)

              Depreciation, depletion and amortization               (1,527,727)        (2,187,036)        (2,018,890)

              Accretion expense                                         (76,823)
                                                                  ---------------    ----------------    ---------------
              Income tax expense                                        -                  -                   _
                                                                  ---------------    ----------------    ---------------
              Results of operations for oil and gas
                producing activities - income                     $   3,712,075      $   2,829,928       $   5,251,713
                                                                  ===============    ================    ===============
              Costs Incurred in Oil and Gas Producing Activities:
                                                                      2003                2002               2001
                                                                  ---------------    ----------------    ---------------
              Property Acquisitions
                    Proved                                        $      -           $      562,760      $ 15,236,808

                    Unproved                                          110,119                14,401           154,076

              Development Costs                                     2,024,663             5,141,075         6,317,527
                                                                  ---------------    ----------------    ---------------
                                                                  $ 2,134,782        $    5,718,236      $ 21,708,411
                                                                  ===============    ================    ===============
                                                                 F-15


                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3. Cost of Oil and Gas Properties - continued

          Effective  July  1,  2001,  we  acquired  interests  in  oil  and  gas
     properties  located in Texas and Louisiana from an unrelated  party,  Grand
     Goldking L.L.C. The acquisition  cost was $15,077,358,  consisting of 9,000
     shares of Series E preferred  stock valued at $4,500,000 and $10,000,000 in
     debt. In addition,  we paid $545,300 in commissions  to unrelated  parties.
     The  commissions  were paid by issuing 10,000 shares of common stock valued
     at $8,800,  150,000  warrants  valued at $91,500 and  $445,000 in cash.  We
     incurred  additional cash costs of $33,058 related to the  acquisition.  On
     the same date, we transferred its ownership interest in these properties to
     our wholly owned subsidiary, GulfWest Oil and Gas Company.

          Supplemental  unaudited  pro forma  information  (under  the  purchase
     method of  accounting)  presenting  the results of operations  for the year
     ended December 31, 2001, as if the Grand Goldking  acquisition had occurred
     as of January 1, 2001:

                                                                 Year Ended
                                                                 December 31,
                                                                    2001
                                                               ----------------
                 Operating revenues                            $   15,649,329
                 Operating expenses                                10,652,222
                                                               ----------------
                 Income from operations                             4,997,107
                 Other income and expense                          (3,325,166)
                 Income taxes                                          -
                                                                ----------------
                 Net income                                         1,671,941
                 Preferred dividends                                 (112,500)
                                                               ----------------
                 Net income to common shareholders             $    1,559,441
                                                               ================
                 Earnings per share
                      Basic                                    $         0.08
                                                               ================
                      Diluted                                  $         0.07
                                                               ================

                    Effective   January  1,  2002,   we  acquired  oil  and  gas
               properties   located  in  Louisiana  from  a  related  party  for
               $182,742.  The  acquisition  price  was the  amount  of  accounts
               receivable due us.

Note 4. Accrued Expenses

              Accrued expenses consisted of the following:

                                                  December 31,               December 31,
                                                      2003                       2002
                                                 ----------------          -----------------
                 Payroll and payroll taxes       $      5,833              $       1,863
                 Interest                             395,735                    414,724
                 Professional fees                     42,000                     42,000
                                                 ----------------          -----------------
                                                 $    443,568              $     458,587
                                                 ================          =================
                                      f-16



                                                                 F-17
                                                 GULFWEST ENERGY INC. AND SUBSIDIARIES
                                              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 5. Notes Payable and Long-Term Debt

          Notes    payable   is   as    follows:                                     2003                   2002
                                                                                ------------------   ------------------
          Non-interest bearing note payable to an unrelated party;  payable out
            Of 50% of the net  transportation  revenues  from a certain  natural
            gas pipeline; no due date.                                          $        40,300      $         40,300

         Promissory note payable to a former director at 8%; due May,
              2001; unsecured.                                                           40,000                40,000

         Promissory note payable to an unrelated party at 10%; payable on
              demand; unsecured.                                                         45,000                45,000

         Line of credit (up to $2,500,000) to a bank; due October, 2002; secured
              by  guaranty  of a  director;  interest  greater of prime rate less
              .25% or 5.25%, (prime rate 4.0% at December 31, 2003).  Line of
              credit increased to $3,000,000 and due date extended to April, 2004.    2,995,488             2,995,488

         Note payable to a bank; due March, 2003; interest at prime rate plus 1%
              (prime rate 4.0% at December 31, 2003); secured by guaranty of
              three of our directors; retired September 2003.                                                 500,000

