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SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549
 FORM 10-KSB Mark One: þ Annual Report
pursuant to Section 13 or 15(d) of the Securities Exchange Act
of 1934.For the fiscal year ended December 31, 2004; oro Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934For the transition period from  to . Commission File No. 0-18956 American Natural
Energy Corporation
 
  Oklahoma
    
    73-1605215(State or Other Jurisdiction of
Incorporation or Organization)
    
    (IRS Employer
Identification No.)
 6100 South Yale, Suite 300, Tulsa, Oklahoma 74136 
 (Address of Principal Executive Offices)
    
    (Zip Code)
 918-481-1440 
  Securities registered under Section 12(b) of the Exchange Act: Title of Each Class
    
    Name of Each Exchange on Which Registered
  
 Securities Registered Pursuant to Section 12(g) of the Exchange Act: 
   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. þ Yes o 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. þ State Issuers revenues for its most recent fiscal year: $3,255,773. 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 15, 2005, was $7,332,149.(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
15, 2005, was 35,603,335. DOCUMENTS INCORPORATED BY REFERENCE
None




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Table of Contents  
 PagePart IItem 1. Description of Business
    
    
    3Item 2. Description of Property
    
    
    19Item 3. Legal Proceedings
    
    
    19Item 4. Submission of Matters to a Vote of Security Holders
    
    
    19Part IIItem 5. Market for Common Equity, Related Stockholder Matters
and Small Business Issuer Purchases of Equity Securities
    
    
    20Item 6. Managements Discussion and Analysis or Plan of
Operation
    
    
    22Item 7. Financial Statements
    
    
    45Item 8. Changes In and Disagreements With Accountants On
Accounting and Financial Disclosure
    
    
    45Item 8A Controls and Procedures
    
    
    45Item 8B Other Information
    
    

    45Part IIIItem 9. Directors, Executive Officers, Promoters and Control
Persons; Compliance with Section 16(a) of the Exchange Act
    
    
    46Item 10. Executive Compensation
    
    
    49Item 11. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters
    
    
    50Item 12. Certain Relationships and Related Transactions
    
    
    52Item 13. Exhibits
    
    
    55Item 14. Principal Accountant Fees and Services
    
    
    57BY LAWS, AS AMENDED THROUGH SEPTEMBER 13, 2004CERTIFICTION OF PRESIDENT AND CHIEF EXECUTIVE OFFICERCERTIFICATION OF CHIEF FINANCIAL OFFICERCERTIFICATION OF PRESIDENT AND CEO PURSUANT TO SECTION 1350CERTIFICATION OF CFO PURSUANT TO SECTION 1350
  2




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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. 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. During 2002, we were able to return to production 5 (4.06 net) well bores drilled by the prior
owners on the Couba properties we acquired. During 2004 we restored 3 (2.44) additional well bores
to production. Our drilling activities commenced in February 2003 and as of December 31, 2004, we
had drilled and completed 7 (2.61 net) wells. By December 31, 2004, our combined production from
all our producing wells (15 gross, 9.11 net) was approximately 665 (180 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. The Louisiana Properties 3




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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:  
    we acquired substantially all the assets of Couba and its outstanding capital stock,
    we paid approximately $2.1 million in cash,
    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.
    we assumed $204,000 of other additional secured liabilities of Couba,
    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 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, 4




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excluding, however, the Bayou Couba Lease. Upon payment of their allowed claims, inclusive
of interest, such royalty and net profits interests terminate.
    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 further area of mutual interest agreement relating to a portion of the 23.5 square mile
area, excluding the Bayou Couba Lease acreage with Wiser Oil Company, a non-affiliated party, was
terminated in December 2004. The termination involved a payment by us to Wiser of $100,000 and we
and Wiser exchanged releases and terminated certain litigation we were involved in relating to an
interpretation of the agreement. 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, 2004, all within the
boundaries of the proprietary 3-D seismic data. This lease was renewed annually in 2003 and 2004
and expired in February 2005. We may seek in the future to re-lease a portion of the acreage
included in the original 2002 lease. 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 5




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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 was drilled and was plugged after
reaching total depth. The second well reached the minimum depth requirement as of February 12,
2004, required under the Expansion Agreement. 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. The second well drilled under the Expansion Agreement was 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-drill the well. We have initiated a lawsuit
against the supplier of tools which we claim caused the mechanical failure seeking to recover the
damages we sustained, including, among other damages, the cost of redrilling the well and our
expenses in attempting to mitigate our losses. 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 6,976,745 shares), it is the
beneficial holder of a total of 7,152,874 shares of our common stock. 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 6




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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. 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 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. Oil and Gas Reserves The tables below set forth information as of December 31, 2004 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 7




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estimated future net revenue shown is not intended to represent the current market value of
the estimated oil and gas reserves we own. OIL
    
    
    GAS
    
    
    TOTAL(MBbl)
    
    
    (Mmcf)
    
    
    (MBble)Proved developed producing
    
    
    35.82
    
    
    
    12.86
    
    
    
    37.97Proved developed non-producing
    
    
    54.69
    
    
    
    37.46
    
    
    
    60.93Proved undeveloped
    
    
    
    
    
    
    
    
    
    
    Total proved
    
    
    90.51
    
    
    
    50.32
    
    
    
    98.90
 Proved Developed
    
    
    Proved Developed
    
    
    ProvedProducing
    
    
    Non-producing
    
    
    Undeveloped
    
    
    Total ProvedEstimated future net revenue(a)
    
    $
    1,009,500
    
    
    $
    1,089,100
    
    
    
    
    
    
    $
    2,098,600Present value of future net revenue(b)
    
    $
    959,300
    
    
    $
    918,800
    
    
    
    
    
    
    $
    1,878,100
   (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, 2004. 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 $40.25 per barrel of oil and $6.18 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 $151,000 during 2005 and an additional $62,000 in
future periods to develop these reserves, the future net revenue attributable to our estimated
proved developed non-producing reserves would be calculated to be $1.01 million at December 31,
2004, with the present value thereof to be $919,000. 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, 2004, the capital necessary to develop these
additional reserves was unavailable to us. Through December 31, 2004, we had expended
approximately $11.5 million in exploration and 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. 8




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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. 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, 2004,
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 31,2002(1)(2)
    
    
    2003
    
    
    2004(3)Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetDevelopmentProductive
    
    
    -0-
    
    
    
    -0-
    
    
    
    5.0
    
    
    
    1.56
    
    
    
    -0-
    
    
    
    -0-Non-productive
    
    
    -0-
    
    
    
    -0-
    
    
    
    -0-
    
    
    
    -0-
    
    
    
    -0-
    
    
    
    -0-ExploratoryProductive
    
    
    4.0
    
    
    
    3.5
    
    
    
    1.0
    
    
    
    0.63
    
    
    
    1.0
    
    
    
    .42Non-productive
    
    
    -0-
    
    
    
    -0-
    
    
    
    1.0
    
    
    
    0.35
    
    
    
    2.0
    
    
    
    1.49
   (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.(3)
    
    Excludes 3 (2.44 net) wells drilled by prior owners on the Bayou Couba properties
which we returned to production during 2004. Recent Activities 9




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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. 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. One well drilled during 2003 was
unsuccessful and was plugged. Activities During 2004 and Present Activities During 2004, we restored to production 3 (2.44 net) wells that had been acquired as part of
the original Bayou Couba acquisition. We also drilled 3 (1.9 net) exploratory wells and completed
1 (.42 net) well. We plugged and have abandoned the ExxonMobil Fee 2 well and have abandoned the
ExxonMobil Fee 2ST well. At December 31, 2004, combined production from all our producing wells on the property was
approximately 665 (180 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. Our plans for 2005 include drilling one exploratory well and at least one development well.
Because of our limited capital available, drilling of these wells is contingent on our securing
industry participation in the financing of the drilling and completion costs. Such participation
has not yet been secured and we are unable to state at this time the expected terms of such
industry participation. At December 31, 2004, we have no commitments to expend funds for drilling
activities in 2005. 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,
2004. 10




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Well CountArea
    
    Gross(1)
    
    Net(1)St. Charles Parish, Louisiana
    
    
    15.0
    
    
    
    9.11
   (1)
    
    Thirteen of the fifteen wells have been classified as primarily oil
producing wells. Two wells are classified as gas 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 three years ended December 31, 2004. All of our production was from our properties
located in St. Charles Parish, Louisiana. Year Ended December 31,2004
    
    
    2003
    
    
    2002Net Production(1)Oil (Mbbl)
    
    
    59.8
    
    
    
    50.3
    
    
    
    11.9Natural Gas (Mmcf)
    
    
    134.6
    
    
    
    6.2
    
    
    
    13.1Oil Equivalent (Mbble)
    
    
    82.2
    
    
    
    51.3
    
    
    
