SECURITIES AND EXCHANGE COMMISSION
                              WASHINGTON, DC 20549

                                   FORM 10-KSB

Mark One:
         [X] Annual Report pursuant to Section 13 or 15(d) of the Securities
             Exchange Act of 1934. For the fiscal year ended 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 NO. 0-18956

                       AMERICAN NATURAL ENERGY CORPORATION
--------------------------------------------------------------------------------
                 (Name of Small Business Issuer in its Charter)

            OKLAHOMA                                      73-1605215
 -------------------------------                        ---------------
 (State or Other Jurisdiction of                         (IRS Employer
  Incorporation or Organization)                       Identification No.)

                7030 SOUTH YALE, SUITE 404, TULSA, OKLAHOMA 74136
               ----------------------------------------------------
               (Address of Principal Executive Offices) (Zip Code)

                                  918-481-1440
               ----------------------------------------------------
                (Issuer's Telephone Number, Including Area Code)

         Securities registered under Section 12(b) of the Exchange Act:
Title of Each Class                    Name of Each Exchange on Which Registered
--------------------------------------------------------------------------------
                                      None

      Securities Registered Pursuant to Section 12(g) of the Exchange Act:
      --------------------------------------------------------------------
                     Common Stock, par value $.01 per share
                              (Title of Each Class)

         Check whether the Issuer (1) filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act during the past twelve (12) months (or
for such shorter period that the Issuer was required to file such reports), and
(2) has been subject to such filing requirements for the past 90 days. [X] Yes
[ ] No

         Check if there is no disclosure of delinquent filers in response to
Item 405 of Regulation S-B in this form, and no disclosure will be contained, to
the best of Issuer's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-KSB, or any amendment to
this Form 10-KSB. [X]

         State Issuer's revenues for its most recent fiscal year:  $1,747,162.

         The aggregate market value of the voting and non-voting common equity
held by non-affiliates computed by reference to the price at which the common
equity was sold, or the average bid and asked prices of such common equity, as
of March 19, 2004, was $0.41. (Non-affiliates have been determined on the basis
of holdings set forth in Item 11 of this Annual Report on Form 10-KSB.)

         The number of shares outstanding of each of the Issuer's classes of
common equity, as of March 19, 2004, was 26,154,546.

                       DOCUMENTS INCORPORATED BY REFERENCE
                                      None

<PAGE>

                                TABLE OF CONTENTS

                                     PART I                                 Page
                                     ------                                 ----

Item 1.    Description of Business .........................................  3

Item 2.    Description of Property ......................................... 19

Item 3.    Legal Proceedings ............................................... 19

Item 4.    Submission of Matters to a Vote of Security Holders.............. 20

                                     PART II

Item 5.    Market for Common Equity, Related Stockholder Matters and
           Small Business Issuer Purchases of Equity Securities............. 21

Item 6.    Management's Discussion and Analysis or Plan of Operation........ 24

Item 7.    Financial Statements............................................. 44

Item 8.    Changes In and Disagreements With Accountants On Accounting...... 45
           and Financial Disclosure

                                    PART III

Item 9.    Directors, Executive Officers, Promoters and Control
           Persons; Compliance with Section 16(a) of the Exchange Act....... 46

Item 10.   Executive Compensation........................................... 48

Item 11.   Security Ownership of Certain Beneficial Owners and
           Management and Related Stockholder Matters....................... 50

Item 12.   Certain Relationships and Related Transactions................... 52

Item 13.   Exhibits and Reports on Form 8-K................................. 55

Item 14.   Controls and Procedures ......................................... 57

Item 15.   Principal Accountant Fees and Services........................... 58


                                        2

<PAGE>


                                     PART I
                                     ------

ITEM 1 - DESCRIPTION OF BUSINESS:
--------------------------------

         American Natural Energy Corporation is engaged in the acquisition,
development, exploitation and production of oil and natural gas. Prior to
December 31, 2001, our activities, conducted entirely through our predecessor,
Gothic Resources Inc., were not significant and involved very limited oil and
natural gas exploration in the southern United States. At that time, we also
invested in shares of other public oil and gas exploration companies resulting
in material capital gains. Since December 31, 2001, we have engaged in several
transactions which we believe will enhance our oil and natural gas development,
exploitation and production activities and our ability to finance further
activities. On December 31, 2001, we acquired the oil and natural gas and
related assets of Couba Operating Company ("Couba"), which prior to our
acquisition of it had commenced in March 2000 an involuntary Chapter 7
Bankruptcy proceeding which was converted to a Chapter 11 debtor in possession
proceeding the following month. On February 8, 2002, we completed a statutory
corporate reorganization which resulted in our domestication as a corporation
into the U.S. from Canada. Prior to that reorganization, our parent corporation
was a Canadian corporation. We are now an Oklahoma corporation.

         Commencing in the second half of 2002, we have engaged in a series of
financing transactions intended to enable us to initiate and pursue exploration
and development activities on the properties we have acquired. During 2002, we
were able to return to production five (4.06 net) well bores drilled by prior
owners on the Couba properties we acquired. Our drilling activities commenced in
February 2003 and as of December 31, 2003, we had drilled and completed six
(2.19 net) wells. By December 31, 2003, our combined production from all our
producing wells was approximately 400 (120 net) barrels of oil equivalent per
day. Production from our existing wells is subject to fluctuation from time to
time based upon the zones of the wells where we are obtaining production. All of
our drilling and production activities are conducted in St. Charles Parish,
Louisiana. We continue to need and seek material amounts of additional capital
to further our oil and natural gas development and exploitation activities.

         Unless the context otherwise requires, references to us in this Annual
Report includes American Natural Energy Corporation, an Oklahoma corporation,
and our wholly-owned subsidiary, Gothic Resources Inc., a corporation organized
under the Canada Business Corporation Act. References to Gothic refer
exclusively to our wholly-owned subsidiary, Gothic Resources Inc. and references
to ANEC refer exclusively to our parent corporation, American Natural Energy
Corporation, organized under the laws of Oklahoma. Through December 2001, our
activities were conducted through Gothic, and Gothic may be deemed a predecessor
of ANEC.


                                       3

<PAGE>


         THE LOUISIANA PROPERTIES

         On December 31, 2001, we acquired the assets and capital stock of
Couba. Couba, organized in 1993, was primarily engaged in the production of oil
from properties located in St. Charles Parish, Louisiana. Couba's principal
acreage is the Bayou Couba Lease under which Couba owned a 72% working interest
in 1,319.991 gross acres. Production from the wells commenced in 1941 and only
oil and non-commercial quantities of natural gas were produced. Natural gas has
never been produced in commercial quantities, and all gas production wells from
the original development of the property were plugged.

         In early 2000, Couba had depleted its borrowing availability under a
bank line of credit and had insufficient capital to continue in operations. On
March 14, 2000, an involuntary Chapter 7 Bankruptcy Petition was filed against
Couba in the United States Bankruptcy Court for the Western District of
Oklahoma. In April, 2000, the case was converted to a Chapter 11 debtor in
possession proceeding. During the pendency of the proceeding, Couba maintained
nominal production from four wells on the Bayou Couba Lease in order to maintain
in effect the lease to the property.

         On May 1, 2001, we joined with Couba in submitting to the Bankruptcy
Court a plan of reorganization whereby we would acquire substantially all the
assets and capital stock of Couba. Couba's only assets at the time were its
physical oil and gas facilities and it had no other business activities,
employees, customers or rights. The plan, as finally confirmed by the Court on
November 16, 2001 and, as it became effective on December 31, 2001, provided for
the following:

o        we acquired substantially all the assets of Couba and its outstanding
         capital stock,

o        we paid approximately $2.1 million in cash,

o        we assumed approximately $3.8 million of senior secured bank debt. On
         March 12, 2003, the final documentation relating to this indebtedness
         was executed with the lender. Concurrently with executing the loan
         documentation, we repaid $2.25 million of principal and interest and,
         as of that date, there remained owing approximately $1.7 million. The
         remaining indebtedness was repaid with proceeds from the sale of
         convertible secured debentures we issued in October 2003.

o        we assumed $204,000 of other additional secured liabilities of Couba,

o        we agreed that the holders of unsecured claims aggregating
         approximately $4.9 million, plus interest accruing at 8% per annum
         commencing January 1, 2002, would receive payment of 100% of their
         allowed claims out of an overriding royalty interest in the amount of
         3% of the production from existing and new wells on the Bayou Couba
         Lease. In addition, such claims are to be paid out of a net profits
         interest granted to the creditors whereby such creditors are allocated
         50% of the net profits from production from the workover of wells
         existing on December 31, 2001 on the Bayou Couba Lease , 15% of the net
         profits from production from the drilling after December 31, 2001 of
         new wells on the Bayou


                                       4

<PAGE>

         Couba Lease and 6% of the net profits from production from the drilling
         after December 31, 2001 of new wells on a 23.5 square mile area of
         mutual interest, excluding, however, the Bayou Couba Lease. Upon
         payment of their allowed claims, inclusive of interest, such royalty
         and net profits interests terminate.

o        we agreed that, after repayment to us of 200% of all costs of
         bankruptcy, drilling, development and field operations from net
         revenues of the Bayou Couba Lease and the 23.5 square mile area of
         mutual interest, including payments we made to all creditors of all
         classes under the plan, the former holders of equity securities of
         Couba will be entitled to a working interest in the wells in the Bayou
         Couba Lease equal to 25% of the working interest obtained by us
         directly from Couba at the time of confirmation and as a result of the
         plan of reorganization of Couba and a 25% interest in our interest in
         the 23.5 square mile area of mutual interest held by us on the
         effective date of the plan, excluding, however, a 25% interest in the
         area of mutual interest held by Wiser Oil Company.

The principal asset of Couba we acquired was the Bayou Couba Lease. The lessor
is Exxon-Mobil Corp. and the lease is held by production of oil and gas on the
property. We further agreed as part of the plan to expend up to $1.1 million to
restore existing wells on the property to production, which we had expended as
of the end of the third quarter of 2002, and to evaluate the advisability of
drilling new wells.

         In addition, the Couba assets we acquired include a gathering system
covering approximately 25 miles located on the Bayou Couba Lease, used solely as
a production collection system among the wells on the leased property leading to
a product distribution point, and various production facilities, geological
data, well logs and production information. The information includes 3-D seismic
information completed in 1997. The seismic information relates to an area of
approximately 23.5 square miles that includes the Bayou Couba Lease, among other
acreage. The gathering system we acquired was initially not in operable
condition. Subsequently, as part of the approximately $1.1 million we expended
to restore existing wells to production we refurbished and upgraded the system
so as to be usable. At present the system, which consists of flow lines,
connections and related facilities, is used to transport our production of oil
and gas to points where it is trans-shipped and sold.

         A portion of the 23.5 square mile area, which excludes the Bayou Couba
Lease acreage, is the subject of a further area of mutual interest agreement
with Wiser Oil Company, a non-affiliated party, whereby we are entitled to a
minimum interest of 75% in any acreage acquired by either party in the area, and
we and the other party bear our proportionate share of the costs of developing
the area. Wiser Oil Company has certain licensing rights with respect to our 3-D
seismic information and is entitled to receive copies of the information. The
agreement is in effect for five years and terminates on December 31, 2006.

         In February 2002, we leased 1,729 acres from the State of Louisiana
giving us in excess of an aggregate of approximately 3,000 net acres under lease
at December 31, 2002, all within the boundaries of the proprietary 3-D seismic
data. Wiser Oil Company


                                       5

<PAGE>

elected not to participate in the development of the acreage that is the subject
of the lease with the State of Louisiana.

         In November 2002, we entered into a four-year joint development
agreement with ExxonMobil Corp. relating to both our Couba properties and
additional properties owned by ExxonMobil Corp. In December 2003 we entered into
an amendment to that agreement. The agreement, as amended, creates an area of
mutual interest ("AMI") covering approximately 11,000 acres, all within the 23.5
square mile 3-D seismic area and calls for both parties to make available for
development, leases and/or mineral interests each owns within the AMI. The
December 2003 amendment (the "Expansion Agreement") expanded the AMI by 2,560
acres, to a depth of 14,000 feet in the additional acreage, subject to us
drilling two wells on the property to depths of 8,000 and 7,700 feet,
respectively. The first well has been drilled and was plugged after reaching
total depth. The second well reached the minimum depth requirement as of
February 12, 2004, completing all conditions of the Expansion Agreement. The
second well has been temporarily abandoned after we encountered mechanical
problems in removing the drilling tools after reaching a total depth of
approximately 11,500 feet. We are evaluating whether to reenter or re-drill the
well and anticipate recovery of the cost of lost drilling tools and our drilling
expenses to be covered by our insurance policy. In addition, the Expansion
Agreement extended the term of the AMI by an additional year to a term of five
years ending November 2007. In exchange, ExxonMobil Corp. received a carried
interest, whereby we pay the drilling expenses incurred, in the two wells to the
point at which a determination is to be made whether or not to complete the
well, after which if ExxonMobil Corp. elects to participate in the completion of
the well, it will receive a 50% working interest or a 25% royalty interest in
the wells. Under the agreement, both parties may propose wells for drilling and
the non-proposing party may elect whether or not to participate, with that
election affecting only the proposed location. If both parties elect to
participate in the proposed well, the interest in the well is shared equally.
Each party is responsible for its share of costs to develop the acreage within
the AMI. Operations of the wells are at the election of the ExxonMobil Corp. but
we anticipate that we will drill and operate most wells within the AMI.

         In March 2003, we assigned a 10% participation interest in the Bayou
Couba Lease, our lease with the State of Louisiana and the ExxonMobil Corp. AMI
to Trans-Atlantic Petroleum Corp. in partial consideration for a $2.0 million
financing. This agreement, which has a term of four years or the expiration of
the agreement with ExxonMobil Corp., whichever is longer, grants to
TransAtlantic the right to acquire a 10% interest in any property we acquire in
the 23.5 square mile area, including any property interests acquired through our
agreement with ExxonMobil Corp. TransAtlantic is engaged in the exploration,
development and production of crude oil and natural gas in Nigeria and the
United States. As a consequence of shares it received in consideration for a
loan it made to us (176,128 shares) and its purchase of $3.0 million principal
amount of our convertible secured debentures in October 2003 (convertible to
6,666,667 shares), it is also the beneficial holder of 6,842,795 shares of our
common stock. Mr. John J. Fleming, who became a Director of our company
immediately following the transaction, was also the President and a Director of
TransAtlantic at the time.


                                       6

<PAGE>

         FEBRUARY 2002 CORPORATE REORGANIZATION

         On February 8, 2002, we completed a corporate reorganization. At a
meeting held on January 18, 2002, the stockholders of Gothic approved an
arrangement under Section 192 of the Canada Business Corporations Act whereby
the stockholders of Gothic voted to exchange all their common shares for our
shares. The effect of the reorganization was that Gothic, which had formerly
been our parent corporation, became our wholly-owned subsidiary. The
stockholders of Gothic tendered their share certificates and received a like
number of our shares. All outstanding warrants and options to purchase shares of
Gothic now represent the right to purchase our shares on substantially the
identical terms and conditions. The shares of Gothic are no longer listed on the
TSX Venture Exchange and in their place, our shares are now listed on that
exchange, quoted and traded in U.S. dollars under the symbol ANR.U.

         Upon petition of Gothic, the Supreme Court of British Columbia, at a
hearing held on January 22, 2002, considered the fairness of the terms and
conditions of the reorganization. All the security holders of Gothic were mailed
a notice dated December 19, 2001 of the hearing and had the opportunity to
appear. Upon finding that the terms of the transaction were fair, both
procedurally and substantively, to the security holders of Gothic, the Court
entered an order approving the reorganization pursuant to the provisions of
Section 192 of the Canada Business Corporations Act. The British Columbia Court
was advised by Gothic in the petition presented to the Court before the hearing
that we would rely on the exemption from the registration requirements of the
Securities Act of 1933, as amended, contained in Section 3(a)(10) thereof in
issuing our shares in exchange for the shares of Gothic.

         The purpose for the reorganization was to permit us to continue our
business and operations, all of which are located in the U.S, as a U.S.
corporation incorporated in Oklahoma. Our Board of Directors believes that the
use of a U.S. corporation whose securities are registered with the U.S.
Securities and Exchange Commission (the "SEC") will provide us with a platform
to stimulate and increase U.S. market interest in us and facilitate our ability
to raise capital in the U.S. and elsewhere in the world.

         At the same meeting, the Gothic stockholders approved the adoption of
our 2001 Stock Incentive Plan whereby, among other things, 5,000,000 shares of
our common stock were reserved for the issuance of options granted under the
plan. The stockholders also approved a reduction, pursuant to the Canadian
Business Corporation Act, of Gothic's stated capital. The reduction in stated
capital, which was a necessary condition under Canadian law to the completion of
the reorganization, did not result in the cancellation or change in the number
of shares of Gothic outstanding. The reduction in the stated capital, which
amounted to approximately $2.0 million, resulted in the elimination of the
accumulated deficit.

         Our officers and Directors remained unchanged after the reorganization
and it had no effect on the relative holdings of our stockholders. One of our
shares was authorized to be issued in exchange for each share of Gothic. No cash
was issued in the transaction


                                       7

<PAGE>

except stockholders who perfected their dissenters' rights in accordance with
Canadian law were entitled to receive cash. No stockholders perfected their
dissenters rights.

         Through December 2001, our activities were conducted through Gothic and
Gothic may be deemed our predecessor.

         OTHER ACTIVITIES

         As of September 30, 2002, we owned leasehold interests in approximately
33,185 gross (10,289 net) acres in eastern Oklahoma with 4 gross (3.5 net) wells
which were not producing. The leases are located in the Arkoma Basin. This area
is believed to contain coalbed methane prospects for the production of natural
gas. In October 2002, we sold these Oklahoma leasehold interests for $1.003
million, subject to post closing adjustments, to a non-affiliated purchaser. We
recorded loss from this transaction in the amount of $726,348 in 2002 and a gain
resulting from post-closing adjustments in 2003 of $43,937.

         At December 31, 2001, we held an aggregate of 7,870,419 shares of First
Calgary Petroleum Ltd., an oil and gas exploration and development company
listed on The Toronto Stock Exchange. We had acquired 7,918,919 of these shares
on conversion in November 1999 of a loan in the amount of $2.0 million we made
to First Calgary in December 1997. In January 2002, we sold all 7,870,419 shares
for net proceeds of $2.3 million. Separately from the foregoing, we also
exercised for $163,000 warrants for the purchase of 400,000 shares of First
Calgary stock. These shares were sold in December 2002 for $335,000 and in
January and February 2003 for $208,000 for total proceeds of $543,000. First
Calgary is not an affiliate of ours.

OIL AND GAS RESERVES

         The tables below set forth information as of December 31, 2003 with
respect to our estimated proved reserves, our estimated future net revenue
therefrom and the present value thereof at such date based on the report of
Netherland, Sewell and Associates, Inc. The calculations which Netherland,
Sewell and Associates, Inc. used in preparation of such report were prepared
using geological and engineering methods generally accepted by the petroleum
industry and in accordance with SEC guidelines. All estimates were prepared
based upon a review of production histories and other geologic, economic,
ownership and engineering data we believe to be accurate. The present value of
estimated future net revenue shown is not intended to represent the current
market value of the estimated oil and gas reserves we own.


                                       8

<PAGE>



                                        OIL           GAS           TOTAL
                                       (MBbl)        (Mmcf)        (MBble)
                                       ------        ------        -------

Proved developed producing             24.85          1.89          25.16
Proved developed non-producing         86.09        210.54         121.18
Proved undeveloped                     68.61         60.04          78.62
Total proved                          179.55        272.47         224.96


                                          PROVED       PROVED        TOTAL
                                        DEVELOPED    UNDEVELOPED     PROVED

Estimated future net revenue(a)           $3,152,700   $1,213,100     $4,365,800
Present value of future net revenue(b)    $2,787,800   $  901,900     $3,689,700

           -----------------------
           (a)   Estimated future net revenue represents estimated future gross
           revenue to be generated from the production of proved reserves, net
           of estimated production and future development costs, using prices
           and costs in effect at December 31, 2003. The amounts shown do not
           give effect to non-property related expenses, such as general and
           administrative expenses, debt service and future income tax expense
           or to depreciation, depletion and amortization, but do give effect to
           net profits obligations arising out of agreements we made to acquire
           the Couba assets in the plan of reorganization. The prices used in
           these estimates were $29.25 per barrel of oil and $5.97 per Mmbtu of
           gas.

          (b)    Present value of future net revenues represents estimated
          future net revenues discounted using an annual discount rate of 10%.

         Assuming that we expend approximately $1.1 million during 2004 and an
additional $78,000 in future periods to develop these reserves, the future net
revenue attributable to our estimated proved developed non-producing reserves
and proved undeveloped reserves would be calculated to be $3.99 million at
December 31, 2003, with the present value thereof to be $3.34 million. The
amount and timing of these expenditures will depend on a number of factors,
including actual drilling results, product prices and the availability of
capital to us. At December 31, 2003, the capital necessary to develop these
additional reserves was unavailable to us. Through December 31, 2003, we had
expended approximately $7.7 million for development of the Bayou Couba
properties.

         No estimates of proved reserves comparable to those included herein
have been included in reports to any federal agency other than the SEC.

         Our ownership interest used in calculating proved reserves and the
estimated future net revenue therefrom was determined after giving effect to the
assumed maximum participation by other parties to our farm-out and participation
agreements. There can be no assurance that all of the estimated proved reserves
will be produced and sold at the assumed prices or that existing contracts will
be honored or judicially enforced.

         There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond our control. Reserve
engineering is a subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact way, and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment.


                                       9

<PAGE>

As a result, estimates made by different engineers often vary. In addition,
results of drilling, testing and production subsequent to the date of an
estimate may justify revision of such estimates, and such revisions may be
material. Accordingly, reserve estimates are often different from the actual
quantities of oil and gas that are ultimately recovered. Furthermore, the
estimated future net revenue from proved reserves and the present value thereof
are based upon certain assumptions, including prices, future production levels
and costs that may not prove correct. Fluctuations in commodities prices will
impact the economic viability of the production of oil and gas. Predictions
about prices and future production levels are subject to great uncertainty, and
the foregoing uncertainties are particularly true as to proved undeveloped
reserves, which are inherently less certain than proved developed reserves.
Accordingly, our existing claimed reserves and any reserves we may discover in
the future are and will be subject to these uncertainties.

         The primary area of our operations is St. Charles Parish, Louisiana. As
of December 31, 2003, all of our operations and reserves are located in that
area.

DRILLING ACTIVITY

         The following table sets forth information as to the wells we completed
during the periods indicated. In the table, "gross" refers to the total wells in
which we have a working interest and "net" refers to gross wells multiplied by
our working interest therein.

                                    YEAR ENDED DECEMBER 31,
                             2001         2002(1)(2)           2003
                        Gross    Net    Gross     Net     Gross      Net
Development
  Productive             -0-     -0-     -0-      -0-      5.0      1.56
  Non-productive         -0-     -0-     -0-      -0-      -0-       -0-
Exploratory
  Productive             -0-     -0-     4.0      3.5      1.0      0.63
  Non-productive         -0-     -0-     -0-      -0-      1.0      0.35

(1)  Wells drilled on leasehold interests owned in eastern Oklahoma which were
     sold in October 2002

(2)  Excludes 5 (4.06 net) wells drilled by prior owners on the Bayou Couba
     properties which we returned to production during 2002.

PRESENT ACTIVITIES

         In July 2002, we completed the restoration activities on the Bayou
Couba Lease and brought the operation into compliance with applicable regulatory
requirements. We also completed reprocessing the 3-D seismic information we
acquired as part of the Couba transaction and we are continuing to review that
data. We also were able to get five well bores on the Bayou Couba lease that had
been drilled by the former owners into a producing condition.


                                       10

<PAGE>

         Our activities in 2002 also included refurbishing the gathering line
connected to the wells. This gathering line delivers our current production of
natural gas to the Transco pipeline for further delivery to an interstate
pipeline.

         In February 2003, we commenced drilling on the Bayou Couba Lease and by
December 31, 2003, we had drilled and completed 6 (2.19 net) wells on the
property. At December 31, 2003, combined production from all our producing wells
on the property was approximately 400 (120 net) barrels of oil equivalents per
day. Production from our existing wells is subject to fluctuation from time to
time based upon the zones of the wells where we are obtaining production. One
well drilled during 2003 was unsuccessful and was plugged.

         Our drilling plans for 2004 include the re-completion of two wells
drilled in the second quarter of 2003, the drilling of the second well required
pursuant to the ExxonMobil Expansion Agreement and additional drilling within
the boundaries of the AMI, subject to capital then being available. The second
well required pursuant to the ExxonMobil Expansion Agreement was drilled to the
depth required to meet the conditions of the Expansion Agreement but was
temporarily abandoned after we encountered mechanical problems in removing the
drilling tools after reaching a total depth of approximately 11,500 feet. We are
evaluating whether to re-enter or re-drill the well. We anticipate the cost of
the lost drilling tools and our drilling expenses in re-entering or re-drilling
the well to be covered by our insurance policy.

         A "development well" is defined as a well drilled within a proved area
of an oil or gas reservoir to a depth of a strategaphic horizon known to be
productive. An "exploratory well" is a well drilled to find and produce oil or
gas in an unproved area, to find a new reservoir in a field previously found to
be productive of oil or gas in another reservoir, or to extend a known
reservoir.

PRODUCTIVE WELL DATA INFORMATION

         The following table sets forth the interests we own in productive wells
as of December 31, 2003.

                                 AREA                  WELL COUNT
                                 ----                  ----------
                                                    GROSS(1)   NET(1)
                                                    --------   ------
          St. Charles Parish, Louisiana                11       6.25

         ---------------------
         (1)   All of such wells have been classified as primarily oil producing
               wells.

PRODUCTION VOLUMES, REVENUE, PRICES AND PRODUCTION COSTS

         The following table sets forth certain information regarding the
production volumes, revenue, average prices received and average production
costs associated with our sale of oil and natural gas for the two years ended
December 31, 2003. We had no


                                       11

<PAGE>

material production of oil and natural gas in the year ended December 31, 2001.
All of our production was from our properties located in St. Charles Parish,
Louisiana.