         Promissory note payable to an unrelated party; payable on demand;
              interest  at 8%;  interest  increased  to 12% on  January  1, 2003;
         secured by certain oil and gas properties.                                     300,000               300,000

         Note payable to a bank; due July, 2004; secured by guaranty
              of a director; interest at prime rate (prime rate 4.0% at December
              31, 2003 with a floor of 4.75% and a ceiling of 8.0%.                     948,400             1,000,000

         Promissory note payable to unrelated party; interest at 6%; due June,
              2003.                                                                     55,300                 55,300

         Promissory note payable to one of our directors; interest at 8%;
              due on demand; unsecured.                                                 50,000                 50,000

         Promissory note payable to one of our directors; interest at
              prime rate (prime rate 4.0% at December 31, 2003); due May, 2003;
              secured by common stock of DutchWest Oil Company, our wholly
              owned subsidiary.                                                      1,375,000              1,200,000

         Promissory note payable to an unrelated party at 8%; due June 2003;
              secured by 4% of the common stock of DutchWest Oil Company, our
              wholly owned subsidiary                                                  100,000

         Promissory note payable to an unrelated party at 8%; due May 2003;
              secured by 8% of the common stock of DutchWest Oil Company, our
              wholly owned subsidiary                                                  200,000

                                      F-17


                                                 GULFWEST ENERGY INC. AND SUBSIDIARIES
                                              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5. Notes Payable and Long-Term Debt

          Notes payable is as follows - continued:

                                                                                       2003                 2002
                                                                                   --------------    -------------------
         Line of credit (up to $3,500,000) to a bank; due June 2004; secured by
              the  guaranty  of a  director;  interest  at prime rate (prime rate
              4.0% at December 31, 2003) with a floor of 4.75% and a ceiling of
              8.0%                                                                   3,497,677
                                                                                   --------------    -------------------
                                                                                   $ 9,647,165       $      6,226,088
                                                                                   ==============    ===================

              The weighted average interest rate for notes payable at December
              31, 2003 and 2002 was 5.0% and 4.7%, respectively.

          Long-term debt is as follows:
                                                                                       2003                 2002
                                                                                  --------------     ------------------
         Line of credit (up to $3,000,000) to a bank; due July, 2003; secured
              by the guaranty of a director; interest at prime rate (prime rate
              4.0% at  December  31,  2003);  replaced by a  short-term  line of
              credit (up to $3,500,000) from the same bank.                       $                  $      2,999,515

         Subordinated promissory notes to various individuals at 9.5% interest
              per annum;  amounts include $50,000 due to related  parties; past
              due.                                                                      150,000               150,000

         Notes payable to finance vehicles, payable in aggregate monthly
              installments of approximately $4,000, including interest of.9% to
              13% per annum; secured by the related equipment; due various
              dates through 2007.                                                        69,500               116,721

         Note payable to related party to finance equipment with monthly
              installments of $5,200, including interest at 13.76% per annum;
              final payment due October, 2003; secured by related equipment;
              retired June, 2003.                                                                              48,850

         Promissory note to a director; interest at 8.5%; due
              December 31, 2003.                                                         78,941                95,670

         Note payable to a bank with monthly principal payments of $2,300;
              interest at 9.5%; due May, 2003; secured by related equipment;
              retired May, 2003.                                                                               11,630

         Note payable to an energy lender; interest at prime plus 3.5% (prime
              rate 4.0% at December 31, 2003) payable monthly out of 90%
              net profits from certain oil and gas properties; final payment due
              May, 2004; secured by related oil and gas properties.                  27,574,769            27,907,509
                                                                 F-18


                     GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5. Notes Payable and Long-Term Debt

         Long-term debt is as follows - continued:

                                                                                       2003                  2002
                                                                                 -----------------     -----------------
         Note payable to a bank with monthly principal payments of $36,000;
              interest at prime plus 1% (prime rate 4.0% at December 31,
              2003) with a minimum prime rate of 5.5%; final payment due
              November, 2003; secured by related oil and gas properties;
              extended to March, 2004.                                                1,564,000             1,996,000

         Note payable to unrelated party to finance saltwater disposal well
              with monthly  installments of $4,540,  including  interest at 10%
              per annum; final payment due January, 2005; secured by related well.      123,624               123,624

         Note payable to related party to finance equipment with monthly
              installments of $5,109, including interest at 13.75% per annum;
              final payment due February, 2004; secured by related equipment;
              retired June, 2003.                                                                              65,743