    14.1Oil and
Natural Gas Sales:Oil
    
    $
    2,476,267
    
    
    $
    1,666,865
    
    
    $
    274,803Natural Gas
    
    $
    660,935
    
    
    $
    32,127
    
    
    $
    33,711Total
    
    $
    3,137,202
    
    
    $
    1,698,992
    
    
    $
    308,514Average Sales
Price:Oil ($per Bbl)
    
    $
    41.42
    
    
    $
    33.17
    
    
    $
    23.07Natural Gas ($per Mcf)
    
    $
    4.91
    
    
    $
    5.18
    
    
    $
    2.58Oil Equivalent ($per Bble)
    
    $
    38.16
    
    
    $
    33.13
    
    
    $
    21.90Oil and
Natural Gas Costs:Lease operating expenses
    
    $
    429,315
    
    
    $
    495,409
    
    
    $
    481,711Production Taxes
    
    $
    232,135
    
    
    $
    66,807
    
    
    $
    11,115Net gain (loss) from sale of oil and
natural gas properties
    
    $
    (44,411
    )
    
    $
    43,937
    
    
    $
    (726,348
    )Impairment of oil and natural gas
properties
    
    $
    7,676,670
    
    
    $
    653,886
    
    
    $
    6,476,993Depreciation, depletion and amortization
    
    $
    2,558,719
    
    
    $
    919,628
    
    
    $
    410,050Average production cost per unit of
production
    
    $
    8.05
    
    
    $
    10.96
    
    
    $
    34.19
 11




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##### Table of Contents



Development, Exploration and Acquisition Expenditures The following table sets
forth certain information regarding the costs we incurred in our development, exploration and acquisition activities during the periods indicated: Year Ended
    
    
    Year Ended
    
    
    Year EndedDecember 31, 2002
    
    
    December 31, 2003
    
    
    December 31, 2004Development Costs
    
    $
    681,102
    
    
    $
    2,953,794
    
    
    $
    2,385,689Exploration Costs
    
    $
    2,842,783
    
    
    $
    1,331,286
    
    
    $
    5,259,630Acquisition Costs(1)
    
    $
    535,680
    
    
    $
    262,130
    
    
    $
    229,673Sales of Oil and Gas Properties
    
    $
    (1,667,581
    )
    
    $
    (618,855
    )
    
    $
    Capitalized Interest
    
    $
    275,857
    
    
    $
    712,829
    
    
    $
    439,135Total
    
    $
    2,667,841
    
    
    $
    4,641,184
    
    
    $
    8,314,127
   (1)
    
    Acquisition costs for 2003 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, 2004, 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 andDeveloped(1)
    
    
    Undeveloped(1)(2)
    
    
    UndevelopedArea
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetLouisiana
    
    
    1,320
    
    
    
    1,072
    
    
    
    1,913
    
    
    
    1,640
    
    
    
    3,233
    
    
    
    2,712Total
    
    
    1,320
    
    
    
    1,072
    
    
    
    1,913
    
    
    
    1,640
    
    
    
    3,233
    
    
    
    2,712
   (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 12




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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.(2)
    
    In February 2005 a lease covering 1,729 acres with the State of Louisiana expired. 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 2004, our oil sales to Teppco Crude Oil, L.P. of $2,476,267 accounted
for 79% 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 $660,935 accounted
for 21% of 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. 13




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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, 2004, 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 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. 14




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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 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 15




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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. 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 16




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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 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 17




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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. Employees As of December 31, 2004, we employed seven persons, of which two were executive officers and
three were operations personnel and two were accounting staff. We outsource our 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. Prior Activities and Organization 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 and was not an affiliate of ours. 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 a
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. 18




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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 6100 South Yale, Suite 300, Tulsa, Oklahoma 74136.
Additionally, we maintain office space in The Woodlands, Texas. Our leased premises include
approximately 4,899 square feet and are leased for various terms expiring in 2009. The annual
aggregate rental is $85,733. 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: No 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, 2004 to a
vote of securityholders through the solicitation of proxies or otherwise. 19




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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,
2004 and through March 15, 2005 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. PricesHigh
    
    
    Low
    
    
    Share Volume2003First Quarter
    
    $
    0.83
    
    
    $
    0.35
    
    
    
    4,805,444Second Quarter
    
    $
    0.80
    
    
    $
    0.35
    
    
    
    1,088,354Third Quarter
    
    $
    0.90
    
    
    $
    0.41
    
    
    
    4,296,356Fourth Quarter
    
    $
    1.20
    
    
    $
    0.59
    
    
    
    4,786,8962004First Quarter
    
    $
    1.15
    
    
    $
    0.31
    
    
    
    4,562,323Second Quarter
    
    $
    0.48
    
    
    $
    0.29
    
    
    
    3,109,403Third Quarter
    
    $
    0.40
    
    
    $
    0.28
    
    
    
    3,536,679Fourth Quarter
    
    $
    0.50
    
    
    $
    0.10
    
    
    
    7,905,1812005First Quarter (through
March 15, 2005)
    
    $
    0.31
    
    
    $
    0.12
    
    
    
    3,319,731
 Current prices for our shares on the TSX Venture Exchange can be found on the Internet at
www.tsx.com using the stock symbol anr.u. As of March 15, 2005, we had 2,875 stockholders of record. 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 20




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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®. 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®. 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®. 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® 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, 2004 Not Registered
Under the Securities Act of 1933, as Amended. During the year ended December 31, 2004 we issued the following securities not requiring
registration under the Securities Act of 1933, as amended: In June and July 2004, we issued 1,300,000 shares of our Common Stock to six persons, all
officers, Directors or employees of our company, on exercise of options issued under the 2001 Stock
Incentive Plan. The shares were issued to such persons in a transaction exempt from the
registration requirements of the Securities Act, by virtue of Section 4(2) thereof. Such persons
represented that the shares were purchased for investment, for their own account and not for
distribution in violation of the registration requirements of the Securities Act. A legend was
affixed to the share certificates stating the restrictions on further transfer. No underwriter
participated in the sale of the shares. 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, 2004. 21




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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 we produce
and sell. 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 2004 and 2003 of approximately $14.9
and $5.7 million, respectively, and have a working capital deficiency and an accumulated deficit at
December 31, 2004 which leads to questions concerning our ability to meet our obligations as they
come due. We also have a need for substantial funds to pay current liabilities and to develop our
oil and gas properties. We have financed our activities using debt and equity financings and we
have no bank or other line of credit or other financing agreement providing borrowing availability
with a commercial lender. 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 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. 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 registered public accounting firms report on our financial statements as of
and for the year ended December 31, 2004 includes an explanatory paragraph which states that we
have sustained substantial losses in 2004 and 2003 and have a working capital deficiency and an
accumulated deficit at December 31, 2004 that raise substantial doubt about our ability to continue
as a going concern. 22




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Statements of Operations A Comparison of Operating Results For The Years Ended December 31, 2004 and December 31, 2003 We incurred a net loss of $14,887,000 during the year ended December 31, 2004 compared to a
net loss of $5,682,000 for the year ended December 31, 2003. During the year ended December 31,
2004, our revenues were comprised of oil and gas sales and operations income totaling $3,254,000
compared with oil and gas sales and operations income of $1,743,000 in 2003. Our oil and gas sales
and operations income for the year ended December 31, 2004 continued to increase primarily because
of the revenues resulting from our increased oil and gas production from the wells drilled during
the last three years as well as because of higher commodity prices in 2004. Production on a
barrels equivalent basis increased 59% from 2003 to 2004. Oil prices increased on average 32% from
2003 to 2004 while natural gas prices increased on average 18% over the same period. At December
31, 2004, we had 15 (9.11 net) wells producing approximately 665 (180 net) barrels of oil
equivalents per day, whereas at December 31, 2003 we had 11 (6.25 net) wells producing
approximately 400 (120 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 2004 of $1,900 compared with interest and other
income of $4,200 in 2003. Our total expenses were $17,817,000 for the year ended December 31, 2004 as compared to
$6,423,000 for the year ended December 31, 2003. Total expenses increased due to higher
impairment, interest and depletion charges in 2004. Lease operating expenses in 2004 were $429,000 compared to $495,000 in 2003. These expenses
decreased as a result of more efficient operations. Production taxes of $232,000 and depletion,
depreciation and amortization of $2,989,000 in 2004 increased from $67,000, and $1,103,000,
respectively in 2003 reflecting the increase in production and capital spending in 2004. The
increase in production taxes was due to higher production and higher oil prices. Our general and administrative expenses in 2004 were $2,078,000 compared to $1,938,000 in
2003. These expenses also increased in 2004 because of our increased activities directed at the
development of additional wells and production of oil and gas from those wells. Additionally,
expenses relating to professional fees and filing and regulatory fees increased in 2004. We had a foreign exchange loss of $722,000 and $1,716,000 in 2004 and 2003, respectively. Our
foreign exchange losses arise out of an inter-company indebtedness we owe to our wholly-owned
subsidiary, Gothic, which is repayable in Canadian dollars. The foreign exchange loss was caused by
the strengthening of the Canadian dollar against the US dollar. Effective February 2005 an
application has been made to liquidate the Gothic 23