                                              Year Ended December 31,
                                       ----------------------------------------
                                       2003              2002              2001
                                       ----              ----              ----
Net Production(1)
   Oil (Mbbl)                            50.3             11.9                --
   Natural Gas
   (Mmcf)                                 6.2             13.1                --
   Oil Equivalent
   (Mbble)                               51.3             14.1                --

Oil and Natural

Gas Sales:
   Oil                            $ 1,666,865      $   274,803                --
   Natural Gas                    $    32,127      $    33,711                --
   Total                          $ 1,698,992      $   308,514                --

Average Sales
Price:
   Oil ($per Bbl)                 $     33.17      $     23.07                --
   Natural Gas
     ($per  Mcf)                  $      5.18      $      2.58                --
   Oil Equivalent
     ($per Bble)                  $     33.13      $     21.90                --

Oil and Natural
     Gas Costs:
   Lease operating
     expenses                     $   495,409      $   481,711                --
   Production Taxes               $    66,807      $    11,115                --

   Net gain (loss)
     from sale of
     oil and
     natural gas
     properties                   $    43,937      ($  726,348)               --

   Impairment of
     oil and
     natural gas
     properties                   $   653,886      $ 6,476,993       $   572,705

Depreciation,
     depletion and
     amortization                 $   919,628      $   410,050                --

Average
   production cost
   per unit of
   production                     $     10.96      $     34.19                --

1)   Includes only production owned by us and produced to our interest, less
     royalties and production due others. 468 and 1,638 barrels of oil were
     produced in December 2003 and 2002 but not sold until January 2004 and
     2003, respectively, and are included in inventory at December 31, 2003 and
     2002 at the lower of production cost and DD&A, or market.

DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES

         The following table sets forth certain information regarding the costs
we incurred


                                       12

<PAGE>

in our development, exploration and acquisition activities during the periods
indicated:

                                Year Ended        Year Ended         Year Ended
                               December 31,      December 31,       December 31,
                                   2001             2002               2003
                              ------------      ------------        ------------
Development Costs              $        --      $   681,102       $ 2,953,794
Exploration Costs              $   364,867      $ 2,842,783       $ 1,331,286
Acquisition Costs(1)           $ 7,728,164      $   535,680       $   262,130
Sales of Oil and Gas
   Properties                         --        $(1,667,581)      $  (618,855)

Capitalized Interest                  --        $   275,857       $   712,829
                               -----------      -----------       -----------
Total                          $ 8,093,031      $ 2,667,841       $ 4,641,184

(1)  Acquisition costs exclude asset retirement costs of $430,000 upon
     implementation of SFAS 143 as of January 1, 2003.

ACREAGE

         The following table sets forth as of December 31, 2003, the gross and
net acres of both developed and undeveloped oil and natural gas leases which we
hold. "Gross" acres are the total number of acres in which we own a working
interest. "Net" acres refer to gross acres multiplied by our fractional working
interest.

                                                        Total Developed and
                  Developed(1)       Undeveloped(1)         Undeveloped
                  ------------       --------------         -----------
       Area      Gross     Net      Gross      Net        Gross       Net
       ----      -----     ---      -----      ---        -----       ---
Louisiana        1,320    1,072     1,912      1,554      3,232     2,626
Total            1,320    1,072     1,912      1,554      3,232     2,626

(1)       Net acreage assumes that we maintain our existing working interest
          percentage in all future development. An election by ExxonMobil to
          participate in our acreage pursuant to the ExxonMobil joint
          development agreement we entered into in November 2002 will reduce our
          net owned acreage position. Our participation in ExxonMobil acreage
          under that agreement will serve to increase our net acreage position.
          At December 31, 2003, ExxonMobil was providing 3,240 gross acres to
          the joint development agreement area. As the agreement was amended in
          December 2003, ExxonMobil agreed to provide an additional 2,560 gross
          acres (to a depth of 14,000 feet) to the joint development agreement.

MARKETING

         Our oil production is sold under market sensitive or spot price
contracts. Our natural gas production is sold to purchasers under varying
percentage-of-proceeds and percentage-of-index contracts or by direct marketing
to end users or aggregators. By the terms of the percentage-of-proceeds
contracts, we receive a percentage of the resale price received by the purchaser
for sales of residue gas and natural gas liquids recovered after gathering and
processing our gas. The residue gas and natural gas liquids sold by these
purchasers are sold primarily based on spot market prices. The revenue we
received from the sale of natural gas liquids is included in natural gas sales.
During 2003, our oil sales to Teppco Crude Oil, L.P. of $1,666,865 accounted for
98% of our total oil and gas sales. We believe we are not materially dependent
upon Teppco for our sales inasmuch as we believe there are numerous other
purchasers for our oil production at competitive prices. Our gas sales to
Transcontinental Pipeline Corporation of $32,127 accounted for 2% of


                                       13

<PAGE>

our total oil and gas sales. We believe that the loss of these customers would
not have a material adverse effect on our results of operations or our financial
position.

         We have no obligations to provide fixed or determinable quantities of
oil or natural gas in the future under existing contracts or agreements.

HEDGING ACTIVITIES

         We have not utilized hedging strategies to hedge the price of our
future oil and gas production or to manage our fixed interest rate exposure.

COMPETITION

         The oil and natural gas industry is highly competitive in all of its
phases. We are not a significant factor in the overall production of oil and
natural gas. We encounter competition from other oil and natural gas companies
in all areas of our operations, including the marketing of oil and natural gas
and the acquisition of producing properties. Most all of these companies possess
greater financial and other resources than we do. Because gathering systems are
the only practical method for the intermediate transportation of natural gas,
competition is presented by other pipelines and gas gathering systems. Because
oil and natural gas is sold as a commodity, pricing is not a factor in our
competition. Competition may also be presented by alternative fuel sources,
including heating oil and other fossil fuels. Because the primary markets for
natural gas liquids are refineries, petrochemical plants and fuel distributors,
prices are generally set by or in competition with the prices for refined
products in the petrochemical, fuel and motor gasoline markets.

REGULATION

         General

         Numerous departments and agencies, federal, state and local, issue
rules and regulations binding on the oil and gas industry, some of which carry
substantial penalties for failure to comply. The regulatory burden on the oil
and gas industry increases our cost of doing business and, consequently, affects
our profitability. At December 31, 2003, we are unable to estimate the costs to
be incurred for compliance with environmental laws over the next twelve months,
however, management believes all such costs will be those ordinarily and
customarily incurred in the development and production of oil and gas and that
no unusual costs will be encountered.

         Exploration and Production

         Our operations are subject to various types of regulation at the
federal, state and local levels. Such regulation includes requiring permits for
the drilling of wells, maintaining bonding requirements in order to drill or
operate wells and regulating the location of wells, the method of drilling and
casing wells, the surface use and restoration of properties upon which wells are
drilled, the plugging and abandoning of wells and the


                                       14

<PAGE>

disposal of fluids used or obtained in connection with operations. Our
operations are also subject to various conservation regulations. These include
the regulation of the size of drilling and spacing units and the density of
wells which may be drilled and the unitization or pooling of oil and gas
properties. In this regard, some states (such as Oklahoma) allow the forced
pooling or integration of tracts to facilitate exploration while other states
(such as California) rely on voluntary pooling of lands and leases. In areas
where pooling is voluntary, it may be more difficult to form units and,
therefore, more difficult to develop a prospect if the operator owns less than
100% of the leasehold. In addition, certain state conservation laws may
establish maximum rates of production from oil and gas wells, generally prohibit
the venting or flaring of gas and impose certain requirements regarding the
ratability of production. The effect of these regulations is to limit the amount
of oil and gas we can produce from our wells and to limit the number of wells or
the locations at which we can drill. The extent of any impact on us of such
restrictions cannot be predicted.

         Environmental and Occupational Regulation

         General. Our activities are subject to existing federal, state and
local laws and regulations governing environmental quality and pollution
control. It is anticipated that, absent the occurrence of an extraordinary
event, compliance with existing federal, state and local laws, rules and
regulations concerning the protection of the environment and human health will
not have a material effect upon our operations, capital expenditures, earnings
or competitive position. We cannot predict what effect additional regulation or
legislation, enforcement policies thereunder and claims for damages for injuries
to property, employees, other persons and the environment resulting from our
operations could have on our activities.

         Our activities with respect to exploration, development and production
of oil and natural gas are subject to stringent environmental regulation by
state and federal authorities including the United States Environmental
Protection Agency ("EPA"). Such regulation has increased the cost of planning,
designing, drilling, operating and in some instances, abandoning wells. In most
instances, the regulatory requirements relate to the handling and disposal of
drilling and production waste products and waste created by water and air
pollution control procedures. Although we believe that compliance with
environmental regulations will not have a material adverse effect on our
operations or earnings, risks of substantial costs and liabilities are inherent
in oil and gas operations, and there can be no assurance that significant costs
and liabilities, including criminal penalties, will not be incurred. Moreover,
it is possible that other developments, such as stricter environmental laws and
regulations, and claims for damages for injuries to property or persons
resulting from our operations could result in substantial costs and liabilities.

         Waste Disposal. We currently own or lease, and have owned or leased,
numerous properties that for many years have been used for the exploration and
production of oil and gas. Although we believe operating and disposal practices
that were standard in the industry at the time were utilized, hydrocarbons or
other wastes may have been disposed of or released on or under the properties we
owned or leased or on or under other


                                       15

<PAGE>

locations where such wastes have been taken for disposal. In addition, these
properties may have been operated by third parties whose treatment and disposal
or release of hydrocarbons or other wastes was not under our control. State and
federal laws applicable to oil and natural gas wastes and properties have
gradually become more strict. Under such laws, we could be required to remove or
remediate previously disposed wastes (including wastes disposed of or released
by prior owners or operators) or property contamination (including groundwater
contamination) or to perform remedial plugging operations to prevent future
contamination.

         We generate wastes, including hazardous wastes, that are subject to the
Federal Resource Conservation and Recovery Act ("RCRA") and comparable state
statutes. The EPA and various state agencies have limited the disposal options
for certain hazardous and non-hazardous wastes and are considering the adoption
of stricter disposal standards for non-hazardous wastes. Furthermore, certain
wastes generated by our oil and natural gas operations that are currently exempt
from treatment as hazardous wastes may in the future be designated as hazardous
wastes, and therefore be subject to considerably more rigorous and costly
operating and disposal requirements.

          Superfund. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability,
without regard to fault or the legality of the original conduct, on certain
classes of persons with respect to the release of a "hazardous substance" into
the environment. These persons include the owner and operator of a site and
persons that disposed of or arranged for the disposal of the hazardous
substances found at a site. CERCLA also authorizes the EPA and, in some cases,
third parties to take actions in response to threats to the public health or the
environment and to seek to recover from responsible classes of persons the costs
of such action. In the course of our operations, we may generate wastes that
fall within CERCLA's definition of "hazardous substances". We may also be an
owner of sites on which "hazardous substances" have been released. We may be
responsible under CERCLA for all or part of the costs to clean up sites at which
such wastes have been released. To date, however, we have not and, to our
knowledge, our predecessors or successors have not been named a potentially
responsible party under CERCLA or similar state superfund laws affecting
property we owned or leased.

          Air Emissions. Our operations are subject to local, state and federal
regulations for the control of emissions of air pollution. Legal and regulatory
requirements in this area are increasing, and there can be no assurance that
significant costs and liabilities will not be incurred in the future as a result
of new regulatory developments. In particular, regulations promulgated under the
Clean Air Act Amendments of 1990 may impose additional compliance requirements
that could affect our operations. However, it is impossible to predict
accurately the effect, if any, of the Clean Air Act Amendments on us at this
time. We may in the future be subject to civil or administrative enforcement
actions for failure to comply strictly with air regulations or permits.

          These enforcement actions are generally resolved by payment of
monetary fines and correction of any identified deficiencies. Alternatively,
regulatory agencies could require us to forego construction or operation of
certain air emission sources.


                                       16

<PAGE>

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

          OPA and Clean Water Act. Federal regulations require certain owners or
operators of facilities that store or otherwise handle oil, such as us, to
prepare and implement spill prevention control plans, countermeasure plans and
facilities response plans relating to the possible discharge of oil into surface
waters. The Oil Pollution Act of 1990 ("OPA") amends certain provisions of the
federal Water Pollution Control Act of 1972, commonly referred to as the Clean
Water Act ("CWA"), and other statutes as they pertain to the prevention of and
response to oil spills into navigable waters. The OPA subjects owners of
facilities to strict joint and several liability for all containment and cleanup
costs and certain other damages arising from a spill, including, but not limited
to, the costs of responding to a release of oil to surface waters. The CWA
provides penalties for any discharges of petroleum products in reportable
quantities and imposes substantial liability for the costs of removing a spill.
State laws for the control of water pollution also provide varying civil and
criminal penalties and liabilities in the case of releases of petroleum or its
derivatives into surface waters or into the ground. Regulations are currently
being developed under OPA and state laws concerning oil pollution prevention and
other matters that may impose additional regulatory burdens on us. In addition,
the CWA and analogous state laws require permits to be obtained to authorize
discharges into surface waters or to construct facilities in wetland areas. The
EPA has adopted regulations concerning discharges of storm water runoff. This
program requires covered facilities to obtain individual permits, participate in
a group permit or seek coverage under an EPA general permit. We believe that we
are in material compliance with all permits we are required to obtain and
obtaining such permits in the future will not have a material adverse impact on
our operations in the future. With respect to our future operations, we believe
we will be able to obtain, or be included under, such permits, where necessary.
Compliance with such permits is not expected to have a material adverse effect
on us.

          NORM. Oil and gas exploration and production activities have been
identified as generators of concentrations of low-level naturally-occurring
radioactive materials ("NORM"). NORM regulations have been adopted in several
states. We are unable to estimate the effect of these regulations, although
based upon our preliminary analysis to date, we do not believe that our
compliance with such regulations will have a material adverse effect on our
operations or financial condition.

         Safe Drinking Water Act. Our operations may involve the disposal of
produced saltwater and other non-hazardous oilfield wastes by re-injection into
the subsurface. Under the Safe Drinking Water Act ("SDWA"), oil and gas
operators, such as us, must


                                       17

<PAGE>

obtain a permit for the construction and operation of underground Class II
injection wells. To protect against contamination of drinking water, periodic
mechanical integrity tests are often required to be performed by the well
operator. While we expect to be able to obtain all such permits as are required,
there can be no assurance that these requirements may not cause us to incur
additional expenses.

         Toxic Substances Control Act. The Toxic Substances Control Act ("TSCA")
was enacted to control the adverse effects of newly manufactured and existing
chemical substances. Under the TSCA, the EPA has issued specific rules and
regulations governing the use, labeling, maintenance, removal from service and
disposal of PCB items, such as transformers and capacitors used by oil and gas
companies. We may own such PCB items but do not believe compliance with TSCA
will have a material adverse effect on our operations or financial condition.

TITLE TO PROPERTIES

         Title to oil and gas properties is subject to royalty, overriding
royalty, carried, net profits, working and other similar interests and
contractual arrangements customary in the industry, to liens for current taxes
not yet due and to other encumbrances. As is customary in the industry in the
case of undeveloped properties, only cursory investigation of record title is
made at the time of acquisition. Drilling title opinions are usually prepared
before commencement of drilling operations. Although we have no basis to believe
that such will occur, there can be no assurance that our title to oil and gas
properties may not be challenged through legal proceedings.

OPERATING HAZARDS AND INSURANCE

         The oil and gas business involves a variety of operating risks,
including the risk of fire, explosions, blow-outs, pipe failure, abnormally
pressured formations and environmental hazards such as oil spills, gas leaks,
ruptures or discharges of toxic gases, the occurrence of any of which could
result in substantial losses to us due to injury or loss of life, severe damage
to or destruction of property, natural resources and equipment, pollution or
other environmental damage, clean-up responsibilities, regulatory investigation
and penalties and suspension of operations.

         We maintain an insurance policy that insures us against certain sudden
and accidental risks associated with drilling, completing and operating our
wells with coverage limits considered adequate by management. There can be no
assurance that this insurance will be adequate to cover any losses or exposure
to liability. We also carry comprehensive general liability policies and
workers' compensation insurance. While we believe these policies are customary
in the industry, they do not provide complete coverage against all operating
risks.

PREVIOUS BUSINESS

         Through December 31, 2001, our primary business was limited oil and gas
exploration and development activities in the southern United States and
acquiring


                                       18

<PAGE>

certain other oil and gas investments. During the three years ended December 31,
2001, we engaged in drilling two exploratory wells, one at West Cameron 18,
offshore Louisiana and the second at South Fort Stockton, Texas, both of which
were nonproductive. We were not the operator of either of these wells.

         Prior to engaging in the oil and gas business, we engaged in mineral
exploration.

EMPLOYEES

         As of December 31, 2003, we employed five persons, of which two were
executive officers and three were operations personnel. We outsource our
accounting function, field pumping operations and TSX Venture Exchange
administration. We do not employ a significant number of temporary employees.
None of our employees is represented by a labor union, and we believe our
relationship with our employees is good.

ORGANIZATION

         We are an Oklahoma corporation organized in January 2001. In June 2001,
we became a wholly-owned subsidiary of Gothic. In January 2002, as a result of
an arrangement under Section 192 of the Canada Business Corporations Act and an
order of the Supreme Court of British Columbia, we became the parent corporation
of Gothic and the holders of Gothic shares exchanged their shares for our
shares. Gothic may be deemed to be our predecessor.

OFFICES

         Our principal office is located at 7030 South Yale, Suite 404, Tulsa,
Oklahoma 74136. Additionally, we maintain office space in The Woodlands, Texas.
Our leased premises include approximately 6,472 square feet and are leased for
various terms expiring in 2004. The annual aggregate rental is $50,196. The
facilities are considered adequate for our present activities.

ITEM 2 - DESCRIPTION OF PROPERTY:
--------------------------------

         A description of our properties appears in Item 1 of this Annual Report
on Form 10-KSB.

ITEM 3 - LEGAL PROCEEDINGS:
--------------------------

                  On October 7, 2003, we were served with a Summons and
Complaint in litigation instituted against us by Wiser Oil Company in the United
States District Court for the Eastern District of Louisiana. In the litigation,
Wiser is seeking to have the Court determine, among other things, the rights and
obligations of the parties and to have the Court compel performance by us of
certain provisions and to stop us from taking certain other actions with respect
to matters allegedly arising under a Leasehold Acquisition and


                                       19

<PAGE>

Development Agreement entered into by us with Wiser in February 2002. The
matters relate to interpretations under the agreement of Wiser's rights to a 25%
participation in oil and gas interests acquired by us in an area of mutual
interest created by the agreement in return for a payment of 25% of the
acquisition cost. These interests relate to acreage outside our Bayou-Couba
Lease acreage in the area that is the subject of our joint development agreement
with Exxon/Mobil Corporation. Wiser is also seeking unspecified damages based on
allegations that we have not performed under the agreement in good faith. We
have filed an answer and counter-claim in the litigation and the parties are
engaged in discovery proceedings. We believe that we have good and meritorious
defenses in the litigation.

         No other legal proceedings are pending against us other than ordinary
litigation incidental to our business, the outcome of which we believe will not
have a material adverse effect on us.

ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS:
------------------------------------------------------------

         No matter was submitted during the fourth quarter of the year ended
December 31, 2003 to a vote of securityholders through the solicitation of
proxies or otherwise.


                                       20

<PAGE>


                                     PART II

ITEM 5 - MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND SMALL
------------------------------------------------------------------------
BUSINESS ISSUER PURCHASES OF EQUITY SECURITIES:
----------------------------------------------

         Our common shares are traded on the TSX Venture Exchange, Inc. under
the symbol ANR.U. Our common shares are not currently traded on any United
States stock exchange or in the over-the-counter market in the United States,
and, accordingly, there is currently no public market for our common shares in
the United States.

         The reported high and low sales prices for our common shares, as
reported by the TSX Venture Exchange, on a calendar quarterly basis for the most
recent two calendar years ended December 31, 2003 and through March 19, 2004
were as follows. The prices for our shares were traded in and reported by the
Exchange in Canadian dollars through February 11, 2002 and in United States
dollars during the period February 12, 2002 through the present.

                              PRICES
                              --------------------------------------------------
                              HIGH              LOW                SHARE VOLUME
                              --------------------------------------------------
         2002
                              (CDN)    (US)     (CDN)     (US)
First Quarter                 $0.77    $0.72    $0.57    $0.54     1,472,002 (1)
Second Quarter                --       $0.55    --       $0.32       957,001
Third Quarter                 --       $0.41    --       $0.25       809,980
Fourth Quarter                --       $0.54    --       $0.25     1,570,120
                              --------------------------------------------------
         2003
--------------------------------------------------------------------------------
                              (CDN)    (US)     (CDN)     (US)
First Quarter                 --       $0.83    --       $0.35     4,805,444
Second Quarter                --       $0.80    --       $0.35     1,088,354
Third Quarter                 --       $0.90    --       $0.41     4,296,356
Fourth Quarter                --       $1.20    --       $0.59     4,786,896
                              --------------------------------------------------
         2004
--------------------------------------------------------------------------------
First Quarter (through
March 19,)                    --       $1.15    --       $0.31     4,363,754


(1)  Includes share volume during the period February 12, 2002 through March 31,
     2002. Share volume prior to that date is no longer available.

         Current prices for our shares on the TSX Venture Exchange can be found
on the Internet at www.TSE-CDNX.com.

         As of January 30, 2004, we had 2,959 stockholders of record.


                                       21

<PAGE>


         We intend to seek to have a trading market for our common shares
develop in the United States. There can be no assurance that we will be
successful in this regard. We do not meet the requirements to have our common
shares included in any NASDAQ trading system or listed on any national
securities exchange. However, we do intend to seek to have our shares quoted on
the OTC Bulletin Board(R). In order to do so, a broker-dealer in securities in
the United States may be required to file with the National Association of
Securities Dealers, Inc. a notice that will enable the broker-dealer to enter
quotations for our common shares on the OTC Bulletin Board(R). There can be no
assurance that a broker-dealer will file such a notice or, if filed, that
quotations will be accepted on the OTC Bulletin Board(R). Further, there can be
no assurance that if a broker-dealer commences to enter bid and asked quotations
for our common shares in the OTC Bulletin Board(R) that a viable and active
trading market will develop.

DIVIDEND POLICY

         We do not intend to pay any dividends on our Common Stock for the
foreseeable future. Any determination as to the payment of dividends on our
Common Stock in the future will be made by our Board of Directors and will
depend on a number of factors, including future earnings, capital requirements,
financial condition and future prospects as well as such other factors as our
Board of Directors may deem relevant. Under the terms of the $12.0 million
principal amount of Debentures issued in October 2003, we are prohibited from
declaring or paying any dividends, other than stock dividends.

         RECENT SALES OF EQUITY SECURITIES SOLD DURING THE YEAR ENDED
 DECEMBER 31, 2003 NOT REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED.

         During the year ended December 31, 2003 we issued the following
securities not requiring registration under the Securities Act of 1933, as
amended:

1.       On February 14, 2003, we issued 166,700 shares of Common Stock to
Middlemarch Partners Ltd. in connection with a loan it made to us. The shares
were issued in a transaction exempt from the registration requirements of the
Securities Act of 1933, as amended, (the "Securities Act") by virtue of the
exemption afforded by Section 4(2) thereof. Such person purchased the shares for
its own account, for investment and not with a view to the distribution of the
shares. The certificate for the shares bears a restrictive legend and stop
transfer instructions have been placed against the transfer of the shares. No
underwriter participated in the sale of the securities.

2.       On March 26, 2003, we issued 688,000 shares of our Common Stock to
Quest Investment Corporation (which corporation subsequently merged with and
into Quest Capital Corp.), as principal and agent, in consideration for a loan
it made to us. The shares were issued in a transaction exempt from the
registration requirements of the Securities Act of 1933, as amended, (the
"Securities Act") by virtue of the exemption afforded by Section 4(2) thereof.
Such persons purchased the shares for their own account, for investment and not
with a view to the distribution of the shares. The certificates for the shares
bear a restrictive legend and stop transfer instructions have been


                                       22

<PAGE>


placed against the transfer of the shares. No underwriter participated in the
sale of the securities.

3.       On October 21 and 31, 2003, we issued an aggregate of $12.0 million of
our 8% Convertible Secured Debentures due September 30, 2005. The Debentures
were issued in a transaction exempt from and not requiring registration under
the U.S. Securities Act of 1933, as amended, by virtue of Regulation D and
Regulation S adopted under that Act. The securities were sold to "accredited
investors", as defined in Regulation D, and all of whom resided outside of the
United States. No underwriter participated in the sale of the securities. We
paid a commission of $360,000 in connection with the transaction. The principal
amount of the Debentures is convertible into shares of our Common Stock at any
time while the Debentures are outstanding at a conversion price of $0.45 per
share.

4.       On December 10, 2003, we issued 100,000 shares of our Common Stock to
Canaccord Capital Corporation in settlement of sums claimed arising out of a
proposed financing that was not concluded. The shares were issued in a
transaction exempt from the registration requirements of the Securities Act of
1933, as amended, (the "Securities Act") by virtue of the exemption afforded by
Section 4(2) thereof. Such person acquired the shares for its own account, for
investment and not with a view to the distribution of the shares. The
certificate for the shares bears a restrictive legend and stop transfer
instructions have been placed against the transfer of the shares. No underwriter
participated in the sale of the securities.

SMALL BUSINESS ISSUER PURCHASES OF EQUITY SECURITIES

         No purchases of shares of our Common Stock, par value $.01 per share,
were made by us or on our behalf or by any "affiliated purchaser," as defined in
Rule 10b-18(a)(3) under the U.S. Securities Exchange Act of 1934, as amended,
during the quarter ended December 31, 2003.


                                       23

<PAGE>


ITEM 6 - MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION:
------------------------------------------------------------------

GENERAL

         We are engaged in the acquisition, development, exploitation and
production of oil and natural gas. Our revenues and profitability can be
expected to be dependent, to a significant extent, upon prevailing spot market
prices for oil and natural gas. Additionally, our revenues and profitability can
be expected to be dependent upon the quantities of oil and natural gas produced
and sold. Prices for oil and natural gas are subject to wide fluctuations in
response to changes in supply of and demand for oil and natural gas, market
uncertainty and a variety of additional factors that are beyond our control.
Such factors include political conditions, weather conditions, government
regulations, the price and availability of alternative fuels and overall
economic conditions.

                  Our financial statements have been prepared on a going concern
basis which contemplates continuity of operations, realization of assets and
liquidation of liabilities in the ordinary course of business. We have sustained
substantial losses in 2003 and 2002, totaling approximately $5.7 and $8.7
million and negative cash flow from operations in each of 2003 and 2002, which
lead to questions concerning our ability to meet our obligations as they come
due. We also have a need for substantial funds to develop our oil and gas
properties. We have financed our activities using private debt and equity
financings and we have no line of credit or other financing agreement providing
borrowing availability with a commercial lender. As a result of the losses
incurred and current negative working capital and other matters described above,
there is no assurance that the carrying amounts of our assets will be realized
or that liabilities will be liquidated or settled for the amounts recorded. Our
ability to continue as a going concern is dependent upon adequate sources of
capital and the ability to sustain positive results of operations and cash flows
sufficient to continue to explore for and develop our oil and gas reserves. See
the discussion under the caption "How We Have Financed Our Activities".