         Note payable to related party to finance equipment with monthly
              installments of $608, including interest at 11% per annum;
              final payment due February, 2004; secured by related equipment.             1,211                 7,960
                                                                                 -----------------     -----------------
                                                                                     29,562,045            33,523,222
         Less current portion                                                        (29,526,244)         (33,385,414)
                                                                                 -----------------     -----------------
         Total long-term debt                                                    $        35,801              137,808
                                                                                 =================     =================

               Estimated annual maturities for long-term debt are as follows:

                   2004                                                         $     29,526,244
                   2005                                                                   27,292
                   2006                                                                    7,150
                   2007                                                                    1,359
                   2008                                                                    -
                                                                                ------------------
                                                                                $     29,562,045
                                                                                ==================
                                      F-19

                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 6.   Stockholders' Equity

          Common Stock
          ------------
                                                                                     2003                  2002
                                                                               -----------------       --------------
         Par value $.001; 40,000,000 shares authorized; 18,492,541
              shares issued and outstanding as of December 31, 2003 and
              2002, respectively                                              $         18,493         $      18,493

                                                                                  =================    ==============

          Preferred Stock
          ---------------

         Series D, par value $.01; 12,000 shares authorized; 8,000 shares
              issued and outstanding at December 31, 2003 and 2002.  The
              Series D preferred stock does not pay dividends and is not
              redeemable.  The liquidation value is $500 per share.  After
              three years from the date of issue, and thereafter, the shares
              are convertible to common stock based upon a value of $500
              per Series D share divided by $8 per share of common stock.                   80                   80

         Series E, par value $.01; 9,000 shares authorized; 9,000 shares
              issued and outstanding at December 31, 2003 and 2002.  The
              Series E preferred  stock pays  dividends,  as declared,  at a
         rate
              of 2.5% per annum, has a liquidation value of $500 per share,
              may be redeemed at our option and, if not redeemed after two
              years, is convertible to common stock based upon a value of
              $500 per Series E share divided by $2 per share of common
              stock.                                                                         90                  90

         Series F, par value $.01; 2,000 shares authorized; 2,000 shares
              issued and outstanding at December 31, 2003.  The Series F
              preferred  stock pays  dividends,  as  declared,  at a rate of
         2.5% per
              annum, has a liquidation value of $500 per share, may be
              redeemed at our option and, if not  redeemed  after two years,
              is convertible to common stock based upon a value of $500 per
              Series E share divided by $1 per share of common stock.                        20
                                                                                    -----------------    --------------
                                                                                    $       190                 170
                                                                                    =================    ==============

                    All  classes  of  preferred  shareholders  have  liquidation
               preference over common  shareholders of $500 per preferred share,
               plus accrued dividends. Dividends in arrears at December 31, 2003
               we $127,083 (Series E $112,500; Series F $14,583).

          Stock Options
          -------------

                    We maintain a  Non-Qualified  Stock  Option Plan (as amended
               and restated,  the "Plan"), which authorizes the grant of options
               of up to  2,000,000  shares  of  common  stock.  Under  the Plan,
               options  may be  granted to any of our key  employees  (including
               officers),  employee and nonemployee  directors,  and advisors. A
               committee  appointed by the Board  administers the Plan. Prior to
               1999,  options  granted  under  the Plan had been  granted  at an
               option  price of $3.13 and $1.81 per  share.  In July  1999,  the
               Board  authorized  that all then  current  employee  and director
               options  under the plan be  reduced to a price of $.75 per share.
               Following is a schedule by year of the activity  related to stock
               options,  including  weighted-average ("WTD AVG") exercise prices
               of options in each category.
                                      F-20

                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 6.   Stockholders' Equity - continued

                                               2003                            2002                          2001
                                    ---------------------------    -----------------------------    ------------------------
                                    Wtd Avg                         Wtd Avg                         Wtd Avg
                                    Prices          Number          Prices           Number          Prices        Number
                                    --------    ---------------    ----------    ---------------    ---------    -----------
         Balance, January 1         $   .90         1,067,000      $ 1.03           1,097,000       $    .09        923,000
               Options issued       $   .75            35,000      $  .75              35,000       $    .83        184,000
               Options expired      $     -              -         $ 3.00             (65,000)      $   3.00        (10,000)
                                                ---------------                  ---------------                 -----------
         Balance, December 31       $   .90         1,102,000      $  .90           1,067,000       $   1.03      1,097,000
                                                ===============                  ===============                 ===========

                    All options were exercisable at December 31, 2003. Following
               is a schedule by year and by exercise  price of the expiration of
               our stock options issued as of December 31, 2003:

                        2004           2005          2006          2007        Thereafter         Total
                      ----------    -----------    ----------    ----------    ------------     -----------
            $ .75       432,000                                     35,000         185,000         652,000
            $ .83                                    184,000                                       184,000
            $1.13                      100,000                                                     100,000
            $1.20                      106,000                                                     106,000
            $1.81                                                                   60,000          60,000
                      ----------    -----------    ----------    ----------    ------------     -----------
                        432,000        206,000       184,000        35,000         210,000       1,102,000
                      ==========    ===========    ==========    ==========    ============     ===========

          Stock Warrants
          --------------

                    We have issued a significant  number of stock warrants for a
               variety  of  reasons,   including   compensation   to  employees,
               additional inducements to purchase our common or preferred stock,
               inducements  related to the  issuance  of debt and for payment of
               goods  and  services.  Following  is a  schedule  by  year of the
               activity  related to stock warrants,  including  weighted-average
               exercise prices of warrants in each category:

                                               2003                          2002                           2001
                                     --------------------------    --------------------------    ---------------------------
                                     Wtd Avg                       Wtd Avg                       Wtd Avg
                                      Prices         Number         Prices         Number         Prices         Number
                                     ---------    -------------    ---------    -------------    ---------    --------------
         Balance, January 1          $  1.24        2,181,754      $  2.15        1,306,754      $ 2.31          1,392,254
             Warrants issued         $   .75          150,000      $   .75        1,145,000      $  .75            150,000
             Warrants exercised
                  or expired         $(3.61)        (366,754)      $  3.57         (270,000)     $ 2.22           (235,500)
                                                  -------------                 -------------                 --------------

         Balance, December 31        $   .76       1,965,000       $  1.24        2,181,754      $ 2.15          1,306,754
                                                  =============                 =============                 ==============

                    Included   in   the   "warrants    issued"   and   "warrants
               exercised/expired"  columns in 2002 were 270,000  warrants  whose
               price was reduced in 2002 to $.75.
                                      F-21

                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 6.   Stockholders' Equity - continued

               Following  is a  schedule  by year and by  exercise  price of the
          expiration of our stock warrants issued as of December 31, 2003:

                          2004           2005            2006            2007            2008            Total
                          ----           ----            ----            ----            ----            -----
         $  .75                         225,000       1,590,000                                       1,815,000
            .875                        150,000                                                         150,000
                        ----------    ----------    -------------    ------------    -----------     ------------
                            -           375,000       1,590,000           -              -            1,965,000
                        ==========    ==========    =============    ============    ===========     ============

               Warrants outstanding to our officers,  directors and employees at
          December 31, 2003 and 2002 were approximately 1,515,000 and 1,682,000,
          respectively. The exercise prices on these warrants range from $.75 to
          $.88 and expire various dates through 2006.

Note 7.   Income (Loss) Per Common Share

          The following is a  reconciliation  of the numerators and denominators
          used in computing income (loss) per share:

                                                         2003                  2002                 2001
                                                   ------------------    -----------------    ------------------
         Net income (loss)                         $   (3,024,426)           (4,502,313)      $       1,044,291
         Preferred stock dividends                       (127,083)             (112,500)                (56,250)
                                                   ------------------    -----------------    ------------------
         Income (loss) available to common
         shareholders (numerator)                  $   (3,151,509)       $   (4,614,813)      $         988,041
                                                   ==================    =================    ==================
         Weighted-average number of shares
            of common stock - basic (denominator)      18,492,541            18,492,541              18,464,343
                                                   ------------------    -----------------    ------------------
         Income (loss) per share - basic           $         (.17)       $         (.25)      $             .05
                                                   ==================    =================    ==================

               Potential dilutive securities (stock options,  stock warrants and
          convertible preferred stock) in 2003 and 2002 have not been considered
          since we reported a net loss and, accordingly,  their effects would be
          antidilutive.  Potential  dilutive  securities  (stock options,  stock
          warrants and convertible  preferred stock) totaling 2,780,520 weighted
          average shares in 2001 have been  considered but there is no effect on
          income per common share.

Note 8.   Related Party Transactions

               On December 1, 1992, Ray Holifield and Associates,  Inc. executed
          an unsecured  promissory  note to us for $118,645 with interest at 10%
          per annum,  due on October 1, 1993. At December 31, 1993, the note was
          still outstanding.  During 1994, we entered into an agreement with the
          Holifield  Trust in which Holifield will make payments on the past due
          note from future oil and gas revenue. During 1995, $10,995 of interest
          payments were received.  At December 31, 2001 the unsecured promissory
          note had been fully  reserved.  At December  31, 2002,  the  unsecured
          promissory note had been fully written off.