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subsidiary and terminate its charter. Therefore, upon final liquidation in 2005, amounts
reflected in accumulated other comprehensive income will be reclassified to earnings. In 2003, we
had a gain on the sale of marketable securities of $173,000. We had no such gain in 2004, and the
Company no longer holds marketable securities. In 2003, we also incurred a loss of $222,000 as a
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 sale of the
Debentures. We had no such loss in 2004. We had a loss on the sale of oil and gas properties in
2004 of $44,000 compared to a gain of $44,000 in 2003. These amounts are due to the sale of our
Oklahoma coalbed methane leasehold interests. Interest expense, net of interest capitalized of $608,000 and $713,000 in 2004 and 2003,
respectively, increased to $3,631,000 in 2004 from $440,000 in 2003. While debt outstanding
increased during 2004, interest expense also reflects the amortization of a beneficial conversion
feature related to the issuance in October 2003 of the Companys Debentures. On the dates the
Debenture transaction was completed, the closing price for our Common Stock was $0.70 per share.
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. An
additional beneficial conversion feature of $858,000 was recorded in the third quarter of 2004
resulting from issuance of shares of our common stock pursuant to a Rights Offering. Due to
antidilution provisions contained in the Debenture Agreement, the issuance of shares of common
stock changed the conversion price of the debentures from $.45 to $.43 per share resulting in the
additional beneficial conversion feature. Such amount will be amortized to interest expense over
the life of the Debentures which mature on September 30, 2005. As debentures are converted prior
to maturity, any unamortized amount attributed to such debentures will be expensed at the time of
conversion. Amortization of the beneficial conversion feature was $3,257,000 in 2004 and $399,000
in 2003. As debentures are converted prior to maturity, any unamortized amount attributed to
such debentures will be expensed at the time of conversion. During 2004, $325,000 of Debentures
was converted and a related $137,000 beneficial conversion feature was expensed. We incurred an impairment charge reflecting a write-down of the carrying value of our oil and
gas properties of $7,677,000 in 2004 compared to an impairment charge of $654,000 in 2003. Our
impairment charges in 2004 and 2003 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 and were primarily the result of drilling two unsuccessful exploratory wells and the
impairment of undeveloped properties. Depreciation, depletion and amortization expenses increased to $2,558,000 during the year
ended December 31, 2004 from $919,628 during the year ended December 31, 2003. This was primarily
the result of our increased production of oil and natural gas and the related depletion expense. In the third quarter of 2004, the Company changed its method of capitalizing interest on
qualifying expenditures related to unproved properties. The Company changed from 24




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using a capitalization rate which includes deemed interest from amortization of a beneficial
conversion feature associated with the Companys Debentures to a rate which excludes the impact of
the beneficial conversion feature. This resulted in a charge for the cumulative effect of an
accounting change in the amount of $326,000. We also had a charge in 2003 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. Our accounts payable increased to $8,340,000 at December 31, 2004 from $3,600,000 at December
31, 2003 resulting primarily from the increased scale of our operations and costs incurred in the
drilling of two unsuccessful exploratory wells. We are paying our accounts payable out of our
current revenues and through March 15, 2005, had not experienced any material disruption in
services or purchases from vendors on account of outstanding payables. 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 25




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$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
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. Liquidity and Capital Resources General 26




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Since 2001, we have funded our capital expenditures and operating activities through a series
of debt and equity capital-raising transactions and, during the last two quarters of 2004, through
an increase in vendor payables. At December 31, 2004, we do not have any available borrowing
capacity under existing credit facilities and our current assets are $1.8 million compared with
current liabilities of $16.2 million. Our current liabilities include approximately $11.7 million
of secured indebtedness, including the related fully amortized discount, due in September 2005 and
accounts payable and revenues payable aggregating approximately $8.3 million. We have substantial
needs for funds to pay our outstanding payables and debt due during 2005. In addition, we have
substantial need for capital to develop our oil and gas prospects and opportunities identified in
our ExxonMobil AMI. Any capital expenditures for drilling purposes during 2005 we expect will be
funded from the sale of drilling participations. It is managements plan to raise additional
capital through 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. Years Ended December 31, 2004 and December 31, 2003 Our net cash provided by operations was $3,858,000 for the year ended December 31, 2004 as
compared to net cash used in operations of $361,000 for 2003. While production from our drilling
program has increased revenues in 2004, such increase has not been sufficient to fund our
operations. Cash provided by operating activities was impacted in 2004 by a foreign currency exchange loss
of $722,000, which did not affect our cash position. Depletion, depreciation and amortization was
$2,989,000 in 2004, resulting from increased activity in our oil and gas operations, compared to
$1,103,000 in 2003. Accounts payable, accrued liabilities and interest increased significantly in
2004 over 2003 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 $7,677,000, resulting from
ceiling test write-down, in 2004 compared to $654,000 in 2003. 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, 2004 and December 31, 2003 the estimated future net cash flows
to be derived from our proved reserves as of those respective dates and was primarily the result of
drilling two unsuccessful exploratory wells and the impairment of
undeveloped properties. In the third quarter of 2004, the Company changed its method of capitalizing interest on
qualifying expenditures related to unproved properties. The Company changed from using a
capitalization rate which includes deemed interest from amortization of a beneficial conversion
feature associated with the Companys Debentures to a rate which excludes the impact of the
beneficial conversion feature. This resulted in a charge for the cumulative effect of an
accounting change in the amount of $326,000. 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. 27




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We used $6,897,000 of net cash in investing activities during the year ended December 31, 2004
compared to net cash used of $4,109,000 in 2003. The 2004 cash used in investing activities
includes $6,786,000 for the purchase and development of oil and gas properties and $111,000 for the
purchase of fixed assets compared to $4,635,000 and $144,000, respectively, in 2003. Proceeds from
the sale of marketable securities, net of cash expended on purchases of marketable securities, were
$208,000 in 2003, and proceeds from the sale of oil and gas properties amounted to $462,000 in
2003. There were not proceeds from such transactions in 2004. Our net cash provided by financing activities for the year ended December 31, 2004 was
$1,693,000 compared to $6,039,000 provided in 2003. The activity in 2004 was the result of
completing the sale, pursuant to the issuance of stock purchase rights to all our stockholders, of
6,941,414 shares of our common stock, and the exercise of 1.3 million stock options by directors,
officers and employees. 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, 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 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 28




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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. 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 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 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. 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 29




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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 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. 30




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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. 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:  
    taxable income projections in future years,
    whether the carryforward period is so brief that it would limit realization of tax
benefits,
    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
    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 31




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carryforwards prior
to their expiration. Accordingly, we are required to provide a
valuation allowance against our deferred tax asset. As of December 31, 2004 and 2003 we have a
deferred tax asset of approximately $11.4 million and $5.6 million for which we have recognized an
$11.4 million and $5.6 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 utilizing units of production basis for
production based loan agreements. Any unamortized 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 sales of debt and equity
securities. Most recently, in August 2004, we completed the sale, pursuant to the issuance of
stock purchase rights to all our stockholders, of 6,941,414 shares of our common stock for gross
proceeds of $1,665,939. After deducting the expenses of the offering,
$1,433,287 of the net
proceeds was applied to our oil and natural gas well drilling activities, including the re-drilling
of the ExxonMobil Fee 2 well. The ExxonMobil Fee 2 well was originally drilled in the first
quarter of 2004 and encountered mechanical problems. During the course of the original drilling of
the well, we gathered evidence concerning this location that we considered to be encouraging. In
October 2004, we announced that the re-drilled ExxonMobil Fee 2 ST well was being plugged and
abandoned as a result of mechanical problems arising from drilling tools dropped in the hole and
irretrievably lost during the final phases of drilling to a total measured depth of approximately
10,830 feet. In the re-drilling of the well, we had encountered what we believed were potentially
productive horizons from approximately 10,700 feet to 10,790 feet total measured depth. We are
evaluating the possibility, subject to the availability of capital, of drilling an additional well
from a new surface location to test potential horizons that were encountered in the original well
below a total measured depth of approximately 11,000 feet. 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
current conversion price of $0.43 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 32




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$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 used 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 Debenture financing and under the terms of the transaction, two persons
were designated to serve as Directors of our corporation. Currently, Mr. Jules Poscente, Chairman
and Director of Eurogas Corp. of Calgary, Alberta, and Gerry Curtis of Bermuda have been 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. 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 $0.43 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 $7.5 million. This amount will be amortized
to interest expense over the life of the Debentures which mature on September 30, 2005. As
Debentures are converted prior to September 30, 2005, any unamortized discount attributed to those
proportionate holdings will be expensed at the time of conversion. During 2004, $325,000 of
Debentures was converted and a related $137,000 beneficial conversion feature was expensed. Future Capital Requirements and Resources 33