         The independent accountants' report on our financial statements as of
and for the years ended December 31, 2003 and 2002 includes an explanatory
paragraph which states that we have sustained substantial losses, an accumulated
deficit, a working capital deficiency and negative cash flow from operations in
each of 2003 and 2002 that raise substantial doubt about our ability to continue
as a going concern.

         In the ordinary course of business, we have made and expect to continue
to make substantial capital expenditures for the exploration and development of
oil and natural gas reserves. In the past, we have financed our capital
expenditures, debt service and working capital requirements with the proceeds of
debt and private offerings of our securities. Our cash flow from operations is
sensitive to the prices we receive for our oil and natural gas. A reduction in
planned capital spending or an extended decline in oil and gas prices could
result in less than anticipated cash flow from operations and a lessened ability
to sell more of our common stock or refinance our debt with current


                                       24

<PAGE>

lenders or new lenders, which would likely have a further material adverse
effect on us. The uncertainty as to whether or not we can raise additional
capital in the future is likely to have an effect on our future revenues and
operations if we are unable to raise that additional capital.

STATEMENTS OF OPERATIONS

A Comparison of Operating Results For The Years Ended December 31, 2003 and
December 31, 2002

         We incurred a net loss of $5,682,000 during the year ended December 31,
2003 compared to a net loss of $8,731,000 for the year ended December 31, 2002.
During the year ended December 31, 2003, our revenues were comprised of oil and
gas sales and operations income totaling $1,743,000 compared with oil and gas
sales and operations income of $311,000 in 2002. Our oil and gas sales and
operations income for the year ended December 31, 2003 continued to increase
because of the revenues resulting from our increased oil and gas production from
the wells drilled in both 2002 and 2003. At December 31, 2003, we had 11 (6.25
net) wells producing approximately 400 (120 net) barrels of oil equivalents per
day, whereas at December 31, 2002 we had 5 (4.06 net) wells producing
approximately 75 (50 net) barrels of oil per day. Production from our existing
wells is subject to fluctuation from time to time based upon the zones of the
wells where we are obtaining production. We had interest and other income in
2003 of $4,200 compared with interest and other income of $166,000 in 2002. This
reduction in our interest income is the consequence of our lower cash balances
during 2003. Other income in 2002 of $164,000 principally represents the
recovery of accounts receivable written off in prior periods.

         Our total expenses were $6,423,000 for the year ended December 31, 2003
as compared to $9,208,000 for the year ended December 31, 2002. Total expenses
decreased due to lower impairment charges in 2003.

         Our general and administrative expenses in 2003 were $1,938,000
compared to $1,378,000 in 2002. These expenses also increased in 2003 because of
our increased activities directed at the development of additional wells and
production of oil and gas from those wells. Interest expense, net of interest
capitalized of $713,000 and $276,000 in 2003 and 2002, respectively, increased
to $440,000 in 2003 from $54,000 in 2002. While debt outstanding increased
during 2003, interest expense also reflects the amortization of a beneficial
conversion feature related to the issuance in October 2003 of the Company's
Debentures. Such amortization of the beneficial conversion feature was $399,000
in 2003. The Debentures are convertible into shares of our Common Stock at a
conversion price of $0.45 per share. On the dates the transaction was completed,
the closing price for our Common Stock was $0.70 per share. Accordingly, because
the conversion price was less than the market price on the dates the transaction
was completed, a beneficial conversion feature of $6.7 million was attributed to
the Debentures. Such amount will be amortized to interest expense over the life
of the Debentures which mature on September 30, 2005. If debentures are
converted prior to maturity, any unamortized amount attributed to such
debentures will be expensed at the


                                       25

<PAGE>

time of conversion. Lease operating expenses of $496,000, production taxes of
$67,000 and depletion, depreciation and amortization of $1,103,000 in 2003
increased from $482,000, $11,000, and $433,000, respectively in 2002 reflecting
the increase in production in 2003. We incurred an impairment charge reflecting
a write-down of the carrying value of our oil and gas properties of $654,000 in
2003 compared to an impairment charge of $6,477,000 in 2002. Our impairment
charges in 2003 and 2002 were the result of the excess of the capitalized cost
of our oil and gas properties over the estimated future net cash flows to be
derived from those proved reserves.

         In 2003, we had a gain on the sale of marketable securities of $173,000
and a foreign exchange loss of $1,716,000. In 2002, we had a gain on the sale of
marketable securities of $553,000 and a foreign exchange gain of $14,000. The
larger gain in 2002 was the result of the sale of more shares in 2002 than in
2003. The Company no longer holds marketable securities at December, 2003. Our
foreign exchange gains and losses arise out of an inter-company indebtedness
owing by ANEC to our wholly-owned subsidiary, Gothic, which is repayable in
Canadian dollars. The foreign exchange loss in 2003 was caused by the
strengthening of the Canadian dollar against the US dollar. In 2003, we also
incurred a loss of $222,000 as the result of the redemption of debt relating to
the early payoff of the TransAtlantic Petroleum production loan, the Quest
Capital note and the Bank One note from the proceeds of the Debentures. We had
no such loss in 2002. We had a gain on the sale of oil and gas properties in
2003 of $44,000 compared to a loss of $726,000 in 2002. The loss in 2002 was due
to the sale of our Oklahoma coalbed methane leasehold interests

         We also had a charge for the cumulative effect of an accounting change
resulting from the application of Statement of Financial Accounting Standards
No. 143, Accounting for Asset Retirement Obligations, in the amount of $1.0
million. We had no comparable charge in 2002.

         Our accounts payable increased to $3,600,000 at December 31, 2003 from
$1,900,000 at December 31, 2002 resulting primarily from the increased scale of
our operations. We are not aware that our accounts payable are in default or
arrears to any material extent.

A Comparison of Operating Results For The Years Ended December 31, 2002 and
December 31, 2001

         We incurred a net loss of $8,731,000 in the year ended December 31,
2002 compared to a net loss of $999,000 for the same period in 2001. During
2002, our income was comprised of interest and other income of $166,000 and of
oil and gas and operations revenues of $311,000. Our oil and gas operations
revenues in 2002 reflect the revenues from the production from the four (three
and one-half net) wells we drilled in 2002. We had no productive wells producing
revenues in 2001. Interest income was $2,500. This compares with interest income
of $64,000 in 2001. Interest income in 2002 was less than 2001 because of lower
average cash balances. Other income of $164,000 represents the recovery of
accounts receivable written off in prior periods. We had no such recoveries in
2001.


                                       26

<PAGE>

         In 2001, our activities were directed primarily towards the completion
of our acquisition of the Couba properties and we were not actively engaged in
development and production activities. In 2002, virtually all of our general and
administrative expenses increased because of our oil and gas well drilling
activities and our activities related to the production of oil and gas.
Reflecting these operations, salary expenses increased by $348,000, audit and
legal expenses increased by $114,000 and office rent and related expenses
increased by $107,000.

         Our expenses were $9,208,000 for the year ended December 31, 2002 as
compared to $1,063,000 for the same period in 2001. Our general and
administrative expenses increased from $650,000 in 2001 to $1,378,000 in 2002
resulting from increased activity in changing to active operations. In 2002 we
had lease operating expenses of $482,000, production taxes of $11,000 and
depreciation, depletion and amortization of $433,000, all of which were usual
expenses incurred in oil and gas production activities. We also had a loss on
sale of oil and gas properties and fixed assets of $726,000 and $100,000,
respectively. These were the result of sales of our Oklahoma natural gas
properties and related assets. Additionally, we had a write down on the value of
oil in inventory at December 31, 2002 of $114,000 which was the result of
reflecting an adjustment of inventory valuations to the lower of cost or market
price. We had no comparable expenses in 2001.

         We incurred an impairment charge reflecting a write-down of the
carrying value of our oil and gas properties of $6,477,000 in 2002 compared to
an impairment charge of $573,000 in 2001. Our impairment charge in 2002 was the
result of the excess at December 31, 2002 of the capitalized cost of our oil and
gas properties over the estimated future net cash flows to be derived from those
proved reserves.

         In 2002, we had a gain on the sale of marketable securities of
$553,000, resulting from the sale of shares of First Calgary Petroleum Ltd. and
T&H Resources, neither of which companies was an affiliate of ours, and a
foreign exchange gain of $14,000. In 2001, we had a gain on the sale of
marketable securities of $77,000 and a foreign exchange gain of $90,000.

LIQUIDITY AND CAPITAL RESOURCES

Years Ended December 31, 2003 and December 31, 2002.

         Our net cash used in operations was $361,000 for the year ended
December 31, 2003 as compared to net cash used in operations of $105,000 for
2002. While production from our drilling program has increased revenues in 2003,
such increase has not been sufficient to fund our operations. We have funded our
capital expenditures and operating activities through a series of private debt
and equity transactions. At December 31, 2003, we do not have any available
borrowing capacity under existing credit facilities. We have substantial needs
for funds to develop our oil and gas prospects and opportunities identified in
our AMI. At December 31, 2003, we have committed to expend up to approximately
$850,000 for drilling activities in 2004. This capital expenditure will be


                                       27

<PAGE>

funded from our available cash which includes the remaining portion of the
proceeds from the sale of our Debentures in October 2003. To the extent
additional funds are required to fully exploit and develop the ExxonMobil Corp.
AMI, it is management's plan to raise additional capital through the sale of our
equity securities or the sale of interests in our drilling activities, however,
we currently have no firm commitment from any potential investors and such
additional capital may not be available to us in the future.

         Cash used in operating activities was impacted in 2003 by a gain of
$173,000 on the sale of marketable securities and a foreign currency exchange
loss of $1,716,000, which did not affect our cash position. Depletion,
depreciation and amortization was $1,103,000 in 2003, resulting from increased
activity in our oil and gas operations, compared to $433,000 in 2002. Accounts
receivable, accounts payable, accrued liabilities and interest increased
significantly in 2003 over 2002 because of the expanded scope of our activities.
We also incurred a non cash impairment charge against our oil and gas properties
in the amount of $654,000, resulting from ceiling test write-down, in 2003
compared to $6,477,000 in 2002. An impairment charge, or also referred to as a
ceiling test write down, is the result of the capitalized cost of our oil and
gas properties exceeding at December 31, 2003 and December 31, 2002 the
estimated future net cash flows to be derived from our proved reserves as of
those respective dates. During the year ended December 31, 2003 we had a charge
for the cumulative effect of an accounting change resulting from the application
of Statement of Financial Accounting Standards No. 143, Accounting for Asset
Retirement Obligations, in the amount of $1,005,000 million. We had no
comparable charge in 2002.

         We used $4,109,000 of net cash in investing activities during the year
ended December 31, 2003 compared to net cash used of $1,421,000 million in 2002.
The 2003 cash used in investing activities includes $4,635,000 for the purchase
and development of oil and gas properties and $144,000 for the purchase of fixed
assets compared to $4,060,000 million and $946,000, respectively, in 2002.
Proceeds from the sale of marketable securities, net of cash expended on
purchases of marketable securities, were $208,000 in 2003 compared to
approximately $2,582,000 in 2002. Proceeds from the sale of oil and gas
properties amounted to $462,000 in 2003 compared to $941,000 in 2002.

         Our net cash provided by financing activities for the year ended
December 31, 2003 was $6,039,000 compared to $512,000 provided in 2002. The
activity in 2003 was the result of new financing from Quest Investment
Corporation (which subsequently merged with and into Quest Capital Corp.),
TransAtlantic Petroleum (USA) Corp. and the private placement of Convertible
Secured Debentures and reflects the repayments to Middlemarch Partners Limited,
Bank One, Quest Capital Corp. and TransAtlantic Petroleum (USA) Corp.

         Additional information regarding liquidity and capital resources is
included under the caption "Future Capital Requirements and Resources."

Years Ended December 31, 2002 and December 31, 2001.


                                       28

<PAGE>

         Our net cash used in operations was $105,000 for the year ended
December 31, 2002 as compared to net cash used of $266,000 for 2001. Cash used
by operating activities was impacted by a gain of $553,000 on the sale of
marketable securities and losses on the sale of fixed assets and oil and gas
properties of $100,000 and $726,000, respectively. Additionally, we had a non
cash write-down in the value of oil in inventory of $114,000. We did not have
any corresponding losses for 2001. We incurred a non cash charge of $6.5 million
for the impairment of our oil and gas properties in 2002 compared to $573,000 in
2001. DD&A was $433,000 in 2002 compared to $4,000 in 2001 as we began
production activities. Accounts payable and accrued liabilities increased
significantly in 2002 over 2001 because of the expanded scope of our activities.

         We used $1,421,000 of net cash in investing activities for the year
ended December 31, 2002 compared to net cash used of $1,877,000 in 2001. The
2002 cash used for investing activities includes $4,060,000 for the purchase and
development of oil and gas properties and is partially offset by proceeds from
the sale of marketable securities, netted against purchases of marketable
securities, of approximately $2,582,000. In 2001, cash of $3,378,000 was used in
the acquisition of oil and gas leaseholds and assets. Also in 2001, net
securities activities provided approximately $1,389,000 in additional cash.

         Our net cash provided by financing activities for 2002 was $512,000
compared to $3,164,000 provided in 2001.

CRITICAL ACCOUNTING POLICIES

Oil and Gas Properties

         We account for our oil and gas exploration and development activities
using the full cost method (as opposed to the successful efforts method) of
accounting prescribed by the SEC. Accordingly, all our productive and
non-productive costs incurred in connection with the acquisition, exploration
and development of oil and natural gas reserves are capitalized and depleted
using the units-of-production method based on proved oil and gas reserves. We
capitalize our costs including salaries and related fringe benefits of employees
directly engaged in the acquisition, exploration and development of oil and
natural gas properties, asset retirement costs, as well as other directly
identifiable general and administrative costs associated with these activities.
These costs do not include any costs related to production, general corporate
overhead, or similar activities. Our oil and natural gas reserves will be
estimated annually by independent petroleum engineers. Our calculation of
depreciation, depletion and amortization ("DD&A") includes estimated future
expenditures that we believe we will incur in developing our proved reserves and
the estimated dismantlement and abandonment costs, net of salvage values.
Quarterly, we will perform a review of the carrying costs of our oil and gas
properties to assess whether such costs are fully recoverable from future cash
flows. In the event the unamortized cost of the oil and natural gas properties
we are amortizing exceeds the full cost ceiling as defined by the SEC, we will
charge the amount of the excess to expense in the period during which the excess
occurs. The full cost ceiling is based principally on the estimated future
discounted net cash flows from our oil and natural gas properties. Changes in
our estimates or declines in prevailing oil and natural gas prices could cause
us to reduce in the near term our carrying value of our oil


                                       29

<PAGE>

and natural gas properties. A write-down arising out of these conditions is
referred to throughout our industry as a full cost ceiling write-down.

         We evaluate oil and natural gas reserve acquisition opportunities in
light of many factors only a portion of which may be reflected in the amount of
proved oil and natural gas reserves that we propose to acquire. In determining
the purchase price to be offered, we do not solely rely on proved oil and gas
reserves or the value of such reserves determined in accordance with Rule 4-10
of Regulation S-X adopted by the SEC. Factors we consider include the probable
reserves of the interests intended to be acquired, anticipated efficiencies and
cost reductions that we believe can be made in us operating the producing
properties, the additional reserves that we believe can be proven relatively
inexpensively based on our knowledge of the area where the interests are located
and existing producing properties we may own. We may also consider other factors
if appropriate. We may conclude that an acquisition is favorable, even if there
may be a subsequent full-cost ceiling write-down associated with it, based on
other factors we believe are important. We do not perform a ceiling test for
specific properties acquired because the ceiling test is performed at each
quarter and at year end for all of our properties included in our cost center
and is based on prices for oil and natural gas as of that date which may be
higher or lower than the prices used when evaluating potential acquisitions. We
review the transaction in the light of proved and probable reserves, historic
and seasonal fluctuations in the prices of oil and natural gas, anticipated
future prices for oil and natural gas, the factors described above as well as
other factors that may relate to the specific properties under review.

Revenue Recognition

         Our profitability and revenues are and will be dependent, to a
significant extent, upon prevailing spot market prices for oil and natural gas.
Oil and natural gas prices and markets have been volatile. Prices are subject to
wide fluctuations in response to changes in supply of and demand for oil and
natural gas, market uncertainty and a variety of additional factors that are
beyond our control. Such factors include political conditions, weather
conditions, government regulations, the price and availability of alternative
fuels and overall economic conditions. Natural gas prices have fluctuated
significantly over the past twelve months.

         We use the sales method for recording natural gas sales. Our oil and
condensate production is sold, title passed, and revenue recognized at or near
our wells under short-term purchase contracts at prevailing prices in accordance
with arrangements, which are customary in our industry. Our gas sales are
recorded as revenues when the gas is metered and title transferred pursuant to
the gas sales contracts. During such times as our sales of gas exceed our pro
rata ownership in a well, such sales will be recorded as revenues unless total
sales from the well have exceeded our share of estimated total gas reserves
underlying the property at which time the excess will be recorded as a gas
balancing liability.


                                       30

<PAGE>

Income taxes

         As part of the process of preparing the consolidated financial
statements, we are required to estimate the federal and state income taxes in
each of the jurisdictions in which we operate. This process involves estimating
the actual current tax exposure together with assessing temporary differences
resulting from differing treatment of items, such as depreciation, depletion and
amortization, and certain accrued liabilities for tax and accounting purposes.
These differences and the net operating loss ("NOL") carryforwards result in
deferred tax assets and liabilities, which are included in our consolidated
balance sheet. We must then assess, using all available positive and negative
evidence, the likelihood that the deferred tax assets will be recovered from
future taxable income. If we believe that recovery is not likely, we must
establish a valuation allowance. To the extent we establish a valuation
allowance or increase or decrease this allowance in a period, we must include an
expense or reduction of expense within the tax provisions in the consolidated
statement of operations.

         Under SFAS 109, Accounting for Income Taxes, an enterprise must use
judgment in considering the relative impact of negative and positive evidence.
The weight given to the potential effect of negative and positive evidence
should be commensurate with the extent to which it can be objectively verified.
The more negative evidence that exists (a) the more positive evidence is
necessary and (b) the more difficult it is to support a conclusion that a
valuation allowance is not needed for some portion, or all of the deferred tax
asset. Among the more significant types of evidence that we consider are:

o        taxable income projections in future years,
o        whether the carryforward period is so brief that it would limit
         realization of tax benefits,
o        future sales and operating cost projections that will produce more than
         enough taxable income to realize the deferred tax asset based on
         existing sales prices and cost structures, and
o        our earnings history exclusive of the loss that created the future
         deductible amount coupled with evidence indicating that the loss is an
         aberration rather than a continuing condition.

     Since we have no earnings history to determine the likelihood of realizing
the benefits of the deferred tax assets, we are unable to determine our ability
to realize our NOL carryforwards prior to their expiration. Accordingly, we are
required to provide a valuation allowance against our deferred tax asset. As of
December 31, 2003 and 2002 we have a deferred tax asset of approximately $5.6
million and $4.0 million for which we have recognized a $5.6 million and $4.0
million valuation allowance, respectively.

Notes payable and long-term debt

         We account for notes payable and long-term debt by recording the face
amount of the debt instrument adjusted for any premium or discount realized on
the issuance of the instrument. The premium or discount is amortized to expense
utilizing the effective interest rate method for debt instruments with scheduled
repayment terms, and by


                                       31

<PAGE>

utilizing units of production basis for production based loan agreements. Any
un-amortized premium or discount remaining at early retirements of a debt
instrument is recorded as a gain or loss as applicable.

HOW WE HAVE FINANCED OUR ACTIVITIES

         Our activities since 2002 have been financed primarily from private
sales of debt and equity securities. Most recently, in October 2003, we
completed the private sale of $12.0 million principal amount of 8% Convertible
Secured Debentures (the "Debentures") due September 30, 2005. The Debentures
bear interest payable quarterly commencing December 31, 2003 at 8% per annum.
The outstanding principal of the Debentures is convertible into shares of our
Common Stock at any time prior to maturity at a conversion price of $0.45 per
share, subject to anti-dilution adjustment, and the Debentures are redeemable by
us at any time after October 1, 2004 if the average weighted price per share on
the TSX Venture Exchange for a 20 consecutive trading day period prior to the
date notice of redemption is given has exceeded 166-2/3% of the conversion
price. The Debentures are collateralized by substantially all of our assets. A
finder's fee in the amount of $360,000 was paid to Middlemarch Partners Limited
in connection with the financing. We used approximately $5.9 million of the
proceeds of the financing for the repayment of secured debt, approximately $2.1
million for the payment of accounts payable and intend to use the balance
primarily for exploration and development of our Bayou Couba oil and gas leases
within the ExxonMobil Joint Development Project in St. Charles Parish,
Louisiana. The secured indebtedness repaid included $2.5 million to Quest
Capital Corp., which bore interest at 12% per annum, was due October 31, 2003,
and was collateralized by a first lien on substantially all our assets, and
approximately $1.7 million owing to Bank One Michigan, NA, which bore interest
at the bank's prime rate plus 2%, was due December 31, 2003 and was
collateralized by a junior lien on substantially all our assets. In addition, we
paid out of the proceeds a $1.7 million production payment owing to
TransAtlantic Petroleum (USA) Corp. TransAtlantic retained its 10% participation
right in our AMI with ExxonMobil Corp. described above which was granted as
partial consideration for the $2.0 million financing entered into in March 2003.
On both October 21 and 31, 2003, the dates the transaction was completed, the
closing sale prices for our shares were $0.70 on the TSX Venture Exchange.

         In connection with the financing and under the terms of the
transaction, John Fleming, formerly Chairman and Director of TransAtlantic, and
Jules Poscente, Chairman and Director of Eurogas Corp., both of Calgary,
Alberta, were elected to our Board of Directors. Mr. Fleming died on March 3,
2004 and it is expected that another person to be selected by the holders of the
Debentures will be elected to our Board of Directors.

         Purchasers of the Debentures included TransAtlantic Petroleum Corp.,
$3.0 million principal amount, and Quest Capital Corp., $500,000 principal
amount. Mr. Brian Bayley, who has been a Director of our company since June
2001, is also President and Chief Executive Officer of Quest Capital Corp. and a
Director of TransAtlantic. In addition, Bonanza Energy Ltd., a corporation of
which Mr. Fleming was the sole


                                       32

<PAGE>

shareholder, purchased $500,000 principal amount of Debentures. Out of the
proceeds of the sale of the Debentures, TransAtlantic was paid $1.7 million in
payment in full of a production payment owing to it and Quest Capital Corp. was
paid $2.5 million in repayment of a loan. Quest Capital Corp. is engaged in
merchant banking activities in Canada and elsewhere which includes providing
financial services to small and mid-cap companies operating primarily in North
America. Quest Investment Corporation is a predecessor company of Quest Capital
Corp..

         The Debentures are convertible into common shares at a conversion price
of $0.45 per share. On the dates the transaction was completed, the closing
price for shares of our common stock on the TSX Venture Exchange was $0.70 per
share. Accordingly, because of the conversion price being less than the market
price on the dates the transaction was completed, there was created a beneficial
conversion feature to the Debentures of approximately $6.7 million. This amount
will be amortized to interest expense over the life of the Debentures which
mature on September 30, 2005. In the event any Debentures are converted prior to
September 30, 2005, any un-amortized discount attributed to those proportionate
holdings will be expensed at the time of conversion.

FUTURE CAPITAL REQUIREMENTS AND RESOURCES

         Our capital requirements relate to the acquisition, exploration,
enhancement, development and operation of oil and natural gas properties. In
general, because our oil and natural gas reserves will be depleted by production
over time, the success of our business strategy is dependent upon a continuous
acquisition, exploitation, enhancement, and development program. In order to
achieve profitability and generate cash flow, we are dependent upon acquiring or
developing additional oil and natural gas properties or entering into joint oil
and natural gas well development arrangements.

         At December 31, 2003, we have committed to expend up to approximately
$850,000 for drilling activities in 2004. This capital expenditure will be
funded from our available cash which includes the remaining portion of the
proceeds from the sale of our Debentures in October 2003. We currently have no
borrowing capacity with any lender. To the extent additional funds are required
to fully exploit and develop this area, it is management's plan to raise
additional capital through the sale of our equity securities or the sale of
interests in our drilling activities, however, we currently have no firm
commitment from any potential investors and such additional capital may not be
available to us in the future.

         Our business strategy requires us to obtain additional financing and
our failure to do so can be expected to adversely affect our ability to further
the development of our ExxonMobil AMI, grow our revenues, oil and gas reserves
and achieve and maintain a significant level of revenues and profitability.
There can be no assurance we will obtain this additional funding. Such funding
may be obtained through the sale of equity securities or by incurring additional
indebtedness. Without such funding, our revenues will continue to be limited and
it can be expected that our operations will not be


                                       33

<PAGE>

profitable. In addition, any additional equity funding that we obtain may result
in material dilution to the current holders of our common stock.

         We intend, as opportunities arise, to evaluate the acquisition and
development of additional leasehold interests. We are unable at this time to
state whether or where any such additional properties may be acquired, to
estimate the purchase price for any properties we may acquire or to state the
terms on which financing for these purposes can be obtained.

ACCOUNTING MATTERS

         Statement of Financial Accounting Standards No. 141, Business
Combinations ("SFAS 141") and Statement of Financial Accounting Standards No.
142, Goodwill and Intangible Assets ("SFAS 142") were issued by the Financial
Accounting Standards Board in June 2001 and became effective for us on July 1,
2001 and January 1, 2002, respectively. SFAS 141 requires all business
combinations initiated after June 30, 2001 to be accounted for using the
purchase method. Additionally, SFAS 141 requires companies to disaggregate and
report separately from goodwill certain intangible assets. SFAS 142 establishes
new guidelines for accounting for goodwill and other intangible assets. Under
SFAS 142, goodwill and certain other intangible assets are not amortized, but
rather are reviewed annually for impairment. The Emerging Issues Task Forces
(EITF) is considering two issues related to the reporting of oil and gas mineral
rights. Issue No. 03-S, Application of SFAS No. 142, Goodwill and Other
Intangible Assets to Oil and Gas Companies, considers whether oil and gas
drilling rights are subject to the classification and disclosure provisions of
SFAS 142 if they are intangible assets. We classifiy the cost of oil and gas
mineral rights as proved and unproved oil and natural gas properties and believe
that this is consistent with oil and gas accounting and industry practice. If
the EITF determines that oil and gas mineral rights are intangible assets and
are subject to the applicable classification and disclosure provisions of SFAS
142, we estimate that $3.8 million and $2.7 million would be classified on our
consolidated balance sheets as "intangible undeveloped leasehold" and $2.4
million and $830,000 would be classified as "intangible developed leasehold" as
of December 31, 2003 and 2002, respectively. These amounts are net of
accumulated DD&A. There would be no effect on the consolidated statements of
operations or cash flows as the intangible assets related to oil and gas mineral
rights would continue to be amortized under the full cost method of accounting.