               On December 1, 1992,  Parkway Petroleum  Company, a Ray Holifield
          related  company,  executed  an  unsecured  promissory  note to us for
          $54,616 with  interest at 10% per annum,  due on October 1, 1993.  The
          note was issued for amounts  due from  contract  drilling  services we
          provided Parkway Petroleum Company. At December 31, 1993, the note was
          still outstanding.  During 1994, we entered into an agreement with the
          Holifield  Trust in which Holifield will make payments on the past due
          note from future oil and gas revenue. During 1995,
                                      F-22

                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 8.   Related Party Transactions - continued

               $6,250 of interest payments were received.  At December 31, 2001,
          the unsecured promissory note had been fully reserved. At December 31,
          2002, the unsecured promissory note had been fully written off.

               On January 10, 1994, we entered into a consulting  agreement with
          Williams  Southwest  Drilling Company,  Inc.  ("Williams")  whereby we
          would provide management and accounting services for $25,000 per month
          for a period of one  year.  We  accrued  the  consulting  fees with an
          offset  to  deferred  income  until  payment  of the fees is  actually
          received. During 1994, $172,140 was recorded as consulting fee income.
          Beginning in the second quarter 1994, we began recognizing  consulting
          income  only as cash  payments  were  received.  Prior  to the  second
          quarter,  $75,000 in consulting  fee revenue was accrued.  We received
          $97,140 in  consulting  fee  payments.  As of December 31,  1994,  the
          receivable  from  Williams of $202,860  for  consulting  fees has been
          offset by deferred  income of $127,860  and a provision  for  doubtful
          accounts  of  $75,000.  Effective  January  1,  1995,  we  received  a
          promissory  note from  Williams  in the  amount of  $202,860,  bearing
          interest  at the  rate of 10% per  annum,  and  payable  in  quarterly
          installments of principal and interest of $15,538.87.  At December 31,
          2001,  the  unsecured  promissory  note had been  fully  reserved.  At
          December  31,  2002,  the  unsecured  promissory  note had been  fully
          written off.

               From  July 22 to August  13,  1998,  we  advanced  sums  totaling
          $102,000 to Gulf Coast  Exploration,  Inc. At December 31,  2001,  the
          debt had been fully reserved.  At December 31, 2002, the debt had been
          fully written off.

               On  October 1,  1998,  Toro Oil  Company  executed  an  unsecured
          promissory note to us for the purchase of 100% of WestCo for $150,000,
          with  interest at the prime rate per annum and due September 30, 1999.
          To date,  no principal  payments have been  received.  At December 31,
          2001, the  promissory  note had been fully  reserved.  At December 31,
          2002, the debt had been fully written off.

               In a subsequent event on March 5, 2004, we entered into an Option
          Agreement  for  the  Purchase  of Oil  and Gas  Leases  (the  "Addison
          Agreement") with W. L. Addison  Investments  L.L.C., a private company
          owned by Mr. J. Virgil  Waggoner  and Mr.  John E.  Loehr,  two of our
          directors, (`Addison").  Effective December 1, 200l and amended August
          16, 2002,  we had entered  into an Oil and Gas  Property  Acquisition,
          Exploration and Development  Agreement (the "Summit  Agreement")  with
          Summit Investment Group-Texas, L.L.C., an unrelated party, ("Summit").
          Under the  agreement,  Summit  provided  payments in the  aggregate of
          $1,200,000 in advanced funds for our use in the acquisition of oil and
          gas leases and other  mineral and royalty  interests,  and  production
          activities,  and was to recoup and recover those advanced funds. Under
          the Addison  Agreement,  Addison agreed to pay Summit,  on our behalf,
          the   non-recouped   and  outstanding   advanced  funds  amounting  to
          $1,200,000,  thereby retiring the Summit Agreement.  For consideration
          of such  payment,  Addison  acquired  certain  oil and gas  leases and
          wellbores  from  Summit  but  agreed to grant us a 180-day  redemption
          option (which may be extended by mutual  consent) to purchase the same
          for  $1,200,000,  plus interest at the prime rate plus 2%. We tendered
          Addison a promissory note in the amount of $600,000,  with interest at
          the prime rate plus 2%, to  substitute  for an account  payable due to
          Summit, pursuant to the Summit Agreement, in the same amount. The note
          will be considered  paid in full if we exercise the redemption  option
          and pay the  $1,200,000,  plus interest.  Summit retained the right to
          participate up to a 25% working  interest in the drilling of any wells
          on the  leases  acquired  by  Addison.  In the event we  exercise  the
          redemption option, Addison may, at its sole option, retain up to a 25%
          working interest in the leases.