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Since 2001, we have funded our capital expenditures and operating activities through a series
of debt and equity capital-raising transactions and, during the last two quarters of 2004, through
an increase in vendor payables. At December 31, 2004, we do not have any available borrowing
capacity under existing credit facilities and our current assets are $1.8 million compared with
current liabilities of $16.2 million. Our current liabilities include approximately $11.7 million
of secured indebtedness, including the related fully amortized discount, due in September 2005 and
accounts payable and revenues payable aggregating approximately $8.3 million. We have substantial
needs for funds to pay our outstanding payables and debt due during 2005. In addition, we have
substantial need for capital to develop our oil and gas prospects and opportunities identified in
our ExxonMobil AMI. Any capital expenditures for drilling purposes during 2005 we expect will be
funded from the sale of drilling participations. It is managements plan to raise additional
capital through 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. At December 31, 2004, we have no commitments for additional capital to fund drilling
activities in 2005. Any capital expenditures will be funded from monies raised through industry
participations, or, if available, borrowings or equity capital. We currently have no borrowing
capacity with any lender and 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 drilling participations, joint ventures, 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 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 Combinationsand Statement of
Financial Accounting Standards No. 142, Goodwill and Intangible Assetswere 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 sets forth guidelines 34




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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. Consistent
with oil and gas accounting and industry practice, the Company classifies the cost of oil and gas
mineral rights as property and equipment and not as intangible assets. In September 2004, the FASB issued FASB Staff Position, FSP SFAS 142-2, Application of FASB
Statement No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Producing Entities. The FSP
clarifies that an exception in SFAS 142 includes the balance sheet classification and disclosures
for drilling and mineral rights of oil and gas producing entities. The FASB staff acknowledges that
the existing accounting framework for oil and gas producers is based on the level of established
reserves, not whether an asset is tangible or intangible. The FSP confirms the Companys historical
treatment of these costs. In September 2004, the SEC issued Staff Accounting Bulletin No. 106 providing guidance
regarding the interaction of SFAS No. 143, Accounting for Asset Retirement Obligations,with the
full cost accounting rules in Article 4-10 of Regulation S-X. The Bulletin provides guidance for
calculation for the full cost ceiling calculation and for the calculation of depreciation,
depletion and amortization. The Bulletin is effective for the Companys reporting quarter
commencing October 1, 2004. The Company does not anticipate any significant effects on financial
position, results of operations or changes in cash flow from the implementation of these
guidelines. In September 2004, the Emerging Issues Task Force issued EITF No. 04-8, The Effect of
Contingently Convertible Instruments on Diluted Earnings per Share.EITF No. 04-8 provides new
guidance on when the dilutive effect of contingently convertible securities with a market price
trigger should be included in diluted EPS. The new guidance states that these securities should be
included in the diluted EPS computation regardless of whether the market price trigger has been
met. The guidance in EITF 04-8 is effective for all periods ending after December 15, 2004 and
would be applied by retrospectively restating previously reported EPS. This pronouncement has no
impact on the Company. In December 2004, the FASB issued Statement on Financial Accounting Standards No. 123 (Revised
2004), Share-Based Payment, revising FASB Statement No. 123, Accounting for Stock-Based
Compensation and superseding APB Opinion No. 25, Accounting for Stock Issued to Employees. This
statement requires a public entity to measure the cost of services provided by employees and
directors received in exchange for an award of equity instruments, including stock options, at a
grant-date fair value. The fair value cost is then recognized over the period that services are
provided. FAS 123 (Revised 2004) is effective for interim and annual periods that begin after June
15, 2005 and will be adopted by the Company in third quarter of 2005. See Note 1 of these
financial statements for a disclosure of the effect on net income and earnings per share for the
years 2003 and 2004 if the Company had applied the fair value recognition provision of FAS 123 to
stock-based employee compensation. 35




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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 2003, and 2004, totaling approximately
$5.7 million and $14.9 million, respectively, and had a working capital deficiency at December 31,
2004 of approximately $14.4 million. We had a negative cash flow from operations in 2003 and 2002.
While production from our drilling program has increased revenues in 2004, 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 pay our current
liabilities and to continue to explore for and develop our oil and gas reserves. The independent registered public accounting firms report on our financial statements as of
and for the year ended December 31, 2004 includes an explanatory paragraph which states that we
have sustained substantial losses in 2004 and 2003 and have a working capital deficiency and an
accumulated deficit at December 31, 2004 that raise substantial doubt about our ability to continue
as a going concern. We Must Repay $11.675 Million of Secured Indebtedness on September 30, 2005. There Are Risks
That This Indebtedness May Not Be Repaid When Due. 36




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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. During 2004 a total of $325,000 of debentures was converted to common stock.
The remaining $11.675 million borrowing is due to be repaid on September 30, 2005. The loan is
collateralized by a lien against all our oil and natural gas properties and undeveloped leaseholds
and bears interest at 8% per annum, payable quarterly commencing December 31, 2003. The
indebtedness is convertible into shares of our common stock at a current conversion price of $0.43
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 Current Liabilities as of December 31, 2004 Exceed Our Current Assets by $14.4 Million As of December 31, 2004, our current assets were approximately $1.8 million and our current
liabilities were approximately $16.2 million. Our current liabilities are net of a discount of
approximately $3.9 million realized on the issuance of the Debentures with a beneficial conversion
feature and which discount is amortized over the term of the Debentures. This discount will be
fully amortized at September 30, 2005 and our current liabilities will then include the outstanding
face amount of the Debentures or $11.675 million. Approximately $7.8 million, which is net of the
approximately $3.9 million of discount, was reflected as a current liability at December 31, 2004. In order to meet our current obligations, we are seeking to raise additional capital. At
March 15, 2005, we have no commitments from others to provide this capital and without additional
capital to meet these obligations, our continued operations cannot be assured. There can be no
assurance that we will be successful in raising additional capital or that the terms on which such
additional capital can be raised may not be disadvantageous to the holders of our common stock or
result in material dilution. Our inability to reduce our current liabilities relative to our
current assets could lead creditors to refuse to extend us further credit which could materially
adversely affect our operations. 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 also have substantial needs for funds to further develop our oil and gas prospects and
opportunities identified in our AMI with ExxonMobil Corp. At December 37




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31, 2004, we have no commitments for drilling activities in 2005. Any capital expenditures
will be funded from monies raised through industry participations, borrowings or equity capital.
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:  
    political conditions in oil producing regions, including the Middle East;
    the domestic and foreign supply of oil and gas;
    the level of consumer demand;
    weather conditions;
    domestic and foreign government regulations;
    the price and availability of alternative fuels;
    overall economic conditions; and
    international political conditions. In addition, various factors may adversely affect our ability to market our oil and gas
production, including:  
    the capacity and availability of oil and gas gathering systems and pipelines; 38




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
    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;
    the effect of federal and state regulation of production and transportation;
    general economic conditions;
    changes in supply due to drilling by other producers;
    the availability of drilling rigs and related crews; and
    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 equity 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. 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. 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 39




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The terms of our $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. 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:  
    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;
    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;
    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
    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. 40




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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 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, 2004, based on the report of Netherland, Sewell and Associates, Inc., we
claimed total estimated proved reserves of 98.9 MBble of oil and gas. We are 41




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currently seeking to develop additional producing wells on our Bayou Couba properties. As of
December 31, 2004, we were able to return to production 8 (6.50 net) well bores drilled by prior
owners on the Couba properties we acquired, and we had successfully completed 7 (2.61 net) wells.
As of that time, our combined production from all our producing wells was approximately 665 (180
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 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. 42




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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. 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 43




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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. 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 Item 1. Description of Business and Item 6.
Managements Discussion and Analysis or Plan of Operation. 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
and current liabilities, 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 successful
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. 44




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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 2005
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. 
 Item 8  Changes In and Disagreements With Accountants on Accounting and Financial
Disclosure: During the two fiscal years ended December 31, 2004, our principal independent accountant did
not resign and was not dismissed. 
 Item 8A  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. Our disclosure controls and procedures are the controls and other procedures that we have
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. 
 Item 8B  Other Information No information is required to be disclosed in response to this Item 8B. 45




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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
    
    PositionDirectors and Executive Officers:Michael K. Paulk
    
    
    56
    
    
    President and DirectorSteven P. Ensz
    
    
    53
    
    
    Vice President, Finance,
and Chief Financial
Officer and DirectorBrian E. Bayley(1)
    
    
    52
    
    
    DirectorJohn K. Campbell(1)
    
    
    71
    
    
    DirectorJules Poscente
    
    
    76
    
    
    DirectorGerry Curtis
    
    
    67
    
    
    DirectorSignificant Employees:Bennett G. Shelton
    
    
    48
    
    
    Manager of Land and
Contract AdministrationRichard O. Mulford
    
    
    52
    
    
    Manager of OperationsRobert G. Snead
    
    
    66
    
    
    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 energy industry, including President of
Waterford Energy, an independent oil and gas 46