         We will continue to classify our oil and gas mineral rights held under
lease and other contractual rights representing the right to extract such
reserves as tangible oil and gas properties until further guidance is provided.

         In July 2002, the FASB issued Statement of Financial Accountings
Standards No. 146, Accounting For Costs Associated with Exit or Disposal
Activities ("SFAS 146"). SFAS 146 was effective for exit or disposal activities
initiated after December 31, 2002. Adoption of this standard did not have any
impact on our financial position or results of operations.


                                       34

<PAGE>

         In November 2002, the FASB issued FASB Interpretation No. 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantee of Indebtedness of Others ("FIN 45"). FIN 45 requires that
upon issuance of a guarantee, the guarantor must recognize a liability for the
fair value of the obligation it assumes under that guarantee. FIN 45's
provisions for initial recognition and measurement should be applied on a
prospective basis to guarantees issued or modified after December 31, 2002. The
guarantor's previous accounting for guarantees that were issued before the date
of FIN 45's initial application may not be revised or restated to reflect the
effect of the recognition and measurement provisions of the Interpretation. The
disclosure requirements are effective for financial statements of both interim
and annual periods that end after December 15, 2002. We are not a guarantor
under any significant guarantees and thus this interpretation did not have a
significant effect on our financial position or results of operations.

          In January 2003, the FASB issued FASB Interpretation No. 46,
Consolidation of Variable Interest Entities -- An Interpretation of ARB No. 51
("FIN 46"). FIN 46 is an interpretation of Accounting Research Bulletin 51,
"Consolidated Financial Statements," and addresses consolidation of variable
interest entities (VIEs) by business enterprises. The primary objective of FIN
46 is to provide guidance on the identification and financial reporting of
entities over which control is achieved through means other than voting rights;
such entities are known as VIEs. FIN 46 requires an enterprise to consolidate a
VIE if that enterprise has a variable interest that will absorb a majority of
the entity's expected losses, receive a majority of the entity's expected
residual returns, or both. An enterprise shall consider the rights and
obligations conveyed by its variable interest in making this determination. At
December 31, 2003, we did not have any entities that would qualify for
consolidation in accordance with the provisions of FIN 46, as amended.
Therefore, the adoption of FIN 46, as amended, did not have an impact on our
consolidated financial statements

         In April 2003, the FASB issued Statement of Financial Accounting
Standards No. 149, Amendment of Statement 133 on Derivative Instruments and
Hedging Activities ("SFAS 149"). SFAS 149 amends and clarifies financial
accounting and reporting for derivative instruments, including certain
derivative instruments embedded in other contracts (collectively referred to as
derivatives) and for hedging activities under Statement of Financial Accounting
Standards No. 133, Accounting for Derivative Instruments and Hedging Activities.
This pronouncement is effective for contracts entered into or modified after
June 30, 2003, and for hedging relationships designated after that date. We
currently have no derivatives, embedded derivatives requiring bifurcation and
separate measurement, or hedging activities, therefore, the implementation of
SFAS 149 did not have any effect on our financial opposition, results of
operations, or cash flows.

         In May 2003, the FASB issued Statement of Financial Accounting
Standards No. 150, Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity ("SFAS 150"). SFAS 150
establishes standards regarding the classification and measurement of certain
financial instruments with characteristics of both liabilities and equity. It
requires that an issuer classify a financial instrument that is


                                       35

<PAGE>

within its scope as a liability (or an asset in some circumstances). Many of
those instruments were previously classified as equity. SFAS 150 became
effective for us starting in the quarter ended September 30, 2003. The
application of SFAS 150 did not have any effect on our financial position,
results of operations or cash flow.

         In December 2003, the Securities and Exchange Commission issued Staff
Accounting Bulletin 104, Revenue Recognition. SAB 104 revises or rescinds
certain guidance included in previously issued staff accounting bulletins in
order to make this interpretive guidance consistent with current authoritative
accounting and auditing guidance and SEC rules and regulations relating to
revenue recognition. This bulletin was effective immediately upon issuance. Our
current revenue recognition policies comply with SAB 104.

                                  RISK FACTORS

         An investment in shares of our common stock involves a high degree of
risk. You should consider the following factors, in addition to the other
information contained in this annual report, in evaluating our business and
proposed activities before you purchase any shares of our common stock. You
should also see the "Cautionary Statement for Purposes of the Safe Harbor
Provisions of the Private Securities Litigation Reform Act of 1995" regarding
risks and uncertainties relating to us and to forward looking statements in this
annual report.

RISKS RELATING TO US AND THE OIL AND GAS INDUSTRY

OUR ABILITY TO CONTINUE AS A GOING CONCERN IS UNCERTAIN

         Our financial statements have been prepared on a going concern basis
which contemplates continuity of operations, realization of assets and
liquidation of liabilities in the ordinary course of business. We have sustained
substantial losses in 2001, 2002 and 2003, totaling approximately $1.0 million,
$8.7 million and $5.7 million, respectively, and had a working capital
deficiency at December 31, 2003 of approximately $116,000. We had a negative
cash flow from operations in 2003 and 2002. While production from our drilling
program has increased revenues in 2003, such increase has not been sufficient to
fund our operations. All the foregoing lead to questions concerning our ability
to meet our obligations as they come due. We also have a need for substantial
funds to develop our oil and gas properties. We have financed our activities
using private debt and equity financings, and we have no line of credit or other
financing agreement providing borrowing availability with a commercial lender.
As a result of the losses incurred and current negative working capital and
other matters described above, there is no assurance that the carrying amounts
of our assets will be realized or that liabilities will be liquidated or settled
for the amounts recorded. Our ability to continue as a going concern is
dependent upon adequate sources of capital and the ability to sustain positive
results of operations and cash flows sufficient to continue to explore for and
develop our oil and gas reserves.


                                       36

<PAGE>

         The independent accountants' report on our financial statements as of
and for the year ended December 31, 2003 includes an explanatory paragraph which
states that we have sustained substantial losses, an accumulated deficit, a
working capital deficiency and negative cash flow from operations in each of
2003 and 2002 that raise substantial doubt about our ability to continue as a
going concern.

WITHOUT SUBSTANTIAL ADDITIONAL CAPITAL WE MAY BE UNABLE TO FUND THE EXPLORATION
AND DEVELOPMENT ACTIVITIES TO FURTHER DEVELOP OUR AREA OF MUTUAL INTEREST WITH
EXXONMOBIL CORP.

         We have substantial needs for funds to further develop our oil and gas
prospects and opportunities identified in our AMI with ExxonMobil Corp.. At
December 31, 2003, we have committed to expend up to approximately $850,000 for
drilling activities in 2004. This capital expenditure will be funded from our
available cash which includes the remaining portion of the proceeds from the
sale of our Debentures in October 2003. To the extent additional funds are
required to further exploit and develop the ExxonMobil Corp AMI, it is
management's plan to raise additional capital through the sale of our equity
securities or the sale of interests in our drilling activities, however, we
currently have no firm commitment from any potential investors and such
additional capital may not be available to us in the future. Our inability to
raise additional capital will limit and perhaps prevent us from further
development of the AMI.

OIL AND GAS PRICES FLUCTUATE WIDELY AND LOW OIL AND GAS PRICES COULD ADVERSELY
AFFECT OUR FINANCIAL RESULTS.

         Our revenues, operating results, cash flow and future rate of growth
depend substantially upon prevailing prices for oil and gas. Historically, oil
and gas prices and markets have been volatile, and they are likely to continue
to be volatile in the future. A significant decrease in oil and gas prices, such
as that experienced in 1998 and the first half of 1999, could have a material
adverse effect on our cash flow and profitability and would adversely affect our
financial condition and the results of our operations.

         Prices for oil and gas fluctuate in response to relatively minor
changes in the supply of and demand for oil and gas, market uncertainty and a
variety of additional factors that are beyond our control, including:

         o  political conditions in oil producing regions, including the Middle
            East;

         o  the domestic and foreign supply of oil and gas;

         o  the level of consumer demand;

         o  weather conditions;

         o  domestic and foreign government regulations;


                                       37

<PAGE>

         o  the price and availability of alternative fuels;

         o  overall economic conditions; and

         o  international political conditions.

         In addition, various factors may adversely affect our ability to market
our oil and gas production, including:

         o  the capacity and availability of oil and gas gathering systems and
            pipelines;

         o  our ability to produce oil and gas in commercial quantities and to
            enhance and maintain production from existing wells and wells
            proposed to be drilled;

         o  the effect of federal and state regulation of production and
            transportation;

         o  general economic conditions;

         o  changes in supply due to drilling by other producers;

         o  the availability of drilling rigs and related crews; and

         o  changes in demand.

LOWER OIL AND GAS PRICES MAY ADVERSELY AFFECT OUR LEVEL OF CAPITAL EXPENDITURES,
RESERVE ESTIMATES AND BORROWING CAPACITY.

         In the ordinary course of business, we have made and expect to continue
to make substantial capital expenditures for the exploration and development of
oil and natural gas reserves. In the past, we have financed our capital
expenditures, debt service and working capital requirements with the proceeds of
debt and private offerings of our securities. Our cash flow from operations is
sensitive to the prices we receive for our oil and natural gas. A reduction in
capital spending or an extended decline in oil and natural gas prices could
result in less than anticipated cash flow from operations and a lessened ability
to raise additional capital or refinance our debt with current lenders or new
lenders, which would likely have a further material adverse effect on us.

         Lower oil and gas prices have various other adverse effects on our
business. A smaller capital expenditure program resulting from reduced cash
flows may adversely affect our ability to increase or maintain our oil and
natural gas reserves and production levels. Lower prices may also result in
reduced oil and natural gas reserve estimates, the write-off of impaired assets
and decreased earnings or losses due to lower oil and natural gas revenues and
higher depreciation, depletion and amortization expense.


                                       38

<PAGE>

         Lower oil and gas prices could adversely affect our ability to borrow
funds in other ways. Lower commodities prices for oil and natural gas adversely
affects the valuations of our oil and natural gas reserves which in turn
adversely affects the amounts lenders may loan to us secured by those oil and
natural gas reserves. Furthermore, reduction in such prices could impede our
ability to fund future acquisitions.

WE MUST REPAY $12.0 MILLION OF SECURED INDEBTEDNESS ON SEPTEMBER 30, 2005. THERE
ARE RISKS THAT THIS INDEBTEDNESS MAY NOT BE REPAID WHEN DUE.

         In October 2003, we completed a borrowing of $12.0 million used for
repayment of outstanding short-term secured debt, for exploration and
development activities on the oil and gas leases within our ExxonMobil joint
development project in St. Charles Parish, Louisiana and for general corporate
purposes. The $12.0 million borrowing is due to be repaid on September 30, 2005
and bears interest at 8% per annum, payable quarterly commencing December 31,
2003. The loan is collateralized by a lien against all our oil and natural gas
properties and undeveloped leaseholds. The indebtedness is convertible into
shares of our common stock at an initial conversion price of $0.45 per share,
subject to anti-dilution adjustments. In the event we are unsuccessful in
refinancing this indebtedness at or before its maturity, the creditors could
foreclose against substantially all of our assets. Under such circumstances, the
holders of our common stock could realize little or nothing from their
investment in our shares of common stock. There can be no assurance that we will
be successful in refinancing this indebtedness or that the terms of such
refinancing may not be disadvantageous to the holders of our common stock or
result in material dilution. Our inability to pay or refinance this indebtedness
could lead to the creditors foreclosing on all our assets which could result in
the loss of a stockholder's entire investment.

OUR FUTURE BORROWINGS AND OTHER OIL AND GAS DEVELOPMENT ACTIVITIES MAY BE
RESTRICTED BECAUSE OF THE RESTRICTIVE COVENANTS IN OUR EXISTING SECURED
INDEBTEDNESS WHICH, AMONG OTHER THINGS, RESTRICTS OUR ABILITY TO INCUR
INDEBTEDNESS IN EXCESS OF $2.0 MILLION

         The terms of our recent $12.0 million borrowing in October 2003,
include a number of affirmative and negative covenants. Among the covenants is a
provision that prohibits us from incurring any indebtedness in excess of $2.0
million without the prior approval of the holders of the indebtedness at a
meeting of the holders by a favorable vote of two-thirds of the principal amount
of debt holders present at the meeting. This restriction on our ability to incur
indebtedness in excess of $2.0 million may impede our ability to fund the
development of our properties in St. Charles Parish, Louisiana. These limits on
our ability to develop these properties may impair our growth in revenues and
oil and natural gas reserves. We may be unable to borrow the funds we may
believe we require to fund further well drilling and development activities
which would result in our inability to replenish our reserves as they are
depleted.

ADDITIONAL SECURED INDEBTEDNESS WE MAY INCUR IN THE FUTURE MAY INCREASE OUR
EXPOSURE TO RISKS ASSOCIATED WITH HIGHER DEBT LEVELS AND POSSIBLE DEFAULTS.


                                       39

<PAGE>

         Subject to the terms of our existing outstanding indebtedness which
matures in September 2005, we may refinance our existing indebtedness and incur
substantial additional indebtedness in the future to fund the acquisition and
development of additional oil and gas reserves or for other purposes. The
issuance of material amounts of indebtedness would expose us to additional risks
including, among others, the following:

         o  a portion of our cash flow from operations would be utilized for the
            payment of principal and interest on our indebtedness and would not
            be available for financing capital expenditures or other purposes;

         o  our level of indebtedness and the covenants governing our
            indebtedness could limit our flexibility in planning for, or
            reacting to, changes in our business because certain financing
            options may be limited or prohibited under the terms of our
            agreements relating to such indebtedness;

         o  our level of indebtedness may make us more vulnerable to defaults
            during periods of low oil and gas prices or in the event of a
            downturn in our business because of our fixed debt service
            obligations; and

         o  the terms of our agreements may require us to make interest and
            principal payments and to remain in compliance with stated financial
            covenants and ratios. If the requirements of these agreements are
            not satisfied, the lenders would be entitled to accelerate the
            payment of all outstanding indebtedness and foreclose on the
            collateral securing payment of that indebtedness. In such event, we
            cannot assure you that we would have sufficient funds available or
            could obtain the financing required to meet our obligations,
            including the repayment of the outstanding principal and interest on
            this indebtedness.

         In addition to the risks described above, these risks may impose limits
on our ability to develop our oil and gas properties and restrict our ability to
replenish our reserves of oil and gas as they are depleted.

OUR EXISTING RESERVES OF OIL AND NATURAL GAS WILL BE DEPLETED OVER TIME BY
PRODUCTION AND THEREFORE OUR FUTURE ABILITY TO EARN REVENUES AND MEET OUR
EXPENSES AND REPAY OUR INDEBTEDNESS DEPENDS UPON OUR ABILITY TO FIND OR ACQUIRE
ADDITIONAL OIL AND NATURAL GAS RESERVES THAT ARE ECONOMICALLY RECOVERABLE AND
RESULT IN REVENUES TO US.

         Unless we successfully replace the oil and natural gas reserves that we
produce, our reserves will decline, resulting eventually in a decrease in the
quantities of oil and natural gas we are able to produce and lower revenues and
cash flow from operations. We seek to replace reserves through exploitation,
development and exploration, as well as through acquisitions. We may not be able
to continue to replace reserves from our exploitation, development and
exploration activities at acceptable costs. Lower prices of oil and gas may
further limit the kinds of reserves that can be developed at an acceptable cost.
Lower prices also decrease our cash flow and may cause us to decrease capital
expenditures. The business of exploring for, developing or acquiring reserves is
capital


                                       40

<PAGE>

intensive. We may not be able to make the necessary capital investment to
maintain or expand our oil and gas reserves if cash flow from operations is
reduced and external sources of capital become limited or unavailable. In
addition, exploitation, development and exploration involve numerous risks that
may result in dry holes, the failure to produce oil and gas in commercial
quantities, the inability to fully produce discovered reserves and the inability
to enhance production from existing wells.

IF WE SHOULD MAKE FUTURE ACQUISITIONS OF OIL AND GAS PROPERTIES WHERE WE BELIEVE
COMMERCIALLY RECOVERABLE QUANTITIES OF OIL AND NATURAL GAS EXIST, THESE
ACQUISITIONS CARRY UNKNOWN RISKS INCLUDING POTENTIAL UNSUCCESSFUL DRILLING
ACTIVITIES OR ENVIRONMENTAL PROBLEMS.

         We expect to continue to evaluate and pursue acquisition opportunities
available on terms we consider favorable in order to replace and increase our
reserves. Successful acquisition of producing properties generally requires
accurate assessments of recoverable reserves, future oil and gas prices,
operating costs, potential environmental and other liabilities and other
factors. Such assessments are necessarily inexact, and as estimates, their
accuracy is inherently uncertain. We cannot assure you that we will successfully
consummate any acquisition, that we will be able to acquire producing oil and
gas properties that contain economically recoverable reserves or that any
acquisition will be profitably integrated into our operations. Our inability to
achieve these objectives will restrict our growth and the development of our oil
and gas reserves. In addition, acquiring producing oil and gas properties may
increase our potential exposure to liabilities and costs for environmental and
other problems existing on such properties. Although we perform a review of the
acquired properties that we believe is consistent with industry practice, such
reviews are inherently incomplete and inexact.

ESTIMATING RESERVES AND FUTURE NET REVENUES INVOLVES UNCERTAINTIES AND OIL AND
GAS PRICE DECLINES MAY LEAD TO IMPAIRMENT OF OIL AND GAS ASSETS.

         At December 31, 2003, based on the report of Netherland, Sewell and
Associates, Inc., we claimed total estimated proved reserves of 224.96 MBble of
oil and gas. We are currently seeking to develop further producing wells on our
Bayou Couba properties. During 2002, we were able to return to production 5
(4.06 net) well bores drilled by prior owners on the Couba properties we
acquired. As of December 31, 2003, we had successfully completed 6 (2.19 net)
wells. As of that time, our combined production from all our producing wells was
approximately 400 (120 net) barrels of oil equivalent per day. Production from
our existing wells is subject to fluctuation from time to time based upon the
zones of the wells where we are obtaining production. There can be no assurance
that we will be successful in our development activities or that as a
consequence we will claim any material amounts of additional proven reserves as
a result of these and further drilling activities. In any event, there are
numerous uncertainties inherent in estimating quantities of proved reserves,
including many factors beyond our control.

         Reserve information provided in this Annual Report and that we may
provide in the future will represent estimates based on reports prepared by our
independent


                                       41

<PAGE>

petroleum engineers, as well as internally generated reports. Petroleum
engineering is not an exact science. Information relating to proved oil and gas
reserves is based upon engineering estimates derived after analysis of
information we furnish or furnished to us by the operator of the property.
Estimates of economically recoverable oil and gas reserves and of future net
cash flows necessarily depend upon a number of variable factors and assumptions,
such as historical production from the area compared with production from other
producing areas, the assumed effects of regulations by governmental agencies and
assumptions concerning future oil and gas prices, future operating costs,
severance and excise taxes, capital expenditures and workover and remedial
costs, all of which may in fact vary considerably from actual results. Oil and
gas prices, which fluctuate over time, may also affect proved reserve estimates.
For these reasons, estimates of the economically recoverable quantities of oil
and gas attributable to any particular group of properties, classifications of
such reserves based on risk of recovery and estimates of the future net cash
flows expected there from prepared by different engineers or by the same
engineers at different times may vary substantially. Actual production, revenues
and expenditures with respect to our reserves will likely vary from estimates,
and such variances may be material. Either inaccuracies in estimates of proved
undeveloped reserves or the inability to fund development could result in
substantially reduced reserves. In addition, the timing of receipt of estimated
future net revenues from proved undeveloped reserves will be dependent upon the
timing and implementation of drilling and development activities estimated by us
for purposes of the reserve report.

         Quantities of proved reserves are estimated based on economic
conditions in existence in the period of assessment. Lower oil and gas prices
may have the impact of shortening the economic lives on certain fields because
it becomes uneconomic to produce all recoverable reserves on such fields, thus
reducing proved property reserve estimates. If such revisions in the estimated
quantities of proved reserves occur, it will have the effect of increasing the
rates of depreciation, depletion and amortization on the affected properties,
which would decrease earnings or result in losses through higher depreciation,
depletion and amortization expense. The revisions may also be sufficient to
trigger impairment losses on certain properties that would result in a further
non-cash charge to earnings.

OUR RELIANCE ON A LIMITED NUMBER OF KEY MANAGEMENT PERSONNEL IMPOSES RISKS ON US
THAT WE WILL HAVE INSUFFICIENT MANAGEMENT PERSONNEL AVAILABLE IF THEIR SERVICES
ARE UNAVAILABLE.

         We are dependent upon the services of our President and Chief Executive
Officer, Michael K. Paulk, and Vice President, Finance and Chief Financial
Officer, Steven P. Ensz. The loss of either of their services could have a
material adverse effect upon us. The loss of the services of such persons would,
in all likelihood, require us to seek the services of one or more other persons
who would be less familiar with our oil and gas properties, our business
objectives and methods and would increase the risk that our activities would be
unsuccessful. We currently do not have employment agreements with either of such
persons.


                                       42

<PAGE>

DRILLING FOR OIL AND NATURAL GAS AND OPERATING OIL AND NATURAL GAS FIELDS
INVOLVES MATERIAL RISKS INCLUDING THE RISK THAT NO COMMERCIALLY PRODUCTIVE
RESERVOIRS WILL BE ENCOUNTERED; WE HAVE UNINSURED RISKS.

         Drilling activities are subject to many risks, including the risk that
no commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by us will be productive or that we will
recover all or any portion of our investment. Drilling for oil and gas may
involve unprofitable efforts, not only from dry wells, but from wells that are
productive but do not produce sufficient net revenues to return a profit after
drilling, operating and other costs. The cost of drilling, completing and
operating wells is often uncertain. Our drilling operations may be curtailed,
delayed or canceled as a result of numerous factors, many of which are beyond
our control, including economic conditions, mechanical problems, title problems,
weather conditions, compliance with governmental requirements and shortages or
delays of equipment and services. Our future drilling activities may not be
successful and, if unsuccessful, such failure may have a material adverse effect
on our future results of operations or financial condition.

         In addition to the substantial risk that wells drilled will not be
productive, hazards such as unusual or unexpected geologic formations,
pressures, downhole fires, mechanical failures, blowouts, cratering, explosions,
uncontrollable flows of natural gas, oil or well fluids, pollution and other
physical and environmental risks are inherent in oil and gas exploration and
production. These hazards could result in substantial losses to us due to injury
and loss of life, severe damage to and destruction of property and equipment,
pollution and other environmental damage and suspension of operations. As
protection against operating hazards, we maintain insurance coverage against
some, but not all, potential losses, as is common in the oil and natural gas
industry. We do not fully insure against all risks associated with our business
either because such insurance is not available or because the cost thereof is
considered prohibitive. The occurrence of an event that is not covered, or not
fully covered, by insurance could have a material adverse effect on our
financial condition and results of operations.

RISKS RELATING TO THE MARKET FOR OUR SECURITIES

ABSENCE OF A U.S. PUBLIC MARKET FOR OUR COMMON SHARES.

         Our common shares have no trading market in the United States, and
there can be no assurance as to the liquidity of any markets that may develop
for the common shares, the ability of the holders of common shares to sell their
common shares in the United States or the price at which holders would be able
to sell their common shares. Future trading prices of the common shares will
depend on many factors, including, among others, our operating results and the
market for similar securities.


                                       43

<PAGE>


CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1996

         With the exception of historical matters, the matters we discussed
below and elsewhere in this Annual Report are "forward-looking statements" as
defined under the Securities Exchange Act of 1934, as amended that involve risks
and uncertainties. The forward-looking statements appear in various places
including under the headings Annual Report Summary, Risk Factors, Management's
Discussion and Analysis of Financial Condition or Plan of Operation, and Our
Business. These risks and uncertainties relate to our capital requirements,
business strategy, ability to raise capital and fund our oil and gas well
drilling and development plans, our ability to fund the repayment of our
outstanding indebtedness, our ability to attain and maintain profitability and
cash flow and continue as a going concern, our ability to increase our reserves
of oil and gas through drilling activities and acquisitions, our ability to
enhance and maintain production from existing wells and successfully develop
additional producing wells, our access to debt and equity capital and the
availability of joint venture development arrangements, our ability to remain in
compliance with the terms of any agreements pursuant to which we borrow money
and to repay the principal and interest when due, our estimates as to our needs
for additional capital and the times at which additional capital will be
required, our expectations as to our sources for this capital and funds, our
ability to successfully implement our business strategy, our ability to
identify, acquire and integrate successfully any additional producing oil and
gas properties we acquire and operate such properties profitably, our ability to
maintain compliance with covenants of our loan documents and other agreements
pursuant to which we issue securities or borrow funds and to obtain waivers and
amendments when and as required, our ability to borrow funds or maintain levels
of borrowing availability under our borrowing arrangements, our ability to meet
our intended capital expenditures, our statements about quantities of production
of oil and gas as it implies continuing production rates of those levels, proved
reserves or borrowing availability based on proved reserves and our future net
cash flows and their present value.

         Readers are cautioned that the risk factors and uncertainties referred
to above, as well as the risk factors described elsewhere in this Annual Report,
in some cases have affected, and in the future could affect, our actual results
and could cause our actual consolidated results during 2004 and beyond, to
differ materially from those expressed in any forward-looking statements made by
or on our behalf.

ITEM 7 - FINANCIAL STATEMENTS:
-----------------------------

         The response to this Item is included in a separate section of this
report. See page F-1.


                                       44

<PAGE>

ITEM 8 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
------------------------------------------------------------------------
FINANCIAL DISCLOSURE:
--------------------

         On February 12, 2002, PricewaterhouseCoopers, LLP, Vancouver, Canada,
was engaged to audit Gothic's consolidated financial statements for the year
ended December 31, 2001 and 2000. The decision to engage PricewaterhouseCoopers
LLP was approved by our Board of Directors.

         The firm of KPMG LLP, Vancouver, Canada, audited the financial
statements of Gothic for the years ended December 31, 2000 and 1999. On February
12, 2002, KPMG LLP's appointment as principal accountants was terminated. The
audit report of KPMG LLP for the two years ended December 31, 2000 did not
contain any adverse opinion or disclaimer of opinion or modification as to
uncertainty, audit scope or accounting principles.