               Interest  expensed on related party notes  totaled  approximately
          $76,000,  $53,000 and $128,000 for the years ended  December 31, 2003,
          2002 and 2001 respectively.

Note 9.   Income Taxes

               The  components  of the net  deferred  federal  income tax assets
          (liabilities)  recognized in our  consolidated  balance sheets were as
          follows::
                                      F-23



                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 9.   Income Taxes - continued


                                                                     December 31,          December 31,
                                                                         2003                  2002
                                                                         ----                  ----
         Deferred tax assets
             Net operating loss carryforwards                      $  6,352,507             5,236,485
             Oil and gas properties                                     610,381               542,131
             Capital loss carryforwards                                   -                    93,211
             Derivative instruments                                     201,099               383,858
             Accretion                                                   26,120
                                                                   -----------------    -------------------

         Net deferred tax assets before
             valuation allowance                                      7,190,107             6,255,685
         Valuation allowance                                         (7,190,107)           (6,255,685)
                                                                   -----------------    -------------------
         Net deferred tax assets (liabilities)                     $     -              $       -
                                                                   =================    ===================

               As of December 31, 2003 and 2002,  we did not believe it was more
          likely than not that the net  operating  loss  carryforwards  would be
          realizable  through  generation of future taxable  income;  therefore,
          they  were  fully  reserved.

               The following table summarizes the difference  between the actual
          tax provision  and the amounts  obtained by applying the statutory tax
          rate of 34% to the income  (loss)  before  income  taxes for the years
          ended December 31, 2003, 2002 and 2001.

                                                                     2003                2002                2001
                                                               -----------------   -----------------    ----------------

         Tax (benefit) calculated at statutory rate            $   (1,028,305)     $   (1,530,786)      $      355,059

         Increase (reductions) in taxes due to:

             Effect on non-deductible expenses                        362,910              65,174               18,157
             Change in valuation allowance                            934,422           1,586,988             (345,754)
             Other                                                   (269,027)           (121,376)             (27,462)
                                                               -----------------   -----------------    ----------------

         Current federal income tax provision                  $        -          $        -           $        -
                                                               =================   =================    ================

               As of December 31, 2003 we had net operating  loss  carryforwards
          of  approximately  $18,700,000,  which are  available to reduce future
          taxable income and capital gains, respectively, and the related income
          tax liability.  The net operating loss carryforward expires at various
          dates through 2023.

Note 10.  Commitments and Contingencies

          Oil and Gas Hedging Activities

               We entered into an agreement with an energy lender  commencing in
          May,  2000, to hedge a portion of our oil and gas sales for the period
          of May, 2000 through  April,  2004.  The agreement  called for initial
          volumes of 7,900  barrels  of oil and  52,400  Mmbtu of gas per month,
          declining monthly thereafter.  We entered into a second agreement with
          the energy lender, commencing September,  2001, to hedge an additional
          portion of our oil and gas sales for the  periods of  September,  2001
          through  July,  2004  and  September,   2001  through  December  2002,
          respectively.  The  agreement  called  for  initial  volumes of 15,000
          barrels of oil and 50,000  Mmbtu of gas per month,  declining  monthly
          thereafter. Volumes at December 31, 2003 had declined to 6,400 barrels
          of oil and 21,200 Mmbtu of gas. As a result of these  agreements,
                                      F-24

                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 10.  Commitments and Contingencies - continued

          we  realized a  reduction  in revenues  of  $1,496,303,  $368,776  and
          $762,480 for the  twelve-month  periods ended December 31, 2003,  2002
          and 2001, respectively, which is included in oil and gas sales.

          Lease Obligations

               We lease  office space at one  location  under a sixty-four  (64)
          month lease,  which commenced December 1, 2001 and was amended May 30,
          2002 after expansion.  Annual  commitments under the lease are: 2004 -
          $130,050,  2005 - $132,979,  2006 - $135,323 and 2007 - $33,977. Total
          rent expense for the years ended December 31, 2003, 2002 and 2001 were
          approximately $134,500, $91,000 and $60,000, respectively.