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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. 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. Gerry Curtis:Mr. Curtis was elected a Director on October 18, 2004. Mr. Curtis is a
chartered accountant and received his Chartered Accountant designation in 1960. He was a partner
in the firm Leebosh, Dobrin, April & Curtis, Chartered Accountants, from 1964 to 1983. Since 1983,
Mr. Curtis has worked independently as a financial administrative consultant, first in Toronto,
then in London and is now based in Bermuda. He is President and Chief Executive Officer of Charter
Global Financial Ltd., a Bermuda corporation engaged in providing corporate services. Mr. Curtis
currently serves as a director on numerous private company boards and has also previously served as
a director for two public companies in the 1980s. 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. 47




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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. 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 March 1, 2005, 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. Under our Audit Committee Charter, our Audit Committees responsibilities include, among other
responsibilities, the appointment, compensation and oversight of the work performed by our
independent auditor, the adoption and assurance of compliance with a pre-approval policy with
respect to services provided by the independent auditor, at least annually, obtain and review a
report by our independent auditor as to relationships between the independent auditor and our
company so as to assure the independence of the independent auditor, review the annual audited and
quarterly financial statements with our management and the independent auditor, and discuss with
the independent auditor their required disclosure relating to the conduct of the audit. 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 was filed as an exhibit to our
Annual Report on Form 10-K for the year ended December 31, 2003. 48




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##### Table of Contents



Item 10 - Executive Compensation: The following table sets forth the annual and long-term compensation paid during our three
fiscal years ended December 31, 2004 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, 2004. SUMMARY COMPENSATION TABLE
Annual Compensation CompensationOther
    
    
    Long-TermName and
    
    
    
    
    
    Annual
    
    
    
    
    
    
    Annual
    
    
    Awards/ Option
    
    
    All OtherPrincipal Position
    
    Year
    
    
    Salary
    
    
    Bonus
    
    
    Comp.
    
    
    (#)
    
    
    Comp.Michael K. Paulk
    
    
    2004
    
    
    $
    125,000
    
    
    
    -0-
    
    
    
    -0-
    
    
    
    250,000
    (1)
    
    
    -0-2003
    
    
    $
    120,000
    
    
    
    -0-
    
    
    
    -0-
    
    
    
    -0-
    
    
    
    -0-2002
    
    
    $
    90,000
    
    
    
    -0-
    
    
    
    -0-
    
    
    
    -0-
    
    
    
    -0-Steven P. Ensz
    
    
    2004
    
    
    $
    125,000
    
    
    
    -0-
    
    
    
    -0-
    
    
    
    250,000
    (1)2003
    
    
    $
    120,000
    
    
    
    -0-
    
    
    
    -0-
    
    
    
    -0-
    
    
    
    -0-2002
    
    
    $
    90,000
    
    
    
    -0-
    
    
    
    -0-
    
    
    
    -0-
    
    
    
    -0-
   (1)
    On April 22, 2004, the Board of Directors granted options to
purchase shares of common stock under the Companys 2001 Stock Incentive Plan exercisable at a
price of $0.45 per share, subject, however, to the adoption by shareholders of certain
amendments to the Plan. Pending shareholder approval, stock options conditionally granted by
the Board of Directors are not exercisable and are not considered outstanding. Stock Option Exercises During the Year Ended December 31, 2004 and Holdings at
December 31, 2004. The following table provides information with respect to the above named
executive officer regarding options held at December 31, 2004. Options were conditionally granted
to such persons during the year ended December 31, 2004 pending approval by shareholders of certain
amendments to the Companys 2001 Stock Incentive Plan. Number of Unexercised Options
    
    
    Value of Unexercised In-the-MoneyShares Acquired on
    
    
    Value
    
    
    at December 31, 2004
    
    
    Options at December 31, 2004(1)Name
    
    Exercise
    
    
    Realized
    
    
    Exercisable
    
    
    Unexercisable
    
    
    Exercisable
    
    
    UnexercisableMichael K.
Paulk
    
    
    -0-
    
    
    
    -0-
    
    
    
    -0-
    
    
    
    250,000
    
    
    
    -0-
    
    
    -0-Steven P. Ensz
    
    
    -0-
    
    
    
    -0-
    
    
    
    -0-
    
    
    
    250,000
    
    
    
    -0-
    
    

    -0-
   (1)
    
    Based on the difference between the option exercise price and the closing bid
price on December 31, 2004 of $0.12 per share. 49




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##### Table of Contents



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
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 15, 2005 (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 15, 2005, we had 35,603,335 common shares
outstanding. Percentage ofNumber of Shares
    
    
    OutstandingName and Address(1)(2)
    
    Owned
    
    
    Shares(3)Mike K. Paulk
    
    
    1,728,875
    (4)
    
    
    4.9
    %Steven P. Ensz
    
    
    2,308,313
    (5)
    
    
    6.5
    %Brian E. Bayley
    
    
    916,500
    (6)
    
    
    2.6
    %Quest Management Corp.
Suite 300 - 570 Granville Street
Vancouver, BC V6C 3P1John K. Campbell
    
    
    215,528
    (7)
    
    
    0.6
    %750 West Pender Street  Suite 710
Vancouver, BC V6C 2T7Jules Poscente
    
    
    256,250
    (8)
    
    
    0.7
    %440, 333 Fifth Avenue, SW
Calgary, Alberta T2P 3B6Gerry Curtis
    
    
    33,500
    (9)
    
    
    0.1
    %33 Reid St.
Box 2706
 50




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##### Table of Contents



Percentage ofNumber of Shares
    
    
    OutstandingName and Address(1)(2)
    
    Owned
    
    
    Shares(3)Hamilton, Bermuda HMKXTransAtlantic Petroleum Corp(10)
    
    
    7,152,874
    (11)
    
    
    20.1
    %1550, 340 - 12th Avenue, SW
Calgary, Alberta T2R 1L5All Directors
and officers as a group (6 persons)
    
    
    5,458,966
    (12)
    
    
    15.3
    %
   (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 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, 6100 South Yale, Suite 300, Tulsa, Oklahoma 74136.(3)
    
    The percentage of outstanding shares calculation is based upon 35,603,335 shares outstanding
as of March 15, 2005, except as otherwise noted.(4)
    
    Does not include 250,000 shares issuable at an exercise price of $0.45 on exercise of an
option which are subject to stockholder approval of amendments to the 2001 Stock Incentive
Plan.(5)
    
    Does not include 250,000 shares issuable at an exercise price of $0.45 on exercise of an
option which are subject to stockholder approval of amendments to the 2001 Stock Incentive
Plan.(6)
    
    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 1,162,791 shares issuable
on conversion of Debentures held by Quest, as to which shares and Debentures Mr. Bayley
disclaims a beneficial interest.(7)
    
    Includes 65,528 shares held by Mr. Campbell and 150,000 shares issuable on exercise of
options at an exercise price of $0.47 per share.(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)
    
    Does not include 50,000 shares issuable at an exercise price of $0.33 on exercise of an
automatic director grant option which are subject to stockholder approval of amendments to the
2001 Stock Incentive Plan.(10)
    
    TransAtlantic Petroleum Corp. is a corporation whose shares are publicly traded on the
Toronto Stock Exchange under the symbol TNP.U. Its Directors are Michael Winn, 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.(11)
    
    Includes 176,129 shares held by TransAtlantic and 6,976,745 shares issuable on conversion of
$3.0 million principal amount of our Debentures. Mr. Bayley, one of our Directors, is also a
Director of TransAtlantic and also disclaims a beneficial interest in the Debentures and
shares.(12)
    
    Excludes shares held by and issuable on conversion of Debentures held by TransAtlantic. Also
excludes 550,000 shares issuable on exercise of options that are subject to stockholder
approval of amendments to the 2001 Stock Incentive Plan. 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 7 to the Notes to Financial Statements for further information on the
material terms of these plans. The following table provides information as of December 31, 2004 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: 51




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Equity Compensation Plan Information (c)Number of securitiesremaining available(a)

    
    
    
    
    
    
    for future issuanceNumber of securities
    
    

(b)
    

    under equityto be issued upon
    
    
    Weighted-average
    
    
    compensation plansexercise of
    
    
    exercise price of
    
    
    (excluding securitiesoutstanding options,
    
    
    outstanding options,
    
    
    reflected in columnPlan Category
    
    warrants and rights
    
    
    warrants and rights
    
    
    (a))(1)Equity
compensation plans
approved by
security holders
    
    
    700,000
    
    
    $
    0.58
    
    
    
    4,300,000Equity compensation
plans not approved
by security holders
    
    
    -0-
    
    
    
    -0-
    
    
    
    -0-Total
    
    
    700,000
    
    
    $
    0.58
    
    
    
    4,300,000
   (1)
    