         During the two years ended December 31, 2000 and through February 12,
2002, neither we nor anyone on our behalf consulted with PricewaterhouseCoopers,
LLP regarding the matters referred to in Item 304(a)(2) of Regulation S-B under
the Securities Exchange Act of 1934, as amended. During the two fiscal years
ended December 31, 2000 and through February 12, 2002, Gothic did not have any
disagreements with KPMG LLP on any matter of accounting principles or practices,
financial statement disclosure or auditing scope or procedures which
disagreements, if not resolved to their satisfaction, would have caused them to
make reference in connection with their opinion to the subject matter of the
disagreement.


                                       45

<PAGE>


                                    PART III

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

DIRECTORS, EXECUTIVE OFFICERS AND SIGNIFICANT EMPLOYEES

         The following table contains information concerning the current
Directors, executive officers and significant employees of the Company:

               NAME                   AGE                    POSITION
--------------------------------------------------------------------------------
DIRECTORS AND EXECUTIVE OFFICERS:

Michael K. Paulk                      55     President and Director

Steven P. Ensz                        52     Vice President, Finance, and Chief
                                             Financial Officer and Director

Brian E. Bayley(1)                    51     Director
John K. Campbell(1)                   69     Director

Jules Poscente                        75     Director

SIGNIFICANT EMPLOYEES:
Bennett G. Shelton                    47     Manager of Land and Contract
                                             Administration
Richard O. Mulford                    51     Manager of Operations
Robert G. Snead                       65     Exploitation Manager

--------------------
         (1)      Member of our Audit Committee

         Each Director of our company has been elected to serve until our next
annual meeting of stockholders and until his successor has been elected and
qualified.

         MICHAEL K. PAULK: Mr. Paulk was elected President and Director of our
company in July 2001. From October 1994 to January 2001, when it was sold to
Chesapeake Energy Corporation, he was the President and a Director of Gothic
Energy Corporation ("GEC"). GEC is neither a predecessor nor affiliate of either
us or our subsidiary, Gothic and there was no affiliation between Gothic and GEC
prior to January 2001. GEC was engaged, until its acquisition by Chesapeake
Energy Corporation in January 2001, in the acquisition, development, exploration
and production of natural gas and oil. Mr. Paulk has been engaged in the oil and
gas industry for more than fifteen years.

         STEVEN P. ENSZ: Mr. Ensz has been Vice-President, Finance and Chief
Financial Officer of our company since July 2001 and is responsible for our
financial activities. From March 1998 to January 2001, he held a similar
position with GEC. From July 1991 to February 1998, he was Vice-President,
Finance of Anglo-Suisse, Inc., an oil and natural gas exploration and producing
company. He has held various positions within the


                                       46

<PAGE>

energy industry, including President of Waterford Energy, an independent oil and
gas producer, for more than the past 18 years. He is a certified public
accountant.

         BRIAN E. BAYLEY: Mr. Bayley was elected a Director of the Company in
June 2001. Since June 30, 2003, Mr. Bayley has been the President and Chief
Executive Officer of Quest Capital Corp. Quest Capital Corp. trades on the
Toronto Stock Exchange under the symbol QC.A and QC.B. Quest Capital Corp. is a
merchant bank that provides financial services to small and mid-cap companies
operating primarily in North America. He is currently President and Director of
Quest Management Corp., a management company that is wholly owned by Quest
Capital Corp. since December 1996. Quest Management Corp. provides various
consulting, administrative, management and related services to publicly-traded
companies. Mr. Bayley currently serves as Director and/or officer on numerous
other public companies, none of which is a reporting issuer under U.S.
securities laws. None of the other companies Mr. Bayley is affiliated with are
affiliates of ours. Mr. Bayley is a Director of TransAtlantic Petroleum (USA)
Corp., which provided financing to our company in March 2003 and purchased
Debentures in October 2003.

         JOHN K. CAMPBELL: Mr. Campbell has been a Director of our company since
April 2000 and was President of Gothic from April 2000 to July 2001. Mr.
Campbell has been the President and Director of TransAmerica Industries Ltd.
since 1986.

         JULES POSCENTE: Mr. Poscente was elected a Director of our company in
October 2003. Mr. Poscente has been the Chairman, President and Chief Executive
Officer of Eurogas Corporation since prior to 1995. It is engaged in oil and gas
exploration and development. Mr. Poscente was elected a Director pursuant to the
terms of the transaction in which our $12.0 million of Debentures were issued in
October 2003.

SIGNIFICANT EMPLOYEES:

         BENNETT G. SHELTON: Mr. Shelton has been Manager of Land and Contract
Administration since June 2001. From May 1995 through January 2001, he was
employed by GEC as Vice President of Land and Contract Administration. From
August 1994 to May 1995, he was a Senior Landman with AEOK. He has been employed
in land and acquisition management and as a landman since approximately 1981.

         RICHARD O. MULFORD: Mr. Mulford has been Manager of Operations since
June 2001. From April 1995 to November 1998, he was employed as Operations
Manager of GEC and from November 1998 to January 2001 he was employed as Vice
President of Operations of GEC. He has been employed in the oil and natural gas
industry since 1978.

         ROBERT G. SNEAD: Mr. Snead has been our Exploitation Manager since June
2001 and served in the same position with GEC on a full-time consulting basis
since April 1997. Between early 1994 and April 1997, he was employed as an
independent geologist and from 1985 to 1994 was the Senior Vice-President/
Exploration Manager of LOGO, Inc., an oil and natural gas well operating
company.


                                       47

<PAGE>

         Messrs. Paulk and Ensz, as the founders of American Natural Energy
Corporation, may be deemed our founders.

Audit Committee and Audit Committee Financial Expert:

         As of January 31, 2004, the members of our Audit Committee of our Board
of Directors are Messrs. Bayley (Chairman), and Campbell. Messrs. Bayley and
Campbell have been members of the Audit Committee since 2002. Our securities are
not listed on any national securities exchange or listed on an automated
inter-dealer quotation system.

         Our Audit Committee, among other things, meets with our independent
accountants to review our accounting policies, internal controls and other
accounting and auditing matters; makes recommendations to the Board of Directors
as to the engagement of independent accountants; and reviews the letter of
engagement and statement of fees relating to the scope of the annual audit and
special audit work which may be recommended or required by the independent
accountants.

         Our Board of Directors has determined that we do not have an Audit
Committee Financial Expert serving on our Audit Committee. We do not have an
Audit Committee Financial Expert serving on our Audit Committee because at this
time the limited magnitude of our revenues and operations does not, in the view
of our Board of Directors, justify or require that we obtain the services of a
person having the attributes required to be an Audit Committee Financial Expert
on our Board of Directors and Audit Committee. The Board of Directors may in the
future determine that a member elected to the Board in the future has the
attributes to be determined to be an Audit Committee Financial Expert.

Code of Ethics:

         We have adopted a Code of Ethics that applies to our principal
executive officer and principal financial and accounting officer. A copy of our
Code of Ethics has been filed as an exhibit to this Annual Report.

ITEM 10 - EXECUTIVE COMPENSATION:
--------------------------------

         The following table sets forth the annual and long-term compensation
paid during our three fiscal years ended December 31, 2003 to our chief
executive officer and all other executive officers who received compensation
exceeding $100,000 and who served in such capacities at December 31, 2003.


                                       48

<PAGE>

                           SUMMARY COMPENSATION TABLE
                               ANNUAL COMPENSATION
<TABLE>
<CAPTION>

                                                                                                COMPENSATION
                                                                                      ----------------------------------
                                                                            OTHER          LONG-TERM        ALL OTHER
         NAME AND                              ANNUAL                      ANNUAL        AWARDS/ OPTION        COMP.
    PRINCIPAL POSITION          YEAR           SALARY          BONUS        COMP.             (#)
------------------------------------------------------------------------------------------------------------------------

<S>                             <C>         <C>                 <C>          <C>            <C>             <C>
Michael K. Paulk                2003        $120,000(2)         -0-          -0-              -0-               -0-
                                2002         $90,000(1)         -0-          -0-              -0-               -0-
                                2001            -0-             -0-          -0-            325,000         $35,000(3)

Steven P. Ensz                  2003        $120,000(2)         -0-          -0-              -0-               -0-
                                2002         $90,000(1)         -0-          -0-              -0-               -0-
                                2001            -0-             -0-          -0-            325,000         $35,000(3)

</TABLE>
------------------------
(1)  Of this amount, $45,000 was unpaid at December 31, 2002 and 2003 and is
     included in accrued liabilities.

(2)  Of this amount, $40,000 was unpaid at December 31, 2003 and is included in
     accrued liabilities.

(3)  This sum represents amounts paid for services prior to the January 2002
     corporate reorganization resulting in American Natural Energy Corporation
     becoming our parent corporation.

STOCK OPTION EXERCISES DURING THE YEAR ENDED DECEMBER 31, 2003 AND HOLDINGS AT
DECEMBER 31, 2003.

       The following table provides information with respect to the above named
executive officer regarding options held at December 31, 2003. No options were
granted to such persons during the year ended December 31, 2003.

<TABLE>
<CAPTION>
                                                      NUMBER OF UNEXERCISED OPTIONS      VALUE OF UNEXERCISED IN-THE-MONEY
                                                           AT DECEMBER 31, 2003           OPTIONS AT DECEMBER 31, 2003(1)
                                                      ------------------------------     ---------------------------------
      NAME         SHARES ACQUIRED ON      VALUE      EXERCISABLE      UNEXERCISABLE      EXERCISABLE    UNEXERCISABLE
                        EXERCISE         REALIZED
--------------------------------------------------------------------------------------------------------------------------
<S>                       <C>              <C>          <C>                 <C>            <C>                  <C>
Michael K. Paulk          -0-              -0-          325,000             -0-            $256,750             -0-

Steven P. Ensz            -0-              -0-          325,000             -0-            $256,750             -0-
</TABLE>
----------------------
(1)   Based on the difference between the option exercise price and the closing
      bid price on December 31, 2003 of $1.11 per share.

         We do not have any employment contracts with any of our executive
officers or other significant employees.

         Our Directors do not receive any cash compensation for serving in that
capacity; however, they are reimbursed for their out-of-pocket expenses in
attending meetings. Pursuant to the terms of our 2001 Stock Incentive Plan, each
non-employee Director who is first elected or appointed after February 1, 2002
automatically receives an option grant for 50,000 shares on the date such person
joins the Board. In addition, on the date of each annual stockholder meeting,
provided such person has served as a non-employee Director for at least six
months, each non-employee Board member who is to continue to serve as a
non-employee Board member will automatically be granted an option to purchase
5,000 shares. Each such option has a term of ten years, subject to earlier


                                       49

<PAGE>

termination following such person's cessation of Board service, and is subject
to certain vesting provisions.

ITEM 11 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS:

         The following table sets forth certain information regarding beneficial
ownership of our common stock as of March 19, 2004 (a) by each person who is
known by us to own beneficially more than five percent (5%) of our common
shares, (b) by each of our Directors and officers, and (c) by all Directors and
officers as a group. As of March 19, 2004, we had 26,154,546 common shares
outstanding.

                                                                   PERCENTAGE OF
                                              NUMBER OF SHARES     OUTSTANDING
         NAME AND ADDRESS (1)(2)                   OWNED             SHARES(3)
--------------------------------------------------------------------------------

Mike K. Paulk                                   1,400,000(4)           5.4%

Steven P. Ensz                                  1,750,000(5)           6.7%

Brian E. Bayley                                   916,500(6)           3.5%
Quest Management Corp.
Suite 300 - 570 Granville Street
Vancouver, BC V6C 3P1

John K. Campbell                                  225,000(7)           0.9%
750 West Pender Street - Suite 710
Vancouver, BC V6C 2T7

Jules Poscente                                    220,000(8)           0.8%
440, 333 Fifth Avenue, SW
Calgary, Alberta  T2P 3B6

Bonanza Energy Ltd.                             1,311,111(9)           5.0%
#1550, 340 - 12th Avenue, SW
Calgary, Alberta  T2R 1L5

Commonwealth Canadian Balanced Fund(10)         1,666,667(11)          6.4%
40 King Street, West
55th Floor
Toronto, Ontario  M5H 4A9

TransAtlantic Petroleum Corp(12)                6,842,795(13)         26.2%
1550, 340 - 12th Avenue, SW
Calgary, Alberta  T2R 1L5

All Directors and officers as a group           5,822,611             26.5%
persons)(6)

---------------------------
(1)      This tabular information is intended to conform with Rule 13d-3
         promulgated under the Securities Exchange Act of 1934 relating to the
         determination of beneficial ownership of securities. The tabular
         information gives effect to the exercise of warrants or options
         exercisable within 60 days of the date of this table owned in each case
         by the person or group whose


                                       50

<PAGE>

         percentage ownership is set forth opposite the respective percentage
         and is based on the assumption that no other person or group exercise
         their option.
(2)      Unless otherwise indicated, the address for each of the above is c/o
         American Natural Energy Corporation, 7030 South Yale, Suite 404, Tulsa,
         Oklahoma 74136.
(3)      The percentage of outstanding shares calculation is based upon
         26,154,546 shares outstanding as of October 31, 2003, except as
         otherwise noted.
(4)      Includes 325,000 shares issuable at an exercise price of $0.32 on
         exercise of an option. Of Mr. Paulk's shares, 141,667 shares are held
         subject to a Pooling Agreement described below.
(5)      Includes 325,000 shares issuable at an exercise price of $0.32 on
         exercise of an option. Of Mr. Ensz's shares, 141,667 shares are held
         subject to a Pooling Agreement described below.
(6)      Includes 200,000 shares issuable at an exercise price of $0.32 on
         exercise of an option. Excludes 60,000 shares held by Mr. Bayley's wife
         and 50,000 shares held by a trust for the benefit of Mr. Bayley's minor
         children, as to all of which Mr. Bayley disclaims a beneficial
         interest. Also excludes 181,632 issued and outstanding shares and
         1,111,111 shares issuable on conversion of Debentures held by Quest, as
         to which shares and Debentures Mr. Bayley disclaims a beneficial
         interest.
(7)      Includes 25,000 shares held by Mr. Campbell, 150,000 shares issuable at
         an exercise price of $0.47 on exercise of an option and 50,000 shares
         issuable at an exercise price of $0.68 on exercise of an option.
(8)      Includes 20,000 shares held jointly by Mr. Poscente and his wife and
         200,000 shares issuable on exercise of options at an exercise price of
         $0.68 per share.
(9)      The shares are issuable on conversion of $500,000 principal amount of
         our Debentures at a conversion price of $0.45 per share, subject to
         adjustment. The Debentures are held by Bonanza Energy Ltd. which is
         wholly owned by the estate of Mr. John Fleming. Also includes 200,000
         shares issuable on exercise of options held by Mr. Fleming's estate
         exercisable at $0.68 per share.
(10)     Commonwealth Canadian Balanced Fund is an open-ended mutual fund trust
         created under the laws of Canada and regulated under the laws of the
         Province of Ontario, Canada. It is managed by Goodman and Company
         Investment Counsel, Ltd. which may be deemed to be the beneficial owner
         of the shares as defined in Rule 13d-3. However, Goodman and Company
         Investment Counsel, Ltd. disclaims a beneficial interest in the shares.
(11)     Shares issuable on conversion of $750,000 principal amount of our
         Debentures.
(12)     TransAtlantic Petroleum Corp. is a corporation whose shares are
         publicly traded on the Toronto Stock Exchange under the symbol TNP.U.
         Its Directors are George Plewes, Brian Bayley and Alan C. Moon. Such
         persons will direct the voting and divestiture of our shares by
         TransAtlantic. However, such persons do not have a pecuniary interest
         in our shares other than as shareholders of TransAtlantic.
(13)     Includes 176,129 shares held by TransAtlantic and 6,666,666 shares
         issuable on conversion of $3.0 million principal amount of our
         Debentures. Mr. Fleming, formerly a Director of our company, was also
         President, Chief Executive Officer and a Director of TransAtlantic
         Petroleum Corp. Mr. Fleming disclaimed a beneficial interest in the
         Debentures held by TransAtlantic as well as the shares issuable on
         conversion. Mr. Bayley, also one of our Directors, is also a Director
         of TransAtlantic and also disclaims a beneficial interest in the
         Debentures and shares.

         Pooling Agreement. Of the shares held by each of Messrs. Paulk and
Ensz, 425,000 of such shares, as well as 50,000 shares held by each of Robert G.
Snead, Bennett G. Shelton and Richard Mulford, employees of our company, are
held pursuant to the terms of an agreement that provides that one-third of such
shares are released from escrow and the restrictions of the agreement on each of
July 17, 2002, July 17, 2003, and July 17, 2004. Under the terms of the escrow
agreement, the stockholders are prohibited from selling, dealing in, assigning
or transferring the shares during the restricted period. The agreement
terminates with respect to all the shares on July 17, 2004. In the event of a
change of control of our company, evidenced by a change of a majority of the
Board of Directors, the shares are then released from the restrictions of the
agreement. The stockholders retain the right to vote the shares and to receive
dividends during the term of the agreement. ANEC is not a party to this
agreement, however, the terms of this agreement could affect the number of
shares of our common stock available for sale from time to time.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

         We have one equity compensation plan for our employees, Directors and
consultants pursuant to which options, rights or shares may be granted or
issued. It is referred to as our 2001 Stock Incentive Plan. See Note 12 to the
Notes to Financial Statements for further information on the material terms of
these plans.


                                       51

<PAGE>


         The following table provides information as of December 31, 2003 with
respect to our compensation plans (including individual compensation
arrangements), under which securities are authorized for issuance aggregated as
to (i) compensation plans previously approved by stockholders, and (ii)
compensation plans not previously approved by stockholders:

Equity Compensation Plan Information

<TABLE>
<CAPTION>
                                        (a)                    (b)                          (c)
PLAN CATEGORY                NUMBER OF SECURITIES TO    WEIGHTED-AVERAGE           NUMBER OF SECURITIES
                             BE ISSUED UPON EXERCISE    EXERCISE PRICE OF          REMAINING AVAILABLE FOR
                             OF OUTSTANDING OPTIONS,    OUTSTANDING OPTIONS,       FUTURE ISSUANCE UNDER
                             WARRANTS AND RIGHTS        WARRANTS AND RIGHTS        EQUITY COMPENSATION
                                                                                   PLANS (EXCLUDING
                                                                                   SECURITIES REFLECTED IN
                                                                                   COLUMN (a))
----------------------------------------------------------------------------------------------------------
<S>                                  <C>                       <C>                        <C>
Equity compensation plans            2,000,000                 $0.41                      3,000,000
approved by security
holders

Equity compensation plans               -0-                        -0-                       -0-
not approved by security
holders

                             -----------------------------------------------------------------------------
Total                                2,000,000                    $0.41                    3,000,000
</TABLE>



ITEM 12 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS:
--------------------------------------------------------

         On June 6, 2001, each of Michael K. Paulk and Steven P. Ensz loaned us
$100,000 evidenced by our promissory note bearing interest at 6% per annum and
due on May 31, 2002. These notes have been repaid with all accrued interest.

         During the year 2001, we paid consulting, management and other
reimbursable expenses aggregating approximately $19,750 to Quest Management
Corp. of which Mr. Bayley, one of our Directors, is President. Payment of
expenses in 2002 aggregated $20,329. No payments were made to Quest Management
Corp. in 2003. These expenses primarily relate to compliance with regulatory
filing requirements with the securities commissions of the Provinces of Canada
where our securities are able to be traded.

         In September 2002, Mr. Paulk loaned to us $40,000. The loan was due on
demand and accrued interest at the Bank One prime rate (4% per annum as of
August 8, 2003), a rate equal to the interest rate Mr. Paulk paid on the funds
borrowed by him. The loan was not collateralized. The proceeds of the loan were
used by us for working capital. The loan was repaid in November 2003.


                                       52

<PAGE>

         In March 2003, we completed a $2.5 million borrowing from Quest
Investment Corporation (a wholly-owned subsidiary of Quest Capital Corp.), as
principal and agent, for working capital and repayment of secured debt. The $2.5
million was due to be repaid on October 31, 2003 and bore interest at 12% per
annum (effective rate 22.0%). The loan was secured by all our oil and gas
properties and undeveloped leaseholds. This loan was repaid in October 2003. The
lenders received 688,000 shares of our common stock as compensation for making
the loan. Mr. Brian Bayley, one of our Directors, is a Director and the Chief
Executive Officer of Quest Capital Corp.

         In March 2003, we entered into a funding arrangement with TransAtlantic
Petroleum (USA) Corp. whereby TransAtlantic agreed to advance to us up to $2.0
million, of which up to $1.8 million was used to fund our share of the drilling
and completion costs for the four initial wells we drilled in St. Charles
Parish. In exchange, TransAtlantic received a $2.0 million production payment
payable out of 75% of the net revenues from the wells drilled with the funds
advanced. In addition, also in exchange for the availability of the funds for
drilling and completion and an additional $200,000 of funding, TransAtlantic
received a 10% interest in our Bayou Couba Lease and our lease with the State of
Louisiana. Under the agreements, TransAtlantic has the right to acquire a 10%
participation in any additional leasehold interests we acquire in our
approximately 23.138 square mile Bayou Couba salt dome development area. Our
obligations to TransAtlantic were collateralized by a lien against our interest
in the four initial wells and their hydrocarbon production. At September 30,
2003, the entire $1.8 million and $200,000 fundings had been advanced and
$327,350 of the production payment had been paid to TransAtlantic. The remaining
outstanding balance on the production payment was paid in October 2003. Because
the transaction involved the sale of a production payment to TransAtlantic,
there was no stated interest rate on the advances. Mr. Brian Bayley, a Director
of our company, is also a Director of TransAtlantic. We imputed interest in the
amount of $461,544 on the $2,000,000 in our financial statements.

         In October 2003, we completed the private sale of $12.0 million
principal amount of 8% Convertible Secured Debentures (the "Debentures") due
September 30, 2005. The Debentures bear interest payable quarterly commencing
December 31, 2003 at 8% per annum. The outstanding principal of the Debentures
is convertible into shares of our Common Stock at any time prior to maturity at
a conversion price of $0.45 per share, subject to anti-dilution adjustment, and
the Debentures are redeemable by us at any time after October 1, 2004 if the
average weighted price per share on the TSX Venture Exchange for a 20
consecutive trading day period prior to the date notice of redemption is given
has exceeded 166-2/3% of the conversion price. The Debentures are collateralized
by substantially all of our assets. A finder's fee in the amount of $360,000 was
paid in connection with the financing. We used approximately $5.9 million of the
proceeds of the financing for the repayment of secured debt. The secured
indebtedness repaid included $2.5 million to Quest Capital Corp., which bore
interest at 12% per annum, was due October 31, 2003, and was collateralized by a
first lien on substantially all our assets. In addition, we paid out of the
proceeds the remaining balance of $1.7 million on a production payment owing to
TransAtlantic Petroleum (USA) Corp. TransAtlantic retained its 10% participation
right in our AMI with ExxonMobil Corp. which was


                                       53

<PAGE>

granted as partial consideration for the $2.0 million financing entered into in
March 2003 described above.

         In connection with and as conditions to the Debenture financing, Mr.
Jules Poscente, Chairman, President, Chief Executive Officer and a Director of
Eurogas Corporation, of Calgary, Alberta, was elected to our Board of Directors.
Mr. John Fleming was also elected a Director at that time. Mr. Fleming died on
March 3, 2004. Under the terms of the Indenture under which the Debentures were
issued, if Mr. Poscente or Mr. Fleming, or any replacement Director for either
of them, ceases at any time to be two of our directors on our board and any of
the following occurs:

         o  such Director has so ceased to be a Director as a result of a
            resolution passed or an election of Directors approved by our
            shareholders; or

         o  we fail to give notice to the Trustee and the holders of the
            Debentures that one or more of such Directors has ceased to be a
            Director of our corporation within five days after the date such
            person ceased to be such a director; or

         o  we fail to appoint or elect an individual, who has been approved as
            a replacement Director by resolution of the Debentureholders and who
            has consented to act as such, to fill a vacancy in such two
            Directors' positions within five days of such resolution being
            passed by the Debentureholders and we receive notice thereof;

then a default has occurred under the Indenture which gives to the Trustee and
the holders of the Debentures the right to accelerate the due date on the
indebtedness. Under such circumstances the Trustee, on behalf of the holders of
the Debentures, may enforce its rights to foreclose on the collateral for the
Debentures which includes substantially all of our oil and gas properties and
other assets. As of March 19, 2004, no individual had been elected to our Board
of Directors in place of Mr. Fleming.

         Purchasers of the Debentures included TransAtlantic Petroleum Corp., in
the amount of $3.0 million principal amounts, Quest Capital Corp., in the amount
of $500,000 principal amount. Mr. Fleming was formerly the Chairman of
TransAtlantic. Mr. Brian Bayley, who has been a Director of our company since
June 2001, is also President and Chief Executive Officer of Quest Capital Corp.
and a Director of TransAtlantic. In addition, Bonanza Energy Ltd., a corporation
of which Mr. Fleming was the sole shareholder, purchased $500,000 principal
amount of Debentures. Out of the proceeds of the sale of the Debentures,
TransAtlantic was paid $1.7 million in payment in full of a production payment
owing to it and Quest Capital Corp. was paid $2.5 million in repayment of a
loan.