          Litigation

               From time to time, we are involved in  litigation  arising out of
          our  operations  or from disputes with vendors in the normal course of
          business.  As of March  29,  2004,  we were not  engaged  in any legal
          proceedings  that are expected,  individually or in the aggregate,  to
          have a material effect on our consolidated financial statements.
                                      F-25

                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 11.    Oil and Gas Reserves Information (Unaudited)

               The  estimates  of proved oil and gas  reserves  utilized  in the
          preparation  of the financial  statements  are estimated in accordance
          with guidelines  established by the Securities and Exchange Commission
          and the  Financial  Accounting  Standards  Board,  which  require that
          reserve  estimates be prepared under  existing  economic and operating
          conditions  with no  provision  for  price and cost  escalations  over
          prices  and  costs   existing  at  year  end  except  by   contractual
          arrangements.

               We emphasize  that reserve  estimates are  inherently  imprecise.
          Accordingly,  the  estimates  are  expected to change as more  current
          information becomes available.  Our policy is to amortize  capitalized
          oil and gas costs on the unit of production  method,  based upon these
          reserve estimates.  It is reasonably possible that, because of changes
          in market  conditions  or the inherent  imprecision  of these  reserve
          estimates,  that the  estimates of future cash  inflows,  future gross
          revenues,  the amount of oil and gas reserves, the remaining estimated
          lives of the oil and gas  properties,  or any combination of the above
          may be increased or reduced in the near term. If reduced, the carrying
          amount of capitalized oil and gas properties may be reduced materially
          in the near term.
                                      F-26

                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 11.    Oil and Gas Reserves Information (Unaudited) - continued

               The  following  unaudited  table  sets  forth  proved oil and gas
          reserves,  all within the United States,  at December 31, 2003,  2002,
          and 2001, together with the changes therein.

                                                                                      Crude Oil          Natural Gas
                                                                                       (BBls)               (Mcf)
                                                                                   ----------------    ----------------
         QUANTITIES OF PROVED RESERVES:

              Balance December 31, 2000                                                 4,575,179          24,811,919
                   Revisions                                                             (386,078)            238,595
                   Extensions, discoveries and additions                                    5,676             895,333
                   Purchase                                                             2,078,561          14,905,837
                   Sales                                                                 (107,225)              1,122
                   Production                                                            (294,276)         (1,594,899)
                                                                                   ----------------    ----------------

              Balance December 31, 2001                                                 5,871,837          39,257,907
                   Revisions                                                             (125,468)         (4,959,229)
                   Extensions, discoveries and additions                                   22,129           1,090,024
                   Purchase                                                                52,480           1,090,025
                   Sales                                                                  (20,698)           (837,856)
                   Production                                                            (278,374)         (1,487,048)
                                                                                   ----------------    ----------------

              Balance December 31, 2002                                                 5,521,906          34,158,823
                   Revisions                                                             (262,608)           (308,080)
                   Extensions, discoveries and additions                                  -                   -
                   Purchase                                                               -                   -
                   Sales                                                                  -                   -
                   Production                                                            (221,335)         (1,190,624
                                                                                   ----------------    ----------------

              Balance December 31, 2003                                                 5,037,963          32,660,119
                                                                                   ================    ================

         PROVED DEVELOPED RESERVES:
              December 31, 2001                                                         3,939,593          21,203,989
                                                                                   ================    ================
              December 31, 2002                                                         4,025,552          25,374,113
                                                                                   ================    ================
              December 31, 2003                                                         3,772,926          24,642,407
                                                                                   ================    ================
                                      F-27

                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 11.  Oil and Gas Reserves Information (Unaudited) - continued

          STANDARDIZED MEASURE:

          Standardized  measure of discounted  future net cash flows relating to
          proved reserves:

                                                                  2003                  2002                 2001
                                                           -------------------    -----------------    -----------------
         Future cash inflows                               $     336,795,385      $  308,381,837        $ 199,162,921

         Future production and development costs
            Production                                           109,468,727         105,629,872           77,526,278
            Development                                           21,460,459          23,350,811           23,610,596
                                                           -------------------    -----------------    -----------------

         Future cash flows before income taxes                   205,866,199         179,401,154           98,026,047
         Future income taxes                                     (46,885,360)        (38,611,577)         (13,281,358)
                                                           -------------------    -----------------    -----------------

         Future net cash flows after income taxes                 158,980,839         140,789,577           84,744,689
         10% annual discount for estimated
           timing of cash flows                                   (70,653,419)        (63,165,742)         (35,895,306)
                                                           -------------------    -----------------    -----------------

         Standardized measure of discounted
           future net cash flows                           $       88,327,420     $    77,623,835      $    48,849,383
                                                           ===================    =================    =================

               The following  reconciles the change in the standardized  measure
          of discounted future net cash flows:

         Beginning of year                                 $       77,623,835     $    48,849,383      $    90,381,127