    On April 22, 2004, the Board of Directors granted options to purchase
shares of common stock under the Companys 2001 Stock Incentive Plan exercisable at a price of
$0.45 per share and on October 15, 2004 options pursuant to the new director automatic grant
provisions of the Plan exercisable at a price of $0.33, both subject, however, to the adoption
by stockholders of certain amendments to the Plan. Pending stockholder approval, stock options
conditionally granted by the Board of Directors are not considered outstanding. 
 Item 12  Certain Relationships and Related Transactions: 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. 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. 52




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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. The outstanding balance on the production payment was paid in 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, as adjusted, of $0.43 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 granted as partial consideration for the $2.0 million financing entered
into in March 2003 described above. The conversion price of the Debentures was adjusted to $0.43
per share as a result of the Rights Offering completed in the third quarter of 2004. 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. Pursuant to the Debenture Indenture, Mr. Gerry Curtis was
elected to our Board of Directors on October 15, 2004 to replace an earlier elected Director no
longer serving. Under the terms of the Indenture under which the Debentures were issued, if Mr.
Poscente or Mr. Curtis, or any 53




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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:  
    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
    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
    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. 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.
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. 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




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Item 13  Exhibits: Exhibit
    
    Description2.0
    
    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, as amended through September 13, 2004(5)10.1
    
    2001 Stock Incentive Plan(1)10.2
    
    Leasehold Acquisition and Development Agreement with The Wiser Oil Company(1)10.3
    
    Assignment of Oil, Gas and Mineral Lease dated as of February 18, 2002 relating to State
Lease Number 17353.(1)10.4
    
    Purchase and Exploration Agreement dated March 10, 2003 between the Registrant and
TransAtlantic Petroleum (USA) Corp.(4)10.5.1
    
    Form of Subscription Agreement to purchase the Registrants 8% Convertible Secured
Debenture due September 30, 2005.(2)10.5.2
    
    Trust Indenture dated as of October 8, 2003 between the Registrant and Computershare Trust
Company of Canada(2)10.6.1
    
    Development Agreement dated November 22, 2002 between the Registrant and ExxonMobil
Corporation(3)10.6.2
    
    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 as of December 31, 2004:
 55




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##### Table of Contents



Exhibit
    
    DescriptionName
    
    State or Jurisdiction of IncorporationGothic Resources, Inc.
    
    Canada Business Corporations ActCouba Operating Company
    
    Oklahoma31.1
    
    Certification of President and Chief Executive Officer Pursuant to Rule
13a-14(a)(5)31.2
    
    Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)(5)32.1
    
    Certification of President and Chief Executive Officer Pursuant to Section 1350
(furnished, not filed)(5)32.2
    
    Certification of Chief Financial Officer Pursuant to Section 1350 (furnished, not
filed)(5)
   (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 the Registrants Annual Report on Form 10-KSB for the year ended
December 31, 2003.(5)
    
    Filed with this Annual Report on Form 10-KSB for the year ended December 31, 2004. 56




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Item 14. Principal Accountant Fees and Services The following sets forth fees we incurred for services provided by PricewaterhouseCoopers LLP,
for the years ended December 31, 2004 and 2003, our independent public accountant at those year
ends: Audit RelatedAudit Fees
    
    
    Fees
    
    
    Tax Fees
    
    
    All Other Fees2004
    
    $
    275,100
    
    
    
    
    
    
    $
    20,500
    
    
    
    2003
    
    $
    287,700
    
    
    
    
    
    
    
    
    
    
    
    
 Our Board of Directors believes that the provision of the services during the years ended
December 31, 2004 and December 31, 2003 is compatible with maintaining the independence of
PricewaterhouseCoopers LLP. Our Audit Committee approves before the engagement the rendering of
all audit and non-audit services provided to our company by our independent auditor. Engagements
to render services are not entered into pursuant to any pre-approval policies and procedures
adopted by the Audit Committee. The services provided by PricewaterhouseCoopers LLP included under
the caption Audit Feesinclude services rendered for the audit of our annual financial statements,
the review of our quarterly financial reports, the issuance of consents, and assistance with review
of documents filed with the Securities and Exchange Commission. Tax fees include services rendered
related to advice on the proposed liquidation of our subsidiary, Gothic. 57




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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 CorporationBy:
    
    /s/ Michael K. PaulkMichael 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 31, 2005Michael K. Paulk
    
    Executive Officer) and Director/s/ Steven P. Ensz
    
    Director and Principal Financial
    
    March 31, 2005Steven P. Ensz
    
    and Accounting Officer/s/ Brian Bayley
    
    Director
    
    March 31, 2005Brian Bayley/s/ Jules Poscente
    
    Director
    
    March 31, 2005Jules Poscente/s/ Gerry Curtis
    
    Director
    
    March 31, 2005Gerry Curtis
 58




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American Natural Energy Corporation Consolidated Financial StatementsDecember 31, 2004 and 2003 F-1




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##### Table of Contents



Report of Independent Registered Public Accounting Firm 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, 2004 and 2003, 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 statements in accordance with the standards
of the Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about whether the
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 2004 and 2003 and has a working capital
deficiency and an accumulated deficit at December 31, 2004. 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 13 to the consolidated financial statements, effective in the third quarter of
2004, the Company changed its method of capitalizing interest on qualifying expenditures related to
unproved properties. Additionally, 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 31, 2005 F-2




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##### Table of Contents



AMERICAN NATURAL ENERGY CORPORATION
Consolidated Balance Sheets
As of December 31, 2004 and December 31, 2003 December 31, 2004
    
    
    December 31, 2003$
    
    
    $ASSETSCurrent assets:Cash and cash equivalents
    
    
    303,817
    
    
    
    1,650,110Accounts receivable  joint interest billing
    
    
    468,737
    
    
    
    1,308,981Accounts receivable  oil and gas sales
    
    
    910,496
    
    
    
    384,003Accounts receivable  other
    
    
    7,893
    
    
    
    50,194Prepaid expenses
    
    
    95,739
    
    
    
    88,762Oil inventory
    
    
    21,968
    
    
    
    14,947Total current assets
    
    
    1,808,650
    
    
    
    3,496,997Proved oil and natural gas properties using full cost method, net of accumulated
depletion, depreciation, amortization and impairment of
$18,456,138 and $8,356,023
    
    
    1,878,100
    
    
    
    3,702,897Unproved oil and natural gas properties
    
    
    3,445,522
    
    
    
    3,773,136Equipment and other fixed assets, net of accumulated depreciation of $361,954 and $205,237
    
    
    712,395
    
    
    
    757,759Deferred expenses (Note 1)
    
    
    321,454
    
    
    
    589,983Total assets
    
    
    8,166,121
    
    
    
    12,320,772LIABILITIES AND STOCKHOLDERS EQUITY (DEFICIT)Current liabilities:Accounts payable and accrued liabilities
    
    
    4,031,055
    
    
    
    2,587,815Revenues payable
    
    
    4,302,834
    
    
    
    836,679Accrued payroll
    
    
    
    
    
    
    170,000Accrued interest
    
    
    6,000
    
    
    
    4,734Insurance notes payable
    
    
    12,910
    
    
    
    13,367Current portion of convertible secured debentures, net of discount of $3,868,386 (Note 6)
    
    
    7,806,614
    
    
    
    Total current liabilities
    
    
    16,159,413
    
    
    
    3,612,595Convertible secured debentures, net of discount of $6,267,705 (Note 6)
    
    
    
    
    
    
    5,732,295Asset retirement obligation (Note 5)
    
    
    1,603,064
    
    
    
    1,438,773Total liabilities
    
    
    17,762,477
    
    
    
    10,783,663Commitments and contingencies (Notes 8 and 12)Stockholders equity (deficit):Common
stock

Authorized - 100,000,000 shares with par value of $0.01

Issued - 35,138,219 (2003 - 26,154,546) shares
    
    
    351,382
    
    
    
    261,545Additional paid-in capital
    
    
    17,435,536
    
    
    
    14,492,998Accumulated deficit, since January 1, 2002 (in conjunction with the quasi-
reorganization stated capital was reduced by an accumulated deficit of $2,015,495)
    
    
    (29,299,486
    )
    
    
    (14,412,031
    )Accumulated other comprehensive income
    
    
    1,916,212
    
    
    
    1,194,597Total stockholders (deficit) equity
    
    
    (9,596,356
    )
    
    
    1,537,109Total liabilities and stockholders (deficit) equity
    
    
    8,166,121
    
    
    
    12,320,772
 The accompanying notes are an integral part of these consolidated financial statements. F-3




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AMERICAN NATURAL ENERGY CORPORATION
Consolidated Statements of Operations
For the years ended December 31, 2004 and December 31, 2003 December 31, 2004
    
    
    December 31, 2003$
    
    
    $Revenues:Oil and gas sales
    
    
    3,137,202
    
    
    
    1,698,992Operations income
    
    
    116,643
    
    
    