                                       54

<PAGE>


ITEM 13 - EXHIBITS AND REPORTS ON FORM 8-K:
------------------------------------------

(a)      EXHIBITS:
EXHIBIT                                   DESCRIPTION
------------------

2.0                  Second Amended Joint Plan of Reorganization Proposed by
                     Couba Operating Company, American Natural Energy
                     Corporation and Gothic Resources Inc. filed in the United
                     States Bankruptcy Court, Western District of Oklahoma. Case
                     No. 00-11837-W (Chapter 11)(4)

2.1                  Order Confirming Plan, filed November 16, 2001 with U.S.
                     Bankruptcy Court, Western District of Oklahoma(1)

3.1                  Certificate of Incorporation of American Natural Energy
                     Corporation(1)

3.2                  Certificate of Amendment filed March 23, 2001(1)

3.3                  Certificate of Amendment filed December 20, 2001(1)

3.4                  By-laws(1)

10.1                 2001 Stock Incentive Plan(1)

10.2                 Omitted as no longer an operative agreement.

10.3                 Leasehold Acquisition and Development Agreement with The
                     Wiser Oil Company(1)

10.4                 Assignment of Oil, Gas and Mineral Lease dated as of
                     February 18, 2002 relating to State Lease Number 17353.(1)

10.5                 Omitted as no longer an operative agreement.

10.6                 Omitted as no longer an operative agreement.

10.7.1               Omitted as no longer an operative agreement.

10.7.2               Omitted as no longer an operative agreement.

10.7.3               Purchase and Exploration Agreement dated March 10, 2003
                     between the Registrant and TransAtlantic Petroleum (USA)
                     Corp.(4)

10.8.1               Form of Subscription Agreement to purchase the Registrant's
                     8% Convertible Secured Debenture due September 30, 2005.(2)

10.8.2               Trust Indenture dated as of October 8, 2003 between the
                     Registrant and Computershare Trust Company of Canada(2)

10.9.1               Development Agreement dated November 22, 2002 between the
                     Registrant and ExxonMobil Corporation(3)


                                       55

<PAGE>
EXHIBIT                                  DESCRIPTION
-------                                  -----------

10.9.2               Amendment dated December 19, 2003 to Development Agreement
                     dated November 22, 2002 between the Registrant and
                     ExxonMobil Corporation(3)

14.1                 Code of Ethics(4)

21.0                 Subsidiaries of the Registrant

               Name                      State or Jurisdiction of Incorporation
               ----                      --------------------------------------
               Gothic Resources, Inc.    Canada Business Corporations Act
               Couba Operating Company   Oklahoma

31.1                 Certification of President and Chief Executive Officer
                     Pursuant to Rule 13a-14(a)(4)

31.2                 Certification of Chief Financial Officer Pursuant to Rule
                     13a-14(a)(4)

32.1                 Certification of President and Chief Executive Officer
                     Pursuant to Section 1350 (furnished, not filed)(4)

32.2                 Certification of Chief Financial Officer Pursuant to
                     Section 1350 (furnished, not filed)(4)

-------------------
(1)  Filed as an Exhibit to the Registrant's registration statement on Form
     10-SB filed on August 12, 2002 and amended on July 29, 2003. (File No.
     0-18956).
(2)  Filed as an Exhibit to the Registrant's Quarterly Report on Form 10-QSB for
     the quarter ended September 30, 2003. (File No. 0-18956).
(3)  Filed with Amendment No. 1 to Registration Statement on Form SB-2 filed
     February 6, 2004 (File No. 333-111244).
(4)  Filed with this Annual Report on Form 10-KSB for the year ended December
     31, 2003.

         (b) (1) REPORTS ON FORM 8-K

                  During the quarter ended December 31, 2003, we filed Current
Reports on Form 8-K as follows:

DATE OF CURRENT REPORT                      ITEM REPORTED
----------------------                      -------------
September 10, 2003         Item 7. Financial Statements and Exhibits (press
                           release dated September 10, 2003)
October 9, 2003            Item 7. Financial Statements and Exhibits (press
                           release dated October 9, 2003)


                                       56

<PAGE>


October 21, 2003           Item 7. Financial Statements and Exhibits (press
                           release dated October 21, 2003)
October 28, 2003           Item 7. Financial Statements and Exhibits (press
                           release dated October 28, 2003)
October 31, 2003           Item 7. Financial Statements and Exhibits (press
                           release dated October 31, 2003)
November 18, 2003          Item 7. Financial Statements and Exhibits (press
                           release dated November 18, 2003).
November 20, 2004          Item 7. Financial Statements and Exhibits (press
                           release dated November 20, 2003)
December 17, 2003          Item 7. Financial Statements and Exhibits (press
                           release dated December 17, 2003)


ITEM 14.   CONTROLS AND PROCEDURES
----------------------------------

         Under the supervision and with the participation of our management,
including Michael K. Paulk, our President and Chief Executive Officer, and
Steven P. Ensz, our Chief Financial Officer, we have evaluated our disclosure
controls and procedures as of the end of the period covered by this report, and,
based on their evaluation, Mr. Paulk and Mr. Ensz have concluded that these
controls and procedures are effective. There were no significant changes in our
internal controls or in other factors that could significantly affect these
controls subsequent to the date of their evaluation.

         Disclosure controls and procedures are our controls and other
procedures that are designed to ensure that information required to be disclosed
by us in the reports that we file or submit under the Exchange Act are recorded,
processed, summarized and reported, within the time periods specified in the
SEC's rules and forms. Disclosure controls and procedures include, without
limitation, controls and procedures designed to ensure that information required
to be disclosed by us in the reports that we file or submit under the Exchange
Act is accumulated and communicated to our management, including Mr. Paulk and
Mr. Ensz, as appropriate to allow timely decisions regarding required
disclosure.


                                       57

<PAGE>



ITEM 15.   PRINCIPAL ACCOUNTANT FEES AND SERVICES
-------------------------------------------------

         The following sets forth fees we incurred for services provided by
PricewaterhouseCoopers LLP, for the years ended December 31, 2003 and 2002, our
independent public accountant at those year ends:

            Audit Fees       Audit Related    Tax Fees      All Other Fees
                                 Fees

2003         $266,500              --            --               --
2002         $356,937              --            --               --

         Our Audit Committee has not adopted any pre-approval policies and
procedures for engaging an accountant to render audit or non-audit services that
are subject to the pre-approval requirement.


                                       58

<PAGE>


                                   SIGNATURES

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

                                            AMERICAN NATURAL ENERGY CORPORATION

                                        BY: /s/ Michael K. Paulk
                                            -------------------------------
                                            MICHAEL K. PAULK, PRESIDENT

         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
Company and in the capacities and on the dates indicated.

SIGNATURE                 TITLE                                DATE
---------                 -----                                ----

/s/ Michael K. Paulk     President (Principal                  March 29, 2004
----------------------     Executive Officer) and Director
Michael K. Paulk


/s/ Steven P. Ensz       Director and Principal Financial      March 29, 2004
-------------------        and Accounting Officer
Steven P. Ensz

/s/ Brian Bayley         Director                              March 29, 2004
-----------------
Brian Bayley

/s/ John Campbell        Director                              March 29, 2004
------------------
John Campbell

/s/ Jules Poscente       Director                              March 29, 2004
-------------------
Jules Poscente


                                       59

<PAGE>

AMERICAN NATURAL ENERGY CORPORATION


Consolidated Financial Statements
DECEMBER 31, 2003 AND 2002


<PAGE>


REPORT OF INDEPENDENT AUDITORS

To the Board of Directors and Stockholders of American Natural Energy
Corporation:

In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, changes in stockholders' equity
(deficit), and cash flows present fairly, in all material respects, the
financial position of American Natural Energy Corporation and its subsidiary
(the "Company") at December 31, 2003 and 2002 and the results of their
operations and their cash flows for the years then ended, in conformity with
accounting principles generally accepted in the United States of America. These
financial statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these financial statements in accordance
with auditing standards generally accepted in the United States of America,
which require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As described in Note 2 of the
consolidated financial statements, the Company has incurred substantial losses
during the last three years, has a working capital deficiency and an accumulated
deficit at December 31, 2003. These matters raise substantial doubt about the
Company's ability to continue as a going concern. Management's plan in regard to
these matters is also described in Note 2 to the consolidated financial
statements. The consolidated financial statements do not include any adjustments
that might result from the outcome of this uncertainty.

As discussed in Note 5 to the consolidated financial statements, effective
January 1, 2003, the Company changed the manner in which it accounts for asset
retirement obligations.




PricewaterhouseCoopers LLP


Tulsa, Oklahoma
March 29, 2004


                                      F-1
<PAGE>

AMERICAN NATURAL ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2003 AND DECEMBER 31, 2002

<TABLE>
<CAPTION>
                                                                                       DECEMBER 31, 2003     DECEMBER 31, 2002
                                                                                               $                     $
<S>                                                                                        <C>                    <C>
                                      ASSETS
Current assets:
     Cash and cash equivalents                                                               1,650,110                 86,295
     Accounts receivable - joint interest billing                                            1,308,981                 70,972
     Accounts receivable - oil and gas sales                                                   384,003                     --
     Accounts receivable - other                                                                50,194                286,155
     Prepaid expenses                                                                           88,762                 28,291
     Marketable securities                                                                          --                192,947
     Oil inventory                                                                              14,947                 53,228
                                                                                           -----------            -----------
           Total current assets                                                              3,496,997                717,888

Proved oil and natural gas properties using full cost method, net of accumulated
depletion, depreciation, amortization and impairment of $8,356,023 and
 6,960,678                                                                                   3,702,897              1,089,200
Unproved oil and natural gas properties                                                      3,773,136              2,710,994
Equipment and other fixed assets, net of accumulated depreciation of $205,237 and
    $76,706                                                                                    757,759                742,672
Deferred expenses (Note 1)                                                                     589,983                     --
                                                                                           -----------            -----------
           Total assets                                                                     12,320,772              5,260,754
                                                                                           -----------            -----------

                   LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
     Accounts payable and accrued liabilities                                                2,587,815              1,626,593
     Revenues payable                                                                          836,679                130,874
     Accrued payroll                                                                           170,000                136,800
     Accrued interest                                                                            4,734                314,275
     Notes payable and current portion of long-term debt  (Note 6)                              13,367              4,461,887
                                                                                           -----------            -----------
           Total current liabilities                                                         3,612,595              6,670,429
Deferred income taxes (Note 10)                                                                     --                     --
Long-term debt (Note 6)                                                                      5,732,295                     --
Asset retirement obligation (Note 5)                                                         1,438,773                     --
                                                                                           -----------            -----------
           Total liabilities                                                                10,783,663              6,670,429
                                                                                           -----------            -----------
Commitments and contingencies (Notes 8 and 12)
Stockholders' equity (deficit):
     Common stock
        Authorized - 100,000,000 shares with par value of $0.01
        Issued - 26,154,546 (2002 - 25,199,846) shares                                         261,545                251,998
     Additional paid-in capital                                                             14,492,998              7,427,503
     Accumulated deficit, since January 1, 2002 (in conjunction with the quasi-
          reorganization stated capital was reduced by an accumulated deficit of
          $2,015,495)                                                                      (14,412,031)            (8,730,517)
     Accumulated other comprehensive (loss) income                                           1,194,597               (358,659)
                                                                                           -----------            -----------
           Total stockholders' (deficit) equity                                              1,537,109             (1,409,675)
                                                                                           -----------            -----------
           Total liabilities and stockholders' (deficit) equity                             12,320,772              5,260,754
                                                                                           -----------            -----------
</TABLE>

        The accompanying notes are an integral part of these consolidated
                             financial statements.


                                      F-2

<PAGE>


AMERICAN NATURAL ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
For the years ended December 31, 2003 and December 31, 2002


<TABLE>
<CAPTION>

                                                                         DECEMBER 31, 2003      DECEMBER 31, 2002
                                                                                $                      $
<S>                                                                          <C>                   <C>
Revenues:
Oil and gas sales                                                             1,698,992                308,514
Operations income                                                                43,902                  2,751
Interest income and other income                                                  4,268                166,114
                                                                             ----------            -----------
                                                                              1,747,162                477,379
                                                                            -----------            -----------

Expenses:
Lease operating expense                                                         495,409                481,711
Production taxes                                                                 66,807                 11,115
General and administrative                                                    1,938,243              1,377,857
Foreign exchange loss (gain)                                                  1,715,570                (13,610)
Interest and bank charges                                                       440,467                 53,706
Loss on sale of fixed assets                                                         --                100,438
(Gain) Loss on sale of oil and gas properties                                   (43,937)               726,348
Impairment of oil and gas properties                                            653,886              6,476,993
Gain on sale of marketable securities                                          (172,788)              (553,438)
Loss on redemption of debt, net                                                 221,730                      -
Write-down of inventory to market                                                 5,202                113,817
Depreciation, depletion, and amortization -  oil and gas
properties                                                                      919,628                347,401
Depreciation and amortization - other assets                                    182,999                 85,558
                                                                            -----------            -----------
    Total expenses                                                            6,423,216              9,207,896
                                                                            -----------            -----------
Loss before cumulative effect of accounting change                           (4,676,054)            (8,730,517)
                                                                            -----------            -----------
Cumulative effect of accounting change (Note 5)                              (1,005,460)                    --

Net loss                                                                     (5,681,514)            (8,730,517)

Other comprehensive (loss) income - net of tax:
Unrealized gain (loss) on marketable securities arising during
the year                                                                         13,870                (95,838)
Foreign exchange translation                                                  1,712,174                (54,155)
Reclassification adjustment for gains on marketable securities
included in net income                                                         (172,788)              (480,146)
                                                                            -----------            -----------
Other comprehensive (loss) incom                                              1,553,256               (630,139)
Comprehensive (loss) income                                                  (4,128,258)            (9,360,656)
                                                                            -----------            -----------

Basic and diluted loss per share before cumulative effect of
accounting change                                                                 (0.18)                 (0.35)
                                                                            -----------            -----------
Cumulative effect of accounting change                                            (0.04)                    --
                                                                            -----------            -----------
Net loss per share                                                                (0.22)                 (0.35)
                                                                            -----------            -----------
Weighted average number of shares outstanding - basic and diluted            25,880,043             25,193,887
                                                                            -----------            -----------
</TABLE>



        The accompanying notes are an integral part of these consolidated
                             financial statements.

                                      F-3

<PAGE>



AMERICAN NATURAL ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT)
For the years ended December 31, 2003 and December 31, 2002

<TABLE>
<CAPTION>
                                                                                        ACCUMU-
                                                                                         LATED
                                                                                         OTHER         TOTAL
                                                                                        COMPRE-        STOCK-
                                      COMMON STOCK            ADDITIONAL                HENSIVE        HOLDERS'
                                -------------------------      PAID-IN                  INCOME         EQUITY
                                  SHARES         AMOUNT        CAPITAL       DEFICIT    (LOSS)        (DEFICIT)

                                                      $            $             $            $             $

<S>                             <C>            <C>            <C>         <C>             <C>        <C>
BALANCE - DECEMBER 31, 2001     25,162,346      9,659,652           --    (2,015,495)      271,480    7,915,637
Results of Plan of
      Arrangement                       --     (9,408,029)    7,392,534    2,015,495            --           --
Exercise of stock options           37,500            375        11,344           --            --       11,719
Compensation expense for
      stock options                     --             --        23,625           --            --       23,625
Decrease in unrealized gain
      on marketable
      securities                        --             --            --           --       (95,838)     (95,838)
Reclassification adjustment
      for gains included in
      net income                        --             --            --           --      (480,146)    (480,146)
Foreign exchange
      translation loss                  --             --            --           --       (54,155)     (54,155)
Net loss (total
      comprehensive loss of
      $9,360,656)                       --             --            --   (8,730,517)           --   (8,730,517)
                                -------------------------------------------------------------------------------
BALANCE - DECEMBER 31, 2002     25,199,846        251,998     7,427,503   (8,730,517)     (358,659)  (1,409,675)
</TABLE>


        The accompanying notes are an integral part of these consolidated
                             financial statements.

                                      F-4

<PAGE>

AMERICAN NATURAL ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT) (CONT.)
For the years ended December 31, 2003 and December 31, 2002

<TABLE>
<CAPTION>
                                                                                        ACCUMU-
                                                                                         LATED
                                                                                         OTHER         TOTAL
                                                                                        COMPRE-        STOCK-
                                      COMMON STOCK            ADDITIONAL                HENSIVE        HOLDERS'
                                -------------------------      PAID-IN                  INCOME         EQUITY
                                  SHARES         AMOUNT        CAPITAL       DEFICIT    (LOSS)        (DEFICIT)

                                                      $            $             $            $             $

<S>                             <C>               <C>         <C>         <C>             <C>        <C>
BALANCE - DECEMBER 31, 2002     25,199,846        251,998     7,427,503   (8,730,517)     (358,659)  (1,409,675)

Stock issued as additional                                                        --                    300,000
      interest                     854,700          8,547       291,453                         --
Stock issued in settlement                                                        --                     69,000
      of contract                  100,000          1,000        68,000                         --
Compensation expense for                                                          --                     39,375
      stock options                     --             --        39,375                         --
Beneficial conversion
      feature of debentures             --             --     6,666,667           --            --    6,666,667
Decrease in unrealized gain
      on marketable
      securities                        --             --            --           --        13,870       13,870
Reclassification adjustment
      for gains included in
      net income                        --             --            --           --      (172,788)    (172,788)
Foreign exchange
      translation gain                  --             --            --           --     1,712,174    1,712,174
Net loss (total
      comprehensive loss of
      $4,128,258)                       --             --            --   (5,681,514)           --   (5,681,514)
                                -------------------------------------------------------------------------------
BALANCE - DECEMBER 31, 2003     26,154,546        261,545    14,492,998  (14,412,031)    1,194,597    1,537,109
                                -------------------------------------------------------------------------------
</TABLE>



        The accompanying notes are an integral part of these consolidated
                             financial statements.

                                      F-5

<PAGE>


AMERICAN NATURAL ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31, 2003 and December 31, 2002

<TABLE>
<CAPTION>
                                                                 DECEMBER 31, 2003      DECEMBER 31, 2002
                                                                         $                      $
<S>                                                                    <C>                    <C>
Cash flows from operating activities:
    Net loss for the period                                            (5,681,514)            (8,730,517)
    Non cash items:
        Depreciation, depletion and amortization                        1,102,627                432,959
        Foreign exchange loss (gain)                                    1,715,570                (13,610)
        Non-cash compensation expense                                      39,375                 23,625
        Gain on sale of marketable securities                            (172,788)              (553,438)
        Cumulative effect of accounting change                          1,005,460                     --
        Loss on sale of fixed asset                                            --                100,438
        (Gain) loss on sale of oil and gas properties                     (43,937)               726,348
        Loss on redemption of debt                                        221,730                     --
        Impairment of oil and gas properties                              653,886              6,476,993
        Write-down of inventory to market                                   5,202                113,817
        Stock issued in settlement of contract                             69,000                     --
    Changes in non-cash working capital items:
        Accounts receivables                                           (1,386,051)                 4,632
        Inventories                                                           330                (30,761)
        Prepaid expenses                                                   99,442                  7,967
        Accounts payable, revenue payables and accrued
              liabilities                                               2,010,174              1,336,284
                                                                       ----------             ----------
Net cash (used in) operating activities                                  (361,494)              (105,263)
                                                                       ----------             ----------
Cash flows from investing activities:
    Proceeds from sale of marketable securities                           208,051              2,745,309
    Proceeds from sale of oil and gas properties                          461,544                941,233
    Proceeds from sale of fixed assets                                         --                 61,609
    Purchase of marketable securities                                          --               (163,600)
    Purchase and development of oil and gas properties                 (4,634,539)            (4,059,565)
    Purchase of fixed assets                                             (143,620)              (946,300)
                                                                       ----------             ----------
Net cash (used in) investing activities                                (4,108,564)            (1,421,314)
                                                                       ----------             ----------
Cash flows from financing activities:
    Issuance of notes payable                                           2,500,000                500,000
    Issuance of convertible debentures (net of costs of
    $643,617)                                                          11,356,383                     --
    Issuance of capital stock                                                  --                 11,719
    Production payment loan                                             1,538,456                     --
    Repayment of production payment loan                               (2,000,000)                    --
    Payments of notes payable                                          (7,356,336)                    --
                                                                       ----------             ----------
Cash provided by financing activities                                   6,038,503                511,719

Effect of exchange rate changes on cash                                    (4,630)               (16,142)
                                                                       ----------             ----------
Increase (decrease) in cash and cash equivalents                        1,563,815             (1,031,000)
                                                                       ----------             ----------
Cash beginning of period                                                   86,295              1,117,295
                                                                       ----------             ----------
Cash end of period                                                      1,650,110                 86,295
                                                                       ----------             ----------
</TABLE>


        The accompanying notes are an integral part of these consolidated
                             financial statements.

                                      F-6

<PAGE>

AMERICAN NATURAL ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
For the years ended December 31, 2003 and December 31, 2002

<TABLE>
<CAPTION>
                                                                     DECEMBER 31, 2003      DECEMBER 31, 2002
                                                                            $                      $
<S>                                                                       <C>                    <C>
Supplemental disclosures:

Interest paid (net of amount capitalized)                                 403,301                 53,706

Non cash financing and investing activities:
Interest expense capitalized to oil and gas properties                    643,559                275,857
Common shares issued in conjunction with issuance of notes
payable                                                                   300,000                     --
Accounts payable refinanced as notes payable                              243,823                     --
Prepaid expenses financed                                                 160,746                     --
Accrued interest refinanced upon modification of debt                     331,728                     --
</TABLE>


        The accompanying notes are an integral part of these consolidated
                             financial statements.

                                      F-7

<PAGE>


AMERICAN NATURAL ENERGY CORPORATION
Notes to Consolidated Financial Statements
December 31, 2003 and 2002
--------------------------------------------------------------------------------

1    BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

      DESCRIPTION OF COMPANY

      American Natural Energy Corporation ("ANEC") is an oil and natural gas
      exploration and production company engaged in the acquisition, exploration
      and development of oil and natural gas properties for the production of
      crude oil and natural gas. Our properties are located in Louisiana.

      ANEC, an Oklahoma corporation, was formed by amalgamation on July 9, 1991
      under the Company Act (British Columbia) and was continued under the
      Canada Business Corporations Act on August 1, 1991. On January 22, 2002,
      Gothic Resources Inc. ("Gothic") completed a plan of arrangement under
      Section 192 of the Canada Business Corporations Act with ANEC which was at
      the time a wholly-owned subsidiary of Gothic, whereby all of the
      shareholders of Gothic exchanged their common shares in the capital of
      Gothic for common shares in the capital of ANEC where by Gothic became a
      wholly owned subsidiary of ANEC and the former shareholders of Gothic
      became shareholders of ANEC (See Note 11) The plan of arrangement became
      effective February 8, 2002.

      CONSOLIDATION

      The financial statements include the accounts of ANEC and its wholly owned
      subsidiary, (the "Company"). All intercompany accounts and transactions
      are eliminated in consolidation.

      The consolidated financial statements contained herein have been prepared
      in accordance with accounting principles generally accepted in the United
      States of America, which differ in certain respects from accounting
      principles generally accepted in Canada.

      CASH AND CASH EQUIVALENTS

      Cash and cash equivalents consist of short-term, highly liquid investments
      with maturities of 90 days or less at time of acquisition. Cash and cash
      equivalents are deposited with one institution and exceed the federally
      ensured limits at December 31, 2003.

      MARKETABLE SECURITIES

      Investments were accounted for under the provisions of Statement of
      Financial Accounting Standards No. 115, Accounting for Certain Investments
      in Debt and Equity Securities ("SFAS 115"). Under SFAS 115, the Company
      classified its investment securities in one of three categories: trading,
      available-for-sale, or held-to-maturity. Trading securities are bought and
      held principally for the purpose of selling them in the near term.
      Held-to-maturity are those debt securities which the Company has the
      ability and intent to hold until maturity. All other securities not
      included in trading or held-to-maturity are classified as
      available-for-sale. At December 31, 2002 the Company's marketable
      securities were all categorized as available-for-sale. The Company had no
      marketable securities at December 31, 2003.

                                      F-8

<PAGE>


      Securities that were classified as available-for-sale are stated at fair
      value as determined by quoted market prices. Unrealized holding gains and
      losses were excluded from current earnings and were included in
      comprehensive income, net of taxes, in a separate component of
      stockholders' equity until realized.

      In computing realized gains and losses on the sale of marketable
      securities, the cost of the marketable securities sold was determined
      using the average cost of the securities at the time of sale.

      At December 31, 2002, the Company held 137,000 common shares of First
      Calgary Petroleum Ltd. with a cost of $34,070 and gross unrealized gain of
      $158,877, having a market value of $192,947. The Company sold these
      securities during 2003, realizing a gain of $172,788.

      INVENTORY

      Oil in storage barges attributable to our interest amounted to 468 and
      1,638 barrels at December 31, 2003 and 2002, respectively. This oil was
      included in inventory at year end at the cost to produce such oil
      including lease operating expenses and depletion, depreciation and
      amortization applicable to those barrels accounted for on a first-in,
      first-out basis. Inventory at December 31, 2003 and 2002 was valued at the
      lower of cost or market at $14,947 and $53,228, respectively.

      OIL AND NATURAL GAS PROPERTIES

      The Company follows the full cost method of accounting for oil and natural
      gas properties. The Company defers the costs of exploring for and
      developing oil and natural gas reserves until such time as proved reserves
      are attributed to the properties. At that time, the deferred costs are
      amortized on a unit-of-production basis. Such costs include land
      acquisition costs, geological and geophysical costs, cost of drilling
      wells, asset retirement costs, interest costs on major development
      projects and overhead charges directly related to acquisition, exploration
      and development activities. The average composite rate used for depletion,
      depreciation and amortization was $2.49 and $6.77 per equivalent mcf in
      2003 and 2002, respectively.

      The capitalized costs are assessed quarterly to determine whether it is
      likely such costs will be recovered in the future. To the extent there are
      costs which are unlikely to be recovered in the future, they are written
      off. As a result of the full cost ceiling test $653,886 and $6,476,993
      were written off as impairment of oil and gas properties in 2003 and 2002,
      respectively.

      All of the Company's exploration and development activities are conducted
      jointly with others and, accordingly, these financial statements reflect
      only the Company's proportionate interest in such activities.

      Proceeds from the sale of properties are accounted for as reductions of
      capitalized costs unless such sales involve a significant change in the
      relationship between costs and the value of proved reserves or the
      underlying value of unproved properties, in which case a gain or loss is
      recognized. In October 2002, the Company sold all of its interest in its
      Oklahoma coalbed gas project and as a result has no further operations in
      Oklahoma. The Company recorded a loss

                                      F-9

<PAGE>

      from this transaction in the amount of $726,348 in 2002 and a gain
      resulting from post-closing adjustments in 2003 of $43,937.

      The Company is in the process of exploring its unproved oil and natural
      gas properties and has not yet determined whether these properties contain
      reserves that are economically recoverable. The recoverability of amounts
      shown for oil and natural gas properties is dependent upon the discovery
      of economically recoverable reserves, confirmation of the Company's
      interest in the underlying oil and gas leases, the ability of the Company
      to obtain necessary financing to complete their exploration and
      development and future profitable production or sufficient proceeds from
      the disposition thereof.

      EQUIPMENT AND OTHER FIXED ASSETS

      Equipment and other fixed assets are stated at cost less accumulated
      depreciation. Depreciation expense is determined using a straight-line
      method over the estimated useful lives of the assets. The ranges of
      estimated useful lives for financial reporting are as follows:

            Computer equipment                                 3 years
            Office furniture and equipment                   5-7 years
            Leasehold improvements                             3 years
            Barges and field equipment                      5-10 years
            Gas gathering and production facility             10 years

      When assets are retired or otherwise disposed of, the cost and related
      accumulated depreciation are removed from the accounts and any gain or
      loss is reflected in income for the period. Maintenance and repairs are
      charged to expense as incurred.

      DEFERRED EXPENSES

      Deferred expenses, representing debenture issuance costs, are stated at
      cost less accumulated amortization. Amortization expense is determined
      using an effective interest rate method over the remaining life of the
      outstanding debentures (due date September 30, 2005).