         Changes from:
            Purchases                                              -                    3,054,793           27,032,359
            Sales                                                  -                     (953,159)            (443,324)
            Extensions, discoveries and improved
             recovery, less related costs                          -                    2,002,176              427,192
            Sales of oil and gas produced net of
                production costs                                  (5,316,619)          (5,016,964)          (7,270,603)
            Revision of quantity estimates                        (3,751,921)          (9,974,557)          (1,783,276)
            Accretion of discount                                  9,889,881            5,649,945           12,414,073
            Change in income taxes                                (4,793,281)         (13,624,917)          26,109,535
            Changes in estimated future
                development costs                                  2,003,801           (5,254,561)          (6,360,990)
            Development costs incurred that
                reduced future development costs                   2,024,663            5,569,881            5,945,369
            Change in sales and transfer prices,
                net of production costs                           16,470,113           46,903,282          (89,573,528)
            Changes in production rates (timing)
                and other                                         (5,823,052)             418,533           (8,028,551)
                                                           -------------------    -----------------    -----------------
          End of year                                      $      88,327,420      $    77,623,835      $    48,849,383
                                                           ===================    =================    =================
                                      F-28

                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 12.  Quarterly Results (Unaudited)

               Summary  data  relating  to the  results of  operations  for each
          quarter for the years ended December 31, 2003 and 2002 follows:

                                                                        Three Months Ended
                                            ----------------------------------------------------------------------------
                                               March 31             June 30          September 30         December 31
                                            ----------------    ----------------    ----------------    ----------------
         2003
              Net sales                     $    3,250,603      $    2,790,124      $    2,436,063      $    2,533,933
              Gross profit                         862,683             406,576              81,573            (433,321)
              Net income (loss)                    120,659          (1,231,883)           (399,457)         (1,640,828)
              Income (loss) per common
                 share - basic and diluted  $          .01      $         (.07)     $         (.02)     $         (.09)

         2002
              Net sales                     $    2,648,873      $    2,951,798      $    2,641,626      $    2,597,500
              Gross profit                         239,912             450,255             100,527             136,961
              Net income (loss)                 (1,964,010)           (305,060)           (924,750)         (1,420,993)
              Income (loss) per common
                 share - basic and diluted  $        (0.11)     $        (0.02)     $        (0.05)     $        (0.07)
                                      F-29


                          INDEPENDENT AUDITOR'S REPORT










    Stockholders and Board of Directors
    GULFWEST ENERGY INC.


     Our report on the consolidated financial statements of GulfWest Energy Inc.
     and Subsidiaries as of December 31, 2003 and 2002 and for each of the three
     years in the period ended  December  31, 2003,  is included on page F-1. In
     connection with our audit of such  consolidated  financial  statements,  we
     have also audited the related  financial  statement  schedule for the years
     ended December 31, 2003, 2002 and 2001 on page F-31.

     In our opinion,  the financial  statement  schedule referred to above, when
     considered in relation to the basic consolidated financial statements taken
     as a whole,  presents  fairly,  in all material  respects,  the information
     required to be included therein.




    \s\ WEAVER AND TIDWELL, L.L.P.
    ---------------------------------
    WEAVER AND TIDWELL, L.L.P.

    Dallas, Texas
    March 19, 2004









                                      F-30

                      GULFWEST ENERGY INC. AND SUBSIDIARIES
                 SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
              FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001

                                             BALANCE                                                       BALANCE
                                               AT                                                            AT
                                            BEGINNING          PROVISIONS/          RECOVERIES/              END
DECRIPTION                                  OF PERIOD           ADDITIONS            DEDUCTIONS           OF PERIOD
- -------------------------------------    ----------------    -----------------    -----------------     --------------
For the year ended

     December 31, 2001

       Accounts and notes receivable
               related parties           $      740,478      $                    $                     $     740,478
                                         ================    =================    =================     ==============

       Valuation allowance for
               deferred tax assets       $    5,014,451      $      (345,754)     $                     $   4,668,697
                                         ================    =================    =================     ==============

For the year ended

     December 31, 2002

       Accounts and notes receivable
               related parties           $      740,478      $                    $     (740,478)       $
                                         ================    =================    =================     ==============

       Valuation allowance for
               deferred tax assets       $    4,668,697      $     1,586,988      $                     $   6,255,685
                                         ================    =================    =================     ==============

For the year ended

     December 31, 2003

       Valuation allowance for
               deferred tax assets       $    6,255,685      $       934,422      $                     $   7,190,107
                                         ================    =================    =================     ==============
                                      F-31