    43,902Interest income and other income
    
    
    1,928
    
    
    
    4,2683,255,773
    
    
    
    1,747,162Expenses:Lease operating expense
    
    
    429,315
    
    
    
    495,409Production taxes
    
    
    232,135
    
    
    
    66,807General and administrative
    
    
    2,078,417
    
    
    
    1,938,243Foreign exchange loss
    
    
    721,889
    
    
    
    1,715,570Interest and bank charges
    
    
    3,630,954
    
    
    
    440,467Loss (Gain) on sale of oil and gas properties
    
    
    44,411
    
    
    
    (43,937
    )Impairment of oil and gas properties
    
    
    7,676,670
    
    
    
    653,886Gain on sale of marketable securities
    
    
    
    
    
    
    (172,788
    )Loss on redemption of debt, net
    
    
    
    
    
    
    221,730Write-down of inventory to market
    
    
    14,258
    
    
    
    5,202Depreciation, depletion, and amortization   oil
and gas properties
    
    
    2,558,719
    
    
    
    919,628Depreciation and amortization  other assets
    
    
    430,079
    
    
    
    182,999Total expenses
    
    
    17,816,847
    
    
    
    6,423,216Loss before cumulative effect of accounting change
    
    
    (14,561,074
    )
    
    
    (4,676,054
    )Cumulative effect of accounting change (Note 13)
    
    
    (326,381
    )
    
    
    (1,005,460
    )Net loss
    
    
    (14,887,455
    )
    
    
    (5,681,514
    )Other comprehensive (loss) income  net of tax:Unrealized gain on marketable securities arising
during the year
    
    
    
    
    
    
    13,870Foreign exchange translation
    
    
    721,615
    
    
    
    1,712,174Reclassification adjustment for gains on
marketable securities included in net income
    
    
    
    
    
    
    (172,788
    )Other comprehensive income
    
    
    721,615
    
    
    
    1,553,256Comprehensive loss
    
    
    (14,165,840
    )
    
    
    (4,128,258
    )Basic and diluted loss per share before
cumulative effect of accounting change
    
    
    (0.48
    )
    
    
    (0.18
    )Cumulative effect of accounting change
    
    
    (0.01
    )
    
    
    (0.04
    )Net loss per share
    
    
    (0.49
    )
    
    
    (0.22
    )Weighted
average number of shares outstanding 
basic and diluted
    
    
    30,330,592
    
    
    
    25,880,043
 The accompanying notes are an integral part of these consolidated financial statements. F-4




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AMERICAN NATURAL ENERGY CORPORATION
Consolidated Statements of Changes in Stockholders Equity (Deficit)
For the years ended December 31, 2004 and December 31, 2003 Accumu-latedOther
    
    
    Totalcompre-
    
    
    stock-Additional
    
    
    Accumu-
    
    
    hensive
    
    
    holdersCommon stock
    
    
    paid-in
    
    
    lated
    
    
    income
    
    
    equityShares
    
    
    Amount
    
    
    capital
    
    
    Deficit
    
    
    (loss)
    
    
    (deficit)$
    
    
    $
    
    
    $
    
    
    $
    
    
    $Balance
 December
31, 2002
    
    
    25,199,846
    
    
    
    251,998
    
    
    
    7,427,503
    
    
    
    (8,730,517
    )
    
    
    (358,659
    )
    
    
    (1,409,675
    )Stock issued as
additional interest
    
    
    854,700
    
    
    
    8,547
    
    
    
    291,453
    
    
    
    
    
    
    
    
    
    
    
    300,000Stock issued in
settlement of
contract
    
    
    100,000
    
    
    
    1,000
    
    
    
    68,000
    
    
    
    
    
    
    
    
    
    
    
    69,000Compensation
expense for stock
options
    
    
    
    
    
    
    
    
    
    
    39,375
    
    
    
    
    
    
    
    
    
    
    
    39,375Beneficial
conversion feature
of debentures
    
    
    
    
    
    
    
    
    
    
    6,666,667
    
    
    
    
    
    
    
    
    
    
    
    6,666,667Decrease in
unrealized gain on
marketable
securities
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    13,870
    
    
    
    13,870Reclassification
adjustment for
gains included in
net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (172,788
    )
    
    
    (172,788
    )Foreign exchange
translation gain
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,712,174
    
    
    
    1,712,174Net 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
 The accompanying notes are an integral part of these consolidated financial statements. F-5




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AMERICAN NATURAL ENERGY CORPORATION
Consolidated Statements of Changes in Stockholders Equity (Deficit) (cont.)
For the years ended December 31, 2004 and December 31, 2003 Accumu-latedOther
    
    
    Totalcompre-
    
    
    stock-Additional
    
    
    Accumu-
    
    
    hensive
    
    
    holdersCommon stock
    
    
    paid-in
    
    
    lated
    
    
    income
    
    
    equityShares
    
    
    Amount
    
    
    capital
    
    
    Deficit
    
    
    (loss)
    
    
    (deficit)$
    
    
    $
    
    
    $
    
    
    $
    
    
    $Balance  December 31,
2003
    
    
    26,154,546
    
    
    
    261,545
    
    
    
    14,492,998
    
    
    
    (14,412,031
    )
    
    
    1,194,597
    
    
    
    1,537,109Stock issued on
conversion of
debentures
    
    
    741,343
    
    
    
    7,414
    
    
    
    317,586
    
    
    
    
    
    
    
    
    
    
    
    325,000Stock issued on
exercise of options
    
    
    1,300,000
    
    
    
    13,000
    
    
    
    403,000
    
    
    
    
    
    
    
    
    
    
    
    416,000Stock issued pursuant
to rights offering
    
    
    6,942,330
    
    
    
    69,423
    
    
    
    1,596,516
    
    
    
    
    
    
    
    
    
    
    
    1,665,939Beneficial conversion
feature of debentures
    
    
    
    
    
    
    
    
    
    
    858,088
    
    
    
    
    
    
    
    
    
    
    
    858,088Costs of rights offering
    
    
    
    
    
    
    
    
    
    
    (232,652
    )
    
    
    
    
    
    
    
    
    
    
    (232,652
    )Foreign exchange
translation gain
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    721,615
    
    
    
    721,615Net loss (total
comprehensive loss of
$14,165,840)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (14,887,455
    )
    
    
    
    
    
    
    (14,887,455
    )Balance  December 31,
2004
    
    
    35,138,219
    
    
    
    351,382
    
    
    
    17,435,536
    
    
    
    (29,299,486
    )
    
    
    1,916,212
    
    
    
    (9,596,356
    )
 The accompanying notes are an integral part of these consolidated financial statements. F-6




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AMERICAN NATURAL ENERGY CORPORATION
Consolidated Statements of Cash Flows
For the years ended December 31, 2004 and December 31, 2003 December 31, 2004
    
    
    December 31, 2003$
    
    
    $Cash flows from operating activities:Net loss for the period
    
    
    (14,887,455
    )
    
    
    (5,681,514
    )Non cash items:Depreciation, depletion and amortization
    
    
    2,988,798
    
    
    
    1,102,627Foreign exchange loss
    
    
    721,889
    
    
    
    1,715,570Amortization of beneficial conversion feature
    
    
    3,257,407
    
    
    
    Non-cash compensation expense
    
    
    
    
    
    
    39,375Gain on sale of marketable securities
    
    
    
    
    
    
    (172,788
    )Cumulative effect of accounting change
    
    
    326,381
    
    
    
    1,005,460Loss (gain) on sale of oil and gas properties
    
    
    44,411
    
    
    
    (43,937
    )Loss on redemption of debt
    
    
    
    
    
    
    221,730Impairment of oil and gas properties
    
    
    7,676,670
    
    
    
    653,886Write-down of inventory to market
    
    
    14,258
    
    
    
    5,202Stock issued in settlement of contract
    
    
    
    
    
    
    69,000Changes in non-cash working capital items:Accounts receivables
    
    
    356,052
    
    
    
    (1,386,051
    )Inventories
    
    
    3,369
    
    
    
    330Prepaid expenses
    
    
    143,933
    
    
    
    99,442Accounts payable, revenue payables and accrued
liabilities
    
    
    3,212,066
    
    
    
    2,010,174Net cash provided by (used in) operating activities
    
    
    3,857,779
    
    
    
    (361,494
    )Cash flows from investing activities:Proceeds from sale of marketable securities
    
    
    
    
    
    
    208,051Proceeds from sale of oil and gas properties
    
    
    
    
    
    
    461,544Purchase and development of oil and gas properties
    
    
    (6,785,531
    )
    
    
    (4,634,539
    )Purchase of fixed assets
    
    
    (111,353
    )
    
    
    (143,620
    )Net cash used in investing activities
    
    
    (6,896,884
    )
    
    
    (4,108,564
    )Cash flows from financing activities:Issuance of notes payable
    
    
    
    
    
    
    2,500,000Issuance of convertible debentures (net of costs of
$643,617)
    
    
    
    
    
    
    11,356,383Issuance of capital stock (net of costs of $232,652)
    
    
    1,433,287
    
    
    
    Exercise of stock options
    
    
    416,000
    
    
    
    Production payment loan
    
    
    
    
    
    
    1,538,456Repayment of production payment loan
    
    
    
    
    
    
    (2,000,000
    )Payments of notes payable
    
    
    (156,201
    )
    
    
    (7,356,336
    )Cash provided by financing activities
    
    
    1,693,086
    
    
    
    6,038,503Effect of exchange rate changes on cash
    
    
    (274
    )
    
    
    (4,630
    )(Decrease) increase in cash and cash equivalents
    
    
    (1,346,293
    )
    
    
    1,563,815Cash beginning of period
    
    
    1,650,110
    
    
    
    86,295Cash end of period
    
    
    303,817
    
    
    
    1,650,110
 The accompanying notes are an integral part of these consolidated financial statements. F-7




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AMERICAN NATURAL ENERGY CORPORATION
Consolidated Statements of Cash Flows (continued)
For the years ended December 31, 2004 and December 31, 2003 December 31, 2004
    
    
    December 31, 2003$
    
    
    $Supplemental disclosures:Interest paid (net of amount capitalized)
    
    
    362,492
    
    
    
    403,301Non cash financing and investing activities:Interest expense capitalized to oil and gas properties
    
    
    
    
    
    
    643,559Principal amount of 8% debentures converted to common stock
    
    
    325,000
    
    
    
    Common shares issued in conjunction with issuance of notes
payable
    
    
    
    
    
    
    300,000Accounts payable refinanced as notes payable
    
    
    
    
    
    
    243,823Prepaid expenses financed
    
    
    155,744
    
    
    
    160,746Accrued interest refinanced upon modification of debt
    
    
    
    
    
    
    331,728
 The accompanying notes are an integral part of these consolidated financial statements. F-8




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003   1
    Basis of presentation and summary of significant accounting policiesDescription of companyAmerican 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 Actwith 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.ConsolidationThe 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 equivalentsCash 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, 2004.Marketable securitiesInvestments 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 F-9




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003   securities not included in trading or held-to-maturity are classified as available-for-sale.
The Company had no marketable securities at December 31, 2004 and 2003.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.The Company sold 137,000 shares of First Calgary Petroleum Ltd. in 2003, realizing a gain of
$172,788.InventoryOil in storage barges attributable to our interest amounted to 519 and 468 barrels at December
31, 2004 and 2003, 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, 2004 and 2003 was valued at the lower of cost or market at $21,968
and $14,947, respectively.Oil and natural gas propertiesThe 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 $29.48 and $14.94 per equivalent bbl in 2004 and 2003,
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, $7,676,670 and
$653,886 were written off as impairment of oil and gas properties in 2004 and 2003,
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
from this transaction in the amount of $726,348 in 2002 and a gain resulting from interim
post-closing adjustments in 2003 of $43,937. An additional loss of $44,411 due to final
post-closing adjustments was recorded in 2004. F-10




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003   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 assetsEquipment 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 yearsOffice furniture and equipment
    
    5-7 yearsLeasehold improvements
    
    3 yearsBarges and field equipment
    
    5-10 yearsGas 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 expensesDeferred expenses, representing debenture issuance costs, are stated at cost less accumulated
amortization. Amortization expense is determined using the effective interest rate method over
the remaining life of the outstanding debentures (due date September 30, 2005).Foreign exchange and currency translationThe 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.Revenue recognition F-11




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003   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. (Teppco) of $2,476,267 and $1,666,865 in 2004 and 2003,
respectively, accounted for 79% and 98% of total oil and gas sales. The Companys gas sales to
Transcontinental Gas Pipe Line Corporation of $660,935 and $32,127 in 2004 and 2003 accounted
for 21% and 2% 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, 2004 and
2003, $217,738 and $954,266 was due from ExxonMobil, $110,517 and $163,343 from TransAtlantic,
$636,036 and $269,781 from Teppco, and $274,460 and $114,221 from Fairway Gas (the Companys
marketing agent with Transcontinental Gas Pipe Line Corporation), respectively.The Company has 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 obligationsEffective 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.Convertible debentures F-12




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003   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. During 2004, $325,000 of debentures converted to common stock with
$11,675,000 outstanding at December 31, 2004.Income taxesThe 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 financial statements or income tax returns.Use of estimatesThe 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 shareBasic 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, 2004 and 2003, there
were 700,000 and 2,000,000 shares available for issuance pursuant to the exercise of previously
granted stock options, respectively. As of December 31, 2004 and 2003, there were 27,151,163
and 26,666,667 shares available for issuance upon the conversion of the Debentures,
respectively.
Due to losses in 2004 and 2003, the options and shares issuable upon conversion of the
Debentures were excluded from the calculation of diluted earnings per share as they were
anti-dilutive. F-13




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003   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 of $721,615 and $1,553,256 for the years ended December 31, 2004 and 2003,
respectively, as a result of foreign exchange translation gains of $721,615 and $1,712,174.
The Company additionally incurred $13,870 of unrealized gains on marketable securities and had
a $172,788 reclassification adjustment for gains on marketable securities included in net
income for the year ended December 31, 2003. There were no reclassification adjustments for
the year ended December 31, 2004.As of December 31, 2004 and 2003, accumulated other comprehensive income (loss) was comprised
solely of foreign currency translation gains.Stock-based compensationAt December 31, 2004, 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-14




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003 
 For years ended December 31,2004
    
    
    2003$
    
    
    $Net loss, as reported
    
    
    (14,887,455
    )
    
    
    (5,681,514
    )Less: Total stock-based
employee compensation
expense determined under
fair value based method for
all awards, net of related
tax effects
    
    
    (215,344
    )
    
    
    (42,441
    )Pro forma net loss
    
    
    (15,102,799
    )
    
    
    (5,723,955
    )Loss per shareBasic and diluted-as reported
    
    
    (0.49
    )
    
    
    (0.22
    )Basic and diluted-pro forma
    
    
    (0.50
    )
    
    
    (0.22
    )
  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: 2003Weighted average life, in years
    
    5.00Risk-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. On April 22, 2004, the Board of
Directors granted to employees and employee Directors of the Company options to purchase an
aggregate of 1.0 million shares of common stock under the Companys 2001 Stock Incentive Plan
exercisable at a price of $0.45 per share and on October 15, 2004 50,000 options pursuant to
the new director automatic grant provisions of the Plan exercisable at a price of $0.33, both
subject, however, to the adoption by shareholders of certain amendments to the Plan. Pending
shareholder approval, stock options provisionally granted by the Board of Directors are not
considered outstanding. Therefore, pro-forma amounts of compensation expense presented above
for 2004 exclude the effect of this grant.  New pronouncements  Statement of Financial Accounting Standards No. 141, Business Combinationsand Statement of
Financial Accounting Standards No. 142, Goodwill and Intangible Assetswere issued by the F-15




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003 
    Financial Accounting Standards Board in June 2001 and became effective for the Company 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 sets forth 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. Consistent with oil and gas accounting and industry practice,
the Company classifies the cost of oil and gas mineral rights as property and equipment and not
as intangible assets.In September 2004, the FASB issued FASB Staff Position, FSP SFAS 142-2, Application of FASB
Statement No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Producing Entities. The
FSP clarifies that an exception in SFAS 142 includes the balance sheet classification and
disclosures for drilling and mineral rights of oil and gas producing entities. The FASB staff
acknowledges that the existing accounting framework for oil and gas producers is based on the
level of established reserves, not whether an asset is tangible or intangible. The FSP confirms
the Companys historical treatment of these costs.In September 2004, the SEC issued Staff Accounting Bulletin No. 106 providing guidance
regarding the interaction of SFAS No. 143, Accounting for Asset Retirement Obligations,with
the full cost accounting rules in Article 4-10 of Regulation S-X. The Bulletin provides
guidance for calculation for the full cost ceiling calculation and for the calculation of
depreciation, depletion and amortization. The Bulletin is effective for the Companys
reporting quarter commencing October 1, 2004. Implementation of these guidelines has not had
any significant effects on financial position, results of operations or changes in cash flow of
the Company.In September 2004, the Emerging Issues Task Force issued EITF No. 04-8, The Effect of
Contingently Convertible Instruments on Diluted Earnings per Share.EITF No. 04-8 provides new
guidance on when the dilutive effect of contingently convertible securities with a market price
trigger should be included in diluted EPS. The new guidance states that these securities should
be included in the diluted EPS computation regardless of whether the market price trigger has
been met. The guidance in EITF 04-8 is effective for all periods ending after December 15, 2004
and would be applied by retrospectively restating previously reported EPS. This pronouncement
has no impact on the Company.In December 2004, the FASB issued Statement on Financial Accounting