      FOREIGN EXCHANGE AND CURRENCY TRANSLATION

      The Company's functional and reporting currency is the U.S. dollar.
      Transactions denominated in foreign currencies are translated into U.S.
      dollars at exchange rates in effect on the date of the transactions.
      Exchange gains or losses on transactions are included in earnings. The
      results of operations are translated from local currencies into U.S.
      dollars using average exchange rates during each period; assets and
      liabilities are translated using exchange rates at the end of each period.
      Adjustments resulting from the translation process are reported in a
      separate component of other comprehensive income, and are not included in
      the determination of the results of operations.

                                      F-10

<PAGE>

      REVENUE RECOGNITION

      Revenues from the sale of oil produced are recognized upon the passage of
      title, net of royalties and net profits interests. Revenues from natural
      gas production are recorded using the sales method, net of royalties and
      net profits interests, which may result in more or less than the Company's
      share of pro-rata production from certain wells. When sales volumes exceed
      the Company's entitled share and the overproduced balance exceeds the
      Company's share of the remaining estimated proved natural gas reserves for
      a given property, the Company will record a liability. The Company's
      policy is to expense the pro-rata share of lease operating costs from all
      wells as incurred.

      The Company's oil production is sold under market sensitive or spot price
      contracts. Oil sales to Teppco Crude Oil, L.P. of $1,666,865 and $274,803
      in 2003 and 2002, respectively, accounted for 98% and 88% of total oil and
      gas sales. The Company's gas sales to Transcontinental Gas Pipe Line
      Corporation of $32,127 in 2003 and to Enerfin Resources of $33,712 in 2002
      accounted for 2% and 11% of total oil and gas sales, respectively. The
      Company's accounts receivable are primarily due from exploration and
      production companies which own an interest in the properties the Company
      operates and from purchasers of oil and natural gas. The industry
      concentration has the potential to impact the Company's exposure to credit
      risk because such companies may be similarly affected by changes in
      economic and industry conditions. As of December 31, 2003 $954,266 was due
      from ExxonMobil, $163,343 from TransAtlantic, and $269,781 from Teppco.
      There were no amounts due from any of these parties at December 31, 2002.

      We have no obligations to provide fixed or determinable quantities of oil
      or natural gas in the future under existing contracts or agreements.

      Operations income represents charges billed to non-operator working
      interest owners who own a working interest in the wells in which the
      Company serves as operator. The income is recognized in the month in which
      oil and gas is produced.

      Interest income is recognized as earned.

      ASSET RETIREMENT OBLIGATIONS

      Effective January 1, 2003, the Company adopted Statement of Financial
      Accounting Standards No. 143, Accounting for Asset Retirement Obligations
      ("SFAS 143"). This statement applies to obligations associated with the
      retirement of tangible long-lived assets that result from the acquisition,
      construction and development of the assets. SFAS 143 requires that the
      fair value of a liability for a retirement obligation be recognized in the
      period in which the liability is incurred. For oil and gas properties,
      this is the period in which an oil or gas well is acquired or drilled. The
      asset retirement obligation is capitalized as part of the carrying amount
      of our oil and gas properties at its discounted fair value. The liability
      is then accreted each period until the liability is settled or the well is
      sold, at which time the liability is reversed.

                                      F-11

<PAGE>

      CONVERTIBLE DEBENTURES

      Convertible debentures ("Debentures") are accounted for at the issue price
      ($11.7 million on October 21, 2003 and $300,000 on October 31, 2003) less
      applicable discount. The discount amount attributable to the Debentures
      resulted from a beneficial conversion feature existing on the date of
      issuance of the Debentures. The beneficial conversion feature is being
      amortized to interest expense using the effective interest method over the
      remaining life of the Debentures. In the event of conversion, or other
      early retirement of the Debentures, the remaining unamortized discount
      attributable to those proportionate holdings will be expensed at the time
      of conversion.

      INCOME TAXES

      The Company accounts for income taxes under Statement of Financial
      Accounting Standards No. 109, Accounting for Income Taxes. Deferred tax
      assets and liabilities are determined based on the differences between the
      tax bases of assets and liabilities and those reported in the financial
      statements. The deferred tax assets or liabilities are calculated using
      the enacted tax rates in effect for the year in which the differences are
      expected to reverse. Deferred tax assets are recognized to the extent that
      they are considered more likely than not to be realized. Income taxes and
      liabilities are recognized for the expected future tax consequences of
      events that have been included in the financia1 statements or income tax
      returns.

      USE OF ESTIMATES

      The preparation of 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
      financial statements and the reported amounts of revenue and expenses
      during the reporting period. Significant areas requiring the use of
      estimates are assessing the recoverability of capitalized oil and natural
      gas property costs, oil and gas reserve estimates and recoverability of
      deferred tax assets. Actual results could differ from those estimates.

      EARNINGS (LOSS) PER SHARE

      Basic earnings (loss) per share is computed by dividing net income or loss
      (the numerator) by the weighted average number of shares outstanding
      during the period (the denominator). The computation of diluted earnings
      per share is the same as for basic earnings per share except the
      denominator is increased to include the weighted average additional number
      of shares that would have been outstanding if previously granted stock
      options had been exercised and Debentures converted unless they are
      anti-dilutive. As of December 31, 2003 and 2002, there were 2,000,000 and
      1,950,000 shares available for issuance pursuant to the exercise of
      previously granted stock options, respectively. As of December 31, 2003,
      there were 26,666,667 shares available for issuance upon the conversion of
      the Debentures. Due to losses in 2003 and 2002, the options and shares
      issuable upon conversion of the Debentures were excluded from the
      calculation of diluted earnings per share as they were anti-di1utive.

                                     F-12

<PAGE>

      COMPREHENSIVE INCOME (LOSS)

      The preparation of financial statements in conformity with accounting
      principles generally accepted in the United States of America requires
      management to report net income (loss) as a component of comprehensive
      income (loss) in the financial statements. Comprehensive income (loss) is
      defined as the change in equity of a business enterprise arising from
      non-owner sources. The classifications of comprehensive income (loss)
      under current accounting standards include foreign currency items, minimum
      pension liability adjustments, and unrealized gains and losses on certain
      investments in debt and equity securities. The Company had other
      comprehensive income (loss) of $1,553,256 and ($630,139) for the years
      ended December 31, 2003 and 2002, respectively, as a result of unrealized
      gains (losses) on marketable securities of $13,870 and ($95,838) and
      $1,712,174 and ($54,155) related to foreign exchange translation gain
      (loss). The Company also had a $172,788 and $480,146 reclassification
      adjustment for gains on marketable securities included in net income for
      the year ended December 31, 2003 and 2002.

      As of December 31, 2003, accumulated other comprehensive income (loss) was
      comprised solely of foreign currency translation gains. As of December 31,
      2002, accumulated other comprehensive income (loss) was comprised of
      $158,918 of unrealized gains on marketable securities and $517,577 of
      foreign currency translation losses.

      STOCK-BASED COMPENSATION

      At December 31, 2003, the Company has a stock-based compensation plan,
      which is described more fully in Note 7. The Company accounts for this
      plan in accordance with the provisions of Accounting Principles Board
      Opinion No. 25, Accounting for Stock Issued to Employees, ("APB 25") and
      complies with the disclosure provisions of Statement of Financial
      Accounting Standards No. 123, Accounting for Stock-Based Compensation
      ("SFAS 123"), as amended by Statement of Financial Accounting Standards
      No. 148, Accounting for Stock-Based Compensation - Transition and
      Disclosure. Under APB 25, compensation expense is recognized based on the
      difference, if any, on the date of grant between the estimated fair value
      of the Company's stock and the amount an employee must pay to acquire the
      stock. Compensation expense is recognized immediately for past services
      and ratably for future services over the option-vesting period.
      Compensation expense has been recognized for any grants to individuals who
      do not meet the definition of employee.

      The Company accounts for equity instruments issued in exchange for the
      receipt of goods or services from other than employees in accordance with
      SFAS 123 and the conclusions reached by the Emerging Issues Task Force in
      Issue No. 96-18, Accounting for Equity Instruments That Are Issued to
      Other Than Employees for Acquiring or in Conjunction with Selling, Goods
      or Services ("EITF 96-18"). Costs are measured at the estimated fair
      market value of the consideration received or the estimated fair value of
      the equity instruments issued, whichever is more reliably measurable. The
      value of equity instruments issued for consideration other than employee
      services is determined on the earlier of a performance commitment or
      completion of performance by the provider of goods or services as defined
      by EITF 96-18. The following table illustrates the effect on net income
      and earnings per share as if the Company had applied the fair value
      recognition provisions of SFAS 123 to stock-based employee compensation.

                                     F-13

<PAGE>

<TABLE>
<CAPTION>
                                                                    For years ended December 31,
                                                                    2003                   2002
                                                                     $                       $
                                                                    ----                   ----

<S>                                                                <C>                     <C>
Net loss, as reported                                              (5,681,514)             (8,730,517)
Less:  Total stock-based employee compensation expense
determined under fair value based method for all
awards, net of related tax effects                                    (42,441)               (284,780)
                                                                   ----------              ----------
Pro forma net loss                                                 (5,723,955)             (9,015,297)
                                                                   ==========              ==========

Loss per share
Basic and diluted-as reported                                           (0.22)                  (0.35)
                                                                   ==========              ==========
Basic and diluted-pro forma                                             (0.22)                  (0.36)
                                                                   ==========              ==========
</TABLE>


      The fair value of the options granted is estimated on the date of the
      grant using the Black-Scholes option-pricing model with the following:

                                                                        2003
                                                                        ----
        Weighted average life, in years                                  5.00
        Risk-Free interest rate                                          4.54%
        Expected volatility                                            107.31%
        Expected Dividend Rate                                          None

      The fair value of the options granted in 2003 was $243,000. There were no
      option grants in 2002.

      NEW PRONOUNCEMENTS

      Statement of Financial Accounting Standards No. 141, Business Combinations
      ("SFAS 141") and Statement of Financial Accounting Standards No. 142,
      Goodwill and Intangible Assets ("SFAS 142") were issued by the Financial
      Accounting Standards Board in June 2001 and became effective for us on
      July 1, 2001 and January 1, 2002, respectively. SFAS 141 requires all
      business combinations initiated after June 30, 2001 to be accounted for
      using the purchase method. Additionally, SFAS 141 requires companies to
      disaggregate and report separately from goodwill certain intangible
      assets. SFAS 142 establishes new guidelines for accounting for goodwill
      and other intangible assets. Under SFAS 142, goodwill and certain other
      intangible assets are not amortized, but rather are reviewed annually for
      impairment. The Emerging Issues Task Forces (EITF) is considering two
      issues related to the reporting of oil and gas mineral rights. Issue No.
      03-S, Application of SFAS No. 142, Goodwill and Other Intangible Assets to

                                     F-14

<PAGE>

      Oil and Gas Companies, considers whether oil and gas drilling rights are
      subject to the classification and disclosure provisions of SFAS 142 if
      they are intangible assets. The Company classifies the cost of oil and gas
      mineral rights as proved and unproved oil and natural gas properties and
      believes that this is consistent with oil and gas accounting and industry
      practice. If the EITF determines that oil and gas mineral rights are
      intangible assets and are subject to the applicable classification and
      disclosure provisions of SFAS 142, we estimate that $3.8 million and $2.7
      million would be classified on our consolidated balance sheets as
      "intangible undeveloped leasehold" and $2.4 million and $830,000 would be
      classified as "intangible developed leasehold" as of December 31, 2003 and
      2002, respectively. These amounts are net of accumulated DD&A. There would
      be no effect on the consolidated statements of operations or cash flows as
      the intangible assets related to oil and gas mineral rights would continue
      to be amortized under the full cost method of accounting.

      We will continue to classify our oil and gas mineral rights held under
      lease and other contractual rights representing the right to extract such
      reserves as tangible oil and gas properties until further guidance is
      provided.

      In July 2002, the FASB issued Statement of Financial Accountings Standards
      No. 146, Accounting For Costs Associated with Exit or Disposal Activities
      ("SFAS 146"). SFAS 146 was effective for exit or disposal activities
      initiated after December 31, 2002. Adoption of this standard did not have
      any impact on our financial position or results of operations.

      In November 2002, the FASB issued FASB Interpretation No. 45, Guarantor's
      Accounting and Disclosure Requirements for Guarantees, Including Indirect
      Guarantee of Indebtedness of Others ("FIN 45"). FIN 45 requires that upon
      issuance of a guarantee, the guarantor must recognize a liability for the
      fair value of the obligation it assumes under that guarantee. FIN 45's
      provisions for initial recognition and measurement should be applied on a
      prospective basis to guarantees issued or modified after December 31,
      2002. The guarantor's previous accounting for guarantees that were issued
      before the date of FIN 45's initial application may not be revised or
      restated to reflect the effect of the recognition and measurement
      provisions of the Interpretation. The disclosure requirements are
      effective for financial statements of both interim and annual periods that
      end after December 15, 2002. The Company is not a guarantor under any
      significant guarantees and thus this interpretation did not have a
      significant effect on the Company's financial position or results of
      operations.

      In January 2003, the FASB issued FASB Interpretation No. 46,
      Consolidation of Variable Interest Entities -- An Interpretation of ARB
      No. 51 ("FIN 46"). FIN 46 is an interpretation of Accounting Research
      Bulletin 51, "Consolidated Financial Statements," and addresses
      consolidation of variable interest entities (VIEs) by business
      enterprises. The primary objective of FIN 46 is to provide guidance on the
      identification and financial reporting of entities over which control is
      achieved through means other than voting rights; such entities are known
      as VIEs. FIN 46 requires an enterprise to consolidate a VIE if that
      enterprise has a variable interest that will absorb a majority of the
      entity's expected losses, receive a majority of the entity's expected
      residual returns, or both. An enterprise shall consider the rights and
      obligations conveyed by its variable interest in making this
      determination. At December 31, 2003, The Company did not have any entities
      that would qualify for consolidation in accordance with the provisions of
      FIN 46, as amended. Therefore, the adoption of FIN 46, as amended, did not
      have an impact on our consolidated financial statements

                                     F-15

<PAGE>

      In April 2003, the FASB issued Statement of Financial Accounting Standards
      No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging
      Activities ("SFAS 149"). SFAS 149 amends and clarifies financial
      accounting and reporting for derivative instruments, including certain
      derivative instruments embedded in other contracts (collectively referred
      to as derivatives) and for hedging activities under Statement of Financial
      Accounting Standards No. 133, Accounting for Derivative Instruments and
      Hedging Activities. This pronouncement is effective for contracts entered
      into or modified after June 30, 2003, and for hedging relationships
      designated after that date. The Company currently has no derivatives,
      embedded derivatives requiring bifurcation and separate measurement, or
      hedging activities, therefore, the implementation of SFAS 149 did not have
      any effect on our financial opposition, results of operations, or cash
      flows.

      In May 2003, the FASB issued Statement of Financial Accounting Standards
      No. 150, Accounting for Certain Financial Instruments with Characteristics
      of both Liabilities and Equity ("SFAS 150"). SFAS 150 establishes
      standards regarding the classification and measurement of certain
      financial instruments with characteristics of both liabilities and equity.
      It requires that an issuer classify a financial instrument that is within
      its scope as a liability (or an asset in some circumstances). Many of
      those instruments were previously classified as equity. SFAS 150 became
      effective for us starting in the quarter ended September 30, 2003. The
      application of SFAS 150 did not have any effect on our financial position,
      results of operations or cash flow.

      In December 2003, the Securities and Exchange Commission issued Staff
      Accounting Bulletin 104, Revenue Recognition. SAB 104 revises or rescinds
      certain guidance included in previously issued staff accounting bulletins
      in order to make this interpretive guidance consistent with current
      authoritative accounting and auditing guidance and SEC rules and
      regulations relating to revenue recognition. This bulletin was effective
      immediately upon issuance. The Company's current revenue recognition
      policies comply with SAB 104.

2    LIQUIDITY AND CAPITAL RESOURCES

      The Company has no current borrowing capacity with any lender. The Company
      has sustained substantial losses in 2003 and 2002, totaling approximately
      $5.7 and $8.7 million and negative cash flow from operations in each of
      2003 and 2002, which leads to questions concerning the ability of the
      Company to meet its obligations as they come due. The Company also has a
      need for substantial funds to develop its oil and gas properties.

      The accompanying financial statements have been prepared on a going
      concern basis which contemplates continuity of operations, realization of
      assets and liquidation of liabilities in the ordinary course of business.
      As a result of the losses incurred and current negative working capital,
      there is no assurance that the carrying amounts of assets will be realized
      or that liabilities will be liquidated or settled for the amounts
      recorded. The ability of the Company to continue as a going concern is
      dependent upon adequate sources of capital and the ability to sustain
      positive results of operations and cash flows sufficient to continue to
      explore for and develop its oil and gas reserves.

      In the ordinary course of business, the Company makes substantial capital
      expenditures for the exploration and development of oil and natural gas
      reserves. Historically, the Company has financed its capital expenditures,
      debt service and working capital requirements with the proceeds of debt
      and private offering of its securities. Cash flow from operations is
      sensitive to

                                     F-16

<PAGE>

      the prices the Company receives for its oil and natural gas. A reduction
      in planned capital spending or an extended decline in oil and gas prices
      could result in less than anticipated cash flow from operations and an
      inability to sell more of its common stock or refinance its debt with
      current lenders or new lenders, which would likely have a further material
      adverse effect on the Company.

      Management's strategy is to obtain additional financing and failure to do
      so can be expected to adversely affect the Company's ability to further
      the development of the ExxonMobil AMI, grow revenues, oil and gas reserves
      and achieve and maintain a significant level of revenues and
      profitability. There can be no assurance the Company will obtain this
      additional funding. Such funding may be obtained through the sale of
      equity securities or by incurring additional indebtedness. Without such
      funding, revenues will continue to be limited and it can be expected that
      operations will not be profitable. In addition, any additional equity
      funding that is obtained may result in material dilution to the current
      holders of common stock

3    JOINT DEVELOPMENT AGREEMENT

      On November 25, 2002 the Company entered into a Joint Development
      Agreement with ExxonMobil whereby the Company gave ExxonMobil the right to
      participate in exploration and development on all lands it has under lease
      in the Bayou Couba area, up to 50% of the total interest and the use of
      its 3D seismic covering those leases in exchange for the rights to
      exploration and development on certain lands and leases owned by
      ExxonMobil, up to 50% of the total interest. Each party will pay their
      respective share of exploration and development costs. The original
      agreement terminated in 4 years and covered approximately 8,427 acres. On
      December 19, 2003, the Company entered into a letter agreement with
      ExxonMobil covering a proposed expansion of the lands covered by the
      agreement and to extend the termination date of the agreement (the
      "Expansion Agreement"). Subject to the Company fulfilling the terms of the
      Expansion Agreement, the Expansion Agreement adds a total of 2,560 acres
      to the lands covered by the agreement and extends the term by one year to
      November 2007 (See Note 12).

4    PROPERTY, PLANT AND EQUIPMENT

      The carrying value of equipment and other fixed assets as of December 31,
      2003 and 2002 included the following components:

                                                         2003           2002
                                                           $              $
                                                         ----           ----
     Computer and office furniture and equipment        102,792         79,497
     Leasehold improvements                               5,520          5,520
     Barges and field equipment                         747,281        734,361
     Gas gathering and production facility
     expansion                                          107,403             --
                                                        -------        -------
                                                        962,996        819,378
     Less: Accumulated depreciation                    (205,237)       (76,706)
                                                        -------        -------
                                                        757,759        742,672
                                                        =======        =======

                                     F-17

<PAGE>

5    ASSET RETIREMENT OBLIGATIONS

      Effective January 1, 2003, the Company adopted Statement of Financial
      Accounting Standards No. 143, Accounting for Asset Retirement Obligations
      ("SFAS 143"). This statement applies to obligations associated with the
      retirement of tangible long-lived assets that result from the acquisition,
      construction and development of the assets.

      SFAS 143 requires that the fair value of a liability for a retirement
      obligation be recognized in the period in which the liability is incurred.
      For oil and gas properties, this is the period in which an oil or gas well
      is acquired or drilled. The asset retirement obligation is capitalized as
      part of the carrying amount of the asset at its discounted fair value. The
      liability is then accreted each period until the liability is settled or
      the asset is sold, at which time the liability is reversed.

      We identified and estimated all of our asset retirement obligations for
      tangible, long-lived assets as of January 1, 2003. These obligations were
      for plugging and abandonment costs for depleted oil and gas wells. Prior
      to the adoption of SFAS 143, we included an estimate of our asset
      retirement obligations related to our oil and gas properties in our
      calculation of oil and gas depreciation, depletion and amortization
      expense. Upon adoption of SFAS 143, we recorded the discounted fair value
      of our expected future obligations of $1.4 million and recorded an
      increase in unproved properties of $0.4 million. The cumulative effect of
      the change in accounting principles was a $1.0 million loss which was
      recorded in the condensed consolidated statement of operations for the
      quarter ended March 31, 2003. Had SFAS 143 been adopted as of January 1,
      2002, the Company's net loss for the year ended December 31, 2002 would
      have increased by approximately $143,000 and there would have been no
      effect on the reported earnings per share. The effect of SFAS 143 for the
      year ended December 31, 2003 was an increase in the net loss before
      cumulative effect of accounting change of approximately $145,000.

      The components of the change in our asset retirement obligations are shown
      below. Information for the year ended December 31, 2002 is shown on a pro
      forma basis.

                                       For the years ended December 31,
                                             2003           2002
                                              $              $
                                             ----           ----
Asset retirement obligations,
     January 1                            1,435,460       1,292,538
Additions and revisions                      18,609              --
Settlements and disposals                  (160,714)             --
Accretion expense                           145,419         142,922
                                          ---------       ---------
Asset retirement obligations,
     December 31                          1,438,774       1,435,460

                                     F-18

<PAGE>


6    NOTES PAYABLE AND LONG-TERM DEBT

      Notes payable and long-term debt as of December 31, 2003 and 2002
consisted of the following:

                                                    2003           2002
                                                     $              $
                                                    ----           ----
12% note payable                                          --        500,000
Note payable - Bank One                                   --      3,961,887
8% Convertible secured debentures                 12,000,000             --
Discount for beneficial conversion feature,
      net of amortization of $398,962             (6,267,705)            --
                                                  ----------      ---------
Total notes payable and long-term debt             5,732,295      4,461,887
                                                  ----------      ---------
Less: Current portion                                     --      4,461,887
                                                  ----------      ---------
Total notes payable and long-term debt, net
      of current portion                           5,732,295             --
                                                  ==========      =========

      12% Note Payable

      On August 2, 2002, the Company borrowed $500,000 from a private investor.
      The borrowing accrued interest at 12% (effective rate 22.0%) and was due
      on December 6, 2002, or out of the proceeds of a financing or sale or
      change of control of the Company if any of these events occurred prior to
      the due date. On February 14, 2003, we issued to the lender 166,700 shares
      of our common stock as additional consideration for making the loan. The
      loan was repaid on March 12, 2003 out of the proceeds from our sale of the
      remaining shares of First Calgary Petroleums Ltd. that the Company owned.

      Note Payable - Bank One

      Effective December 31, 2001, the Company acquired all of the assets and
      capital stock of Couba Operating Company (Couba) in connection with the
      bankruptcy proceedings of Couba. The ANEC/Couba Reorganization Plan
      ("Plan") was confirmed by the U.S. Bankruptcy Court for the Western
      District of Oklahoma on November 16, 2001 and became effective on December
      31, 2001. As part of the Plan, the Company was to have entered into a
      $3,961,887 note payable with Bank One. The note was to be amortized based
      on a five year period and payments of principal and interest were to be
      made quarterly. An interest rate, final terms for repayment and collateral
      were not finalized until the first quarter of 2003. On March 12, 2003 the
      Company entered into a refinancing transaction with Bank One whereby Bank
      One was paid $2,250,000 for partial release of collateral held by it
      resulting from the Plan. Additionally, the Company entered into a note
      payable with Bank One for remaining balances due pursuant to the Plan in
      the amount of $1,715,134 with interest at Bank One prime plus 2%, due
      December 31, 2003. This refinancing was treated as a modification of debt.
      Interest rate on the outstanding balance during the year ranged from 6.25%
      to 6.75%. The note was paid in full in October 2003 upon issuance of 8%
      convertible debentures discussed in more detail below. The balance of
      unamortized premium

                                     F-19

<PAGE>

      arising from the March 2003 refinancing was recorded as a reduction to the
      loss on redemption of debt of $102,790.

      Note Payable - Quest Capital Corp.

      In March 2003 the Company borrowed $2,500,000 from Quest Capital Corp., as
      successor to Quest Investment Corporation (collectively "Quest") in the
      form of a note payable due October 31, 2003. Interest was payable monthly
      at an annual rate of 12% (effective rate 22.0%). The note was
      collateralized by a mortgage on all oil and gas properties of the Company.
      The Company also issued 688,000 shares of its stock to Quest as additional
      consideration. A director of the Company is also a director of Quest. On
      October 21, 2003, concurrent with the sale of Convertible Secured
      Debentures further discussed below, the Company paid the Quest note in
      full and the Company received a release of collateral held by Quest. The
      balance of unamortized discount on the Quest note was recorded as a loss
      on redemption of debt in the amount of $33,263.

      Production Payment Financing

      On March 12, 2003, the Company entered into a funding arrangement with
      TransAtlantic Petroleum (USA) Corp. ("TransAtlantic") whereby
      TransAtlantic agreed to advance the Company up to $2.0 million, of which
      up to $1.8 million was to be used to fund the Company's share of the
      drilling and completion costs for the four initial wells the Company
      drilled in St. Charles Parish, Louisiana ("Subject Wells") (the advance
      was repaid in October 2003, as further discussed below). In exchange,
      TransAtlantic received a production payment payable out of 75% of the net
      revenues from the Subject Wells, and, upon repayment, a 10% working
      interest in such wells. In addition, TransAtlantic received a 10% interest
      in the Company's Bayou Couba lease and lease with the State of Louisiana
      ("Subject Leases"). Further, TransAtlantic has the right to acquire a 10%
      participation in any additional interests the Company acquires in the
      23.138 square mile Bayou Couba salt dome development area, including any
      interests acquired through the Company's area of mutual interest joint
      development agreement with ExxonMobil Corp. The Company's obligations to
      TransAtlantic were collateralized by a lien against the Company's interest
      in the Subject Wells and their hydrocarbon production. The Company had
      drawn a total of $2.0 million, including the $200,000 not specifically
      identified with the drilling of the Subject Wells. Imputed interest on the
      $2.0 million amounted to $461,544, which was recorded as a discount on the
      production payment liability, with a corresponding reduction in the value
      of proved and unproved oil and natural gas properties, representing the
      sale of the 10% working interest in the Subject Leases and Subject Wells.
      The discount was accreted to interest expense, using the units of
      production method. Concurrent with the sale of Convertible Secured
      Debentures on October 21, 2003, as further discussed below, the Company
      paid the TransAtlantic production payment loan in full and the Company
      received a release of collateral held by TransAtlantic. At that time the
      outstanding balance of the production payment loan was $1,672,650
      (including the amounts related to volumes produced). The balance of
      unamortized discount on the production payment loan in the amount of
      $291,257 at the time of the early repayment of the loan was recorded as
      loss on redemption of debt.

      A current director of the Company is a current director of TransAtlantic.
      Therefore, this transaction represents a related party transaction.
      Concurrent with the sale of Convertible

                                     F-20

<PAGE>

      Secured Debentures on October 21, 2003 the chairman of TransAtlantic at
      the time was appointed to the board of directors of the Company as further
      discussed below.

      8% Convertible secured debentures

      On October 21, 2003 and October 31, 2003 the Company completed financing
      transactions of $11.695 million and $305,000, respectively, by issuing
      Convertible Secured Debentures (the "Debentures"). The Debentures are
      repayable on September 30, 2005 with interest payable quarterly commencing
      December 31, 2003 at 8% per annum. The outstanding principal of the
      Debentures is convertible by the holders into common shares of the Company
      at any time prior to maturity at a conversion price of $0.45 per share,
      subject to antidilution adjustment, and the Debentures are redeemable by
      the Company at any time after October 1, 2004 if the weighted average
      price per share on the TSX Venture Exchange for a 20 consecutive trading
      day period prior to the date notice of redemption is given has exceeded
      1662/3% of the conversion price. A finder's fee in the amount of $360,000
      was paid to Middlemarch Partners Limited of London, England in connection
      with the financing. The Company used approximately $5.9 million of the
      proceeds of the financing for the repayment of the secured debt held by
      Quest Capital Corporation, Bank One and TransAtlantic Petroleum (USA)
      Corp. and approximately $2.1 million of the proceeds for the payment of
      accounts payable and intends to use the balance primarily for exploration
      and development of its Bayou Couba oil and gas leases within its
      ExxonMobil Joint Development Project in St. Charles Parish, Louisiana. The
      Debentures are collateralized by substantially all of ANEC's assets. The
      Debentures have covenants limiting unsecured borrowings to $2 million and
      restricting the payment of dividends and capital distributions.

       The Debentures are convertible into common shares at a conversion price
      of $0.45 per share. On the dates the transaction was completed, the
      closing price for shares of the Company's common stock on the TSX Venture
      Exchange was $0.70 per share. Because the market price of the Company's
      stock on the dates the transaction was completed exceeded the conversion
      price, the Debentures included a beneficial conversion feature of
      approximately $6.7 million. The estimated value of the beneficial
      conversion feature was recorded as a discount to the carrying value of the
      bonds and as an increase in additional paid-in capital. The discount is
      being amortized to interest expense over the life of the Debentures using
      the effective interest method. In the event any Debentures are converted
      prior to September 30, 2005, any unamortized discount attributed to those
      proportionate holdings will be expensed at the time of conversion.
      Amortization of the discount amounted to approximately $399,000 for 2003.

      Concurrent with the financing, two additional directors were elected to
      the board of directors of the Company. One of the newly elected directors
      was the chairman of TransAtlantic at the time of the transaction.

7    CAPITAL STOCK

      OPTIONS

      The Company adopted the 2001 Stock Incentive Plan during the year ended
      December 31, 2001 that replaced the 2000 Stock Option Plan. Under the
      terms of the 2000 Plan, which had been

                                     F-21

<PAGE>

      adopted by Gothic prior to the reorganization (see Note 11), the board had
      the right from time to time authorize the issuance of options to
      directors, officers and service providers of Gothic and its subsidiaries.
      The option price under each option shall not be less than the discounted
      market price, as allowed by the TSX Venture Exchange, on the grant date.
      The expiration date for each option shall be set by the board at the time
      of issue of the option and shou1d not be more than 5 years after the grant
      date. The maximum number of shares which may be issuable pursuant to
      options granted under the plan shall be 5,000,000 shares or such
      additional amount as may be approved from time to time by the shareholders
      of Gothic. The number of shares issuable to any one optionee under the
      plan shall not exceed 5% of the total number of issued and outstanding
      shares on a non-diluted basis. The number of shares which may be issuable
      under the plan within a one year period, in aggregate shall not exceed 20%
      of the then outstanding options issued under such plan and to any optionee
      who is an insider shall not exceed 5% of the then outstanding options
      issued under such plan. Upon approval by Gothic's shareholders of the
      corporate reorganization (see Note 11) and the adoption of the 2001 Stock
      Incentive Plan, the options outstanding under the 2000 Plan were replaced
      with options having the same exercise price and expiration date under the
      2001 Stock Incentive Plan. No further options will be granted under the
      2000 Plan.

      Stock option activity for the years ended December 31, 2003 and 2002 is as
      follows:

                                                                    Weighted
                                                Number of            Average
                                                  Options     Exercise price
                                                                           $
                                                ---------     --------------
     Outstanding - December 31, 2001            1,987,500               0.33
     Exercised                                    (37,500)              0.33
                                                ---------               ----
     Outstanding - December 31, 2002            1,950,000               0.33
                                                ---------               ----
     Granted                                      450,000               0.68
     Expired                                     (400,000)              0.32
                                                ---------               ----
     Outstanding - December 31, 2003            2,000,000               0.41
                                                =========               ====


      Exercise prices of options outstanding at December 31, 2003 ranged from
      $0.32 to $0.68. At December 31, 2003, 1,550,000 (2002 - 1,050,000) options
      have vested and are exercisable at a weighted average price of $0.33. The
      weighted average remaining contractual life of options granted at December
      31, 2003 is 40 months (2002 - 42 months).

      The 2001 Stock Incentive Plan, (approved by the shareholders in January
      2002), is comprised of a Discretionary Option Grant Program, a Salary
      Investment Option Grant Program, a Stock Issuance Program, an Automatic
      Option Grant Program, and a Director Fee Option Grant. The maximum number
      of shares of Common Stock initially reserved for issuance over the term of
      the 2001 Stock Incentive Plan shall not exceed 5,000,000 shares. The 2001
      Stock Incentive Plan terminates upon the earliest of (i) December 14,
      2011, (ii) the date on which all shares available for issuance under the
      plan have been issued as fully-vested shares, or (iii) the termination of
      all outstanding options in connection with a change in control. Options
      outstanding under the 2000 Stock Option Plan were exchanged for options
      under the new plan.

                                     F-22

<PAGE>

      Under the Discretionary Option Grant Program, the Plan Administrator will
      fix the exercise price per share at the time of the grant. No option will
      have a term in excess of ten years measured from the option grant date. As
      of December 31, 2003 and 2002, there were options to purchase 1,900,000
      and 1,950,000 shares outstanding under the Discretionary Option Grant
      Program, respectively.

      Under the Salary Investment Option Grant Program, the exercise price per
      share will be thirty-three and one-third percent of the fair market value
      per share of the common stock on the option grant date. The options will
      become exercisable in a series of twelve successive equal monthly
      installments upon the completion of each calendar month of service in the
      calendar year for which the salary reduction is in effect. Each option
      will have a maximum term of ten years measured from the option grant date.
      As of December 31, 2003 and 2002, there were no options granted under the
      Salary Investment Option Grant Program.

      The plan administrator will fix the purchase price per share of common
      stock under the Stock Issuance Program. The plan administrator may issue
      shares that are fully and immediately vested upon issuance or which are to
      vest in one or more installments over the participant's period of service
      or upon attainment of specified performance objectives. As of December 31,
      2003 and 2002, there were no shares outstanding under the Stock Issuance
      Program.

      Under the Automatic Option Grant Program, each individual who is first
      elected or appointed as a non-employee Board member at any time after
      February 1, 2002 shall automatically be granted, on the date of initial
      election or appointment, a Non-Statutory Option to purchase 50,000 shares
      of common stock, provided that the individual has not previously been
      employed by the Company or any parent or subsidiary. On the date of each
      Annual Stockholders Meeting held after January 1, 2002, each individual
      who is to continue to serve as a non-employee Board Member will
      automatically be granted a Non-Statutory Option to purchase 5,000 shares
      of common stock, provided, commencing January 1, 2003, the individual has
      served as a non-employee Board member for at least 6 months. The exercise
      price under this plan will be the fair market value of the common stock on
      the option grant date. Each option shall be immediately exercisable for
      any or all option shares. However, any shares purchased under the option
      shall be subject to repurchase by the Company, at the exercise price paid,
      upon the optionee's cessation of Board service prior to vesting in those
      shares. Each initial 50,000 share option will vest, and the Company's
      repurchase right will lapse, in a series of three successive equal annual
      installments upon the optionee's completion of each year of Board service
      over a three-year period measured from the grant date. Each annual 5,000
      share option will vest, and the Company's repurchase right will lapse,
      upon the optionee's completion of one year of Board service measured from
      the grant date. As of December 31, 2003 there were 100,000 options
      outstanding under the Automatic Option Grant Program. There were no
      options outstanding under the Automatic Option Grant Program as of
      December 31, 2002.

      The Board has the authority to implement the Director Fee Option Grant
      Program as of the first day of any calendar year. Upon the implementation
      of the Director Fee Option Grant Program, each non-employee Board member
      may elect to apply all or any portion of the annual retainer fee otherwise
      payable in cash for his or her service on the Board to the acquisition of
      a special option grant. As of December 31, 2003 and 2002, there were no
      options outstanding under the Director Fee Option Grant Program.

                                     F-23


<PAGE>

8    COMMITMENTS AND CONTINGENCIES

      The Company rents office space and equipment under long-term operating
      leases that expire through 2005. The future minimum lease payments
      required under the operating leases that have initial non-cancelable lease
      terms in excess of one year amounted to $35,074 to be paid in 2004 and
      $1,523 to be paid in 2005.

      Rent expense on all operating leases amounted to approximately $85,300 and
      $66,000 in 2003 and 2002, respectively.

      Bank of Oklahoma, N.A. has issued an irrevocable standby letter of credit,
      dated December 24, 2003 and expiring December 24, 2004, in the amount of
      $125,000 drawn in favor of RLI Insurance Company securing a surety bond in
      favor of the Louisiana Office of Conservation for plugging and abandonment
      obligations which may occur as a result of drilling operations in St.
      Charles Parish, Louisiana.

      We agreed that the Class 7 creditors to the ANEC/Couba Reorganization Plan
      ("Plan") would receive a contingent payable from future production of the
      properties in the amount of approximately $4.9 million. The contingent
      payable is in the form of a net profits interest ("NPI"), the size of
      which is determined by the location of wells that may be drilled in the
      future. Wells existing at the effective date of the Plan receive an NPI of
      50%, new wells drilled on acreage transferred by the Plan to the Company
      will receive an NPI of 15% and new wells drilled within the boundaries of
      a seismic shoot previously owned by Couba will receive an NPI of 6%. The
      Company is entitled to recover all capital and operating costs prior to
      the NPI becoming payable. At a minimum, the Class 7 creditors are to
      receive an overriding royalty interest that is in payment of the
      contingent payable. The Company is accounting for any contingent purchase
      price payments to the Class 7 creditors as additions to the full cost pool
      as production occurs.

      We agreed that, after repayment to us of 200% of all costs of bankruptcy,
      drilling, development and field operations from net revenues of the Bayou
      Couba Lease and the area of mutual interest, the former holders of equity
      securities of Couba Operating Company will be entitled to a reversionary
      interest in the wells in the Bayou Couba Lease equal to 25% of the working
      interest obtained by us directly from Couba Operating Company at the time
      of confirmation and as a result of the plan of reorganization of Couba
      Operating Company.

      We are a defendant in a number of legal proceedings which we consider to
      be routine litigation that is incidental to our business. We do not expect
      to incur any material liability as a consequence of such litigation.

9    RELATED PARTY TRANSACTIONS

      The Company was charged $20,329 of office administration expense by
      companies controlled by directors of the Company during 2002, $3,992 of
      which was accrued as of December 31, 2002. No such expenses were incurred
      in 2003.

      During the year ended December 31, 2002 we had a note payable to an
      officer/director of the Company in the amount of $40,000. The note was an
      uncollateralized, demand loan with no stated interest rate. Interest was
      paid at a rate commensurate with the rate incurred by the


                                     F-24

<PAGE>

      officer/director in a personal loan transaction providing these funds. The
      note was repaid in November 2003.

      We entered into two financing transactions with entities in which either
      current or former directors of the Company are currently directors. We
      borrowed $2,500,000 from Quest Investment, Inc. in March 2003. We
      currently have a director who is also a director of Quest (see Note 6). In
      addition, we entered into a financing transaction with TransAtlantic
      Petroleum (USA) Corp. A current director of the Company is currently a
      director of TransAtlantic (see Note 6).

10   INCOME TAXES

      The provision for income taxes for the year ended December 31, 2003 is
      based on the liability method prescribed by Statement of Financial
      Accounting Standards No. 109 and includes current taxes and the change in
      the Company's deferred income tax asset or liability during the year.
      Deferred income tax assets and liabilities arise from temporary
      differences between the tax bases of assets and liabilities and their
      reported amounts in the financial statements.

      The tax effects of temporary differences between the tax bases of assets
      and liabilities and their financial reporting amounts and the tax credits
      and other items that give rise to significant portions of the deferred tax
      assets and deferred tax liabilities at December 31, 2003 and 2002 are
      presented below:

                                                        2003         2002
                                                          $            $
                                                        ----         ----
     DEFERRED TAX ASSETS:
     Asset retirement costs                              546,158           --
     Foreign exchange loss                               651,230           --
     Acquisition, exploration and development
     costs and related depreciation, depletion and
     amortization                                      1,699,127    2,581,495
     Contribution carryovers                               1,967          949

     Net operating loss carryforwards                  2,677,805    1,404,667
                                                      ----------   ----------
               Deferred tax asset                      5,576,287    3,987,111

     Less: Valuation allowance                        (5,576,287)  (3,987,111)
                                                      ----------   ----------
     Total deferred tax asset (liability)                     --           --
                                                      ==========   ==========


      The provision for income taxes is different than the amounts computed
      using the applicable statutory federal income tax rate. The differences
      for the years ended December 31, 2003 and 2002 are summarized as follows:


                                     F-25

<PAGE>

                                                     2003           2002
                                                      $              $
                                                     ----           ---

        Federal tax benefit at statutory rate       1,978,730      2,867,537
        State taxes, net of federal taxes             167,623        365,603
        Other                                         (20,335)       (10,034)
        Less: valuation allowance                  (2,126,018)    (3,223,106)
                                                   ----------     ----------

        Total provision for income taxes                   --             --
                                                   ==========     ==========

      As of December 31, 2003, the Company has a net operating loss
      carry-forward of approximately $7,054,281 which is available to reduce
      future taxable income, if any, through 2024. Management has determined
      that it is more likely than not that the benefit of the deferred tax asset
      will not be realized and thus has provided a 100% valuation allowance
      against the deferred tax asset.

11   REORGANIZATION

      On January 22, 2002, the Company completed a corporate reorganization
      which became effective February 8, 2002. At a meeting held on January 18,
      2002, the shareholders of Gothic approved an arrangement under Section 192
      of the Canada Business Corporations Act whereby the shareholders of Gothic
      voted to exchange all their common shares for shares of ANEC. The effect
      of the reorganization was that Gothic, which had formerly been the parent
      corporation of ANEC, became its wholly-owned subsidiary and ANEC became
      the parent corporation. The shareholders of Gothic tendered their share
      certificates and received a like number of shares of ANEC. All outstanding
      warrants and options to purchase shares of Gothic now represent the right
      to purchase shares of ANEC on substantially the identical terms and
      conditions. The shares of Gothic are no longer listed on the Toronto
      Venture Exchange, Inc. and in their place, the shares of ANEC were listed
      on that exchange, quoted and traded in U.S. dollars under the symbol
      ANR.U. Also on that date, the shareholders approved the reduction of the
      stated capital of Gothic by the amount of the accumulated deficit of
      $2,015,495. This transaction has been accounted for as a
      quasi-reorganization. Gothic may be deemed a predecessor of the Company.

      Upon petition of Gothic, the Supreme Court of British Columbia, at a
      hearing held on January 22, 2002, considered the fairness of the terms and
      conditions of the reorganization. All the security holders of Gothic were
      mailed a notice dated December 19, 2001 of the hearing and had the
      opportunity to appear. Upon finding that the terms of the transaction were
      fair, both procedurally and substantively, to the security holders of
      Gothic, the Court entered an order approving the reorganization pursuant
      to the provisions of Section 192 of the Canada Business Corporations Act.
      The British Columbia Court was advised by Gothic in the petition presented
      to the Court before the hearing that ANEC would rely on the exemption from
      the registration requirements of the Securities Act of 1933, as amended,
      contained in Section 3(a) (10) thereof in issuing its shares in exchange
      for the shares of Gothic


                                     F-26

<PAGE>

12   SUBSEQUENT EVENTS

      On December 19, 2003, the Company entered into a letter agreement with
      ExxonMobil whereby the terms of the Joint Development Agreement (the
      "Agreement") by and between the Company and ExxonMobil were expanded with
      the occurrence of specific events (the "Expansion Agreement"). The Company
      at its sole risk and expense drilled two wells in specific locations to
      minimum depths of 8,000 feet and 7,700 feet, the first within 90 days of
      the date of the execution of the Expansion Agreement and the second,
      within 90 days of reaching total depth on the first well. With completion
      of the first well on January 1, 2004, an additional 1,280 acres were added
      by ExxonMobil to the area in the Agreement and the termination date was
      extended to November 2007. With completion of the requirements of the
      second well on February 12, 2004, an additional 1,280 acres were added by
      ExxonMobil to the area in the Agreement.

13   DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

      Net Capitalized Costs

      The following summarizes net capitalized costs as of December 31, 2003 and
      2002.

                                                         2003         2002
                                                          $             $
                                                         ----         ----
      Oil and gas properties
           Proved                                     12,058,920      8,049,878
           Unproved                                    3,773,136      2,710,994
                                                      ----------     ----------
                Total                                 15,832,056     10,760,872

      Less accumulated depreciation, depletion and
      amortization and impairment                     (8,356,023)    (6,960,678)
                                                      ----------     ----------

      Net capitalized costs                            7,476,033      3,800,194
                                                      ==========     ==========


      Unproved Property Costs

      The following summarizes the capitalized unproved property costs excluded
      from amortization as of December 31, 2003. All costs represent investment
      in unproved property in Louisiana and will be evaluated over several years
      as the properties are explored.

                               2003        2002         2001        Total
                                $           $            $            $
                               ----        ----         ----        -----
Property acquisition costs    262,130     535,680    1,986,640    2,784,450
Capitalized interest          712,829     275,857           --      988,686
                              -------     -------    ---------    ---------
                              974,959     811,537    1,986,640    3,773,136
                              =======     =======    =========    =========


                                     F-27

<PAGE>

      Costs Incurred in Oil and Gas Acquisition, Exploration and Development

                                            2003             2002
                                             $                 $
                                            ----             ----

      Development costs                   2,953,794            681,102
      Exploration costs                   1,331,286          2,842,783
      Acquisition costs (1)
           Proved                                --                 --
           Unproved                         974,959            811,537
      Sales of properties                  (618,855)        (1,667,581)
                                          ---------         ----------

                                          4,641,184          2,667,841
                                          =========         ==========

----------
(1)   Acquisition costs exclude asset retirement costs of $430,000 upon
      implementation of SFAS 143 as of January 1, 2003.

      Results of Operations from Oil and Gas Producing Activities

      The Company's results of operations from oil and gas producing activities
      are presented below for the years 2003 and 2002. The following table
      includes revenues and expenses associated directly with our oil and gas
      producing activities. It does not include any general and administrative
      costs or any interest costs.
<TABLE>
<CAPTION>

                                                                 2003          2002
                                                                   $              $
                                                               ----------      ----------
<S>                                                            <C>               <C>
      Oil and gas sales                                         1,698,992         308,514
      Operations income                                            43,902           2,751
      Lease operating expenses                                   (495,409)       (481,711)
      Production taxes                                            (66,807)        (11,115)
      Net gain (loss) from sale of oil and gas properties          43,937        (726,348)
      Impairment of oil and gas properties                       (653,886)     (6,476,993)
      Depreciation, depletion and amortization                 (1,024,676)       (410,050)
                                                               ----------      ----------

      Results of operations from oil and gas activities          (453,947)     (7,794,952)
                                                               ==========      ==========
</TABLE>

      Oil and Gas Reserve Quantities (unaudited)

      The reserve information presented below is based on reports prepared by
      independent petroleum engineers Netherland, Sewell and Associates, Inc.

      The information is presented in accordance with regulations prescribed by
      the Securities and Exchange Commission. Reserve estimates are inherently
      imprecise. These estimates were generally based upon extrapolation of
      historical production trends, analogy to similar properties and volumetric
      calculations. Accordingly, these estimates are expected to change, and
      such change could be material and occur in the near term as future
      information becomes available.


                                     F-28

<PAGE>

      Proved oil and gas reserves represent the estimated quantities of crude
      oil, natural gas and natural gas liquids which geological and engineering
      data demonstrate with reasonable certainty to be recoverable in future
      years from known reservoirs under current economic and operating
      conditions. Proved developed oil and gas reserves are those expected to be
      recovered through existing equipment and operating methods.

      December 31, 2003
      -----------------
<TABLE>
<CAPTION>

                                                                   OIL                GAS                 TOTAL
                                                                 (mbbl)              (mmcf)              (mmble)
                                                                 ------              ------              -------
<S>                                                              <C>                 <C>                 <C>
       Proved reserves, beginning of period                      114.53              40.01               121.20
       Extensions, discoveries and other additions                77.09             203.71               111.04
       Revisions of previous estimates                            71.09              56.70                80.54
       Production                                                (50.25)             (6.20)              (51.28)
       Sale of reserves in place                                 (32.91)            (21.75)              (36.54)
       Purchase of reserves in place                                 --                 --                   --
                                                                 ------             ------               ------
       Proved reserves, end of period                            179.55             272.47               224.96
                                                                 ======             ======               ======

       Proved developed reserves:
            Beginning of period                                   18.02                 --                18.02
                                                                 ======             ======               ======
            End of period                                        110.93             212.43               146.34
                                                                 ======             ======               ======
</TABLE>



      December 31, 2002
      -----------------

<TABLE>
<CAPTION>
                                                                   OIL              GAS                   TOTAL
                                                                 (mbbl)            (mmcf)                (mmble)
                                                                 ------            ------                -------
<S>                                                              <C>             <C>                    <C>
       Proved reserves, beginning of period                          --                 --                   --
       Extensions, discoveries and other additions               126.44           1,445.75               367.40
       Revisions of previous estimates                               --                 --                   --
       Production                                                (11.91)            (13.06)              (14.09)
       Sale of reserves in place                                     --          (1,392.68)             (232.11)
       Purchase of reserves in place                                 --                 --                   --
                                                                 ------          ---------               ------

       Proved reserves, end of period                            114.53              40.01               121.20
                                                                 ======             ======               ======

       Proved developed reserves:
            Beginning of period                                      --                 --                   --
                                                                 ======             ======               ======
            End of period                                         18.02                 --                18.02
                                                                 ======             ======               ======
</TABLE>


      The Company had no proved reserves at December 31, 2001.

                                      F-29
<PAGE>


      Standardized Measure of Discounted Future Net Cash Flows (unaudited)

      Statement of Financial Accounting Standards No. 69 prescribes guidelines
      for computing the standardized measure of future net cash flows and
      changes therein relating to estimated proved reserves. The Company has
      followed these guidelines which are briefly discussed below.

      Future cash inflows and future production and development costs are
      determined by applying year-end prices and costs to the estimated
      quantities of oil and gas to be produced. The prices used at December 31,
      2003 and December 31, 2002 were $29.25 and $30.16 per barrel for oil and
      $5.97 and $4.74 per mmbtu for natural gas, respectively. Estimates are
      made of quantities of proved reserves and the future periods during which
      they are expected to be produced based on year-end economic conditions.
      Estimated future income taxes are computed using current statutory income
      tax rates including consideration for current tax basis of properties and
      related carryforwards, giving effect to permanent differences and tax
      credits. The resulting future net cash flows are reduced to present value
      amounts by applying a 10% annual discount factor.

      The assumptions used to compute the standardized measure are those
      prescribed by the Financial Accounting Standards Board and, as such, do
      not necessarily reflect our expectations of actual revenue to be derived
      from those reserves nor their present worth. The limitations inherent in
      the reserve quantity estimation process, as discussed previously, are
      equally applicable to the standardized measure computations since these
      estimates are the basis for the valuation process.

      The following sets forth our future net cash flows relating to proved oil
      and gas reserves based on the standardized measure prescribed in SFAS 69:

<TABLE>
<CAPTION>
                                                                                     December 31,
                                                                               2003                2002
                                                                                $                   $
                                                                               ----                ----
<S>                                                                        <C>                  <C>
     Future cash inflows                                                    7,464,800           3,644,000
     Future production taxes                                                 (574,200)           (202,000)
     Future development costs                                              (1,178,400)           (827,700)
     Future production costs                                               (1,323,600)           (957,300)
     Estimated future Net Profits payments                                    (22,800)           (366,200)
     Future income tax provision                                                   --                  --
                                                                           ----------           ---------
     Net future cash flows                                                  4,365,800           1,290,800
     Less effect of a 10% discount factor                                    (676,100)           (201,600)
                                                                           ----------           ---------
     Standardized measure of discounted future net cash flows               3,689,700           1,089,200
                                                                           ==========           =========
     Discounted (at 10%) future net cash flows before income taxes          3,689,700           1,089,200
                                                                           ==========           =========
</TABLE>

                                      F-30
<PAGE>

      The principal sources of change in the standardized measure of discounted
      future net cash flows are as follows:

<TABLE>
<CAPTION>
                                                                                     December 31,
                                                                                 2003            2002
                                                                                  $                $
                                                                                 ----            ----
<S>                                                                          <C>              <C>
     Standardized measure, beginning of period                               1,089,200               --
     Sales of oil and gas produced, net of production costs                   (464,630)        (218,147)
     Extensions and discoveries, net of future production and
     development costs                                                       3,397,830        2,861,666
     Sales of oil and gas properties                                                --         (986,519)
     Change in estimated net profits payments                                  343,400         (366,200)
     Accretion of discount                                                    (676,100)        (201,600)
                                                                             ---------        ---------
     Standardized measure, end of period                                     3,689,700        1,089,200
                                                                             =========        =========
</TABLE>



                                      F-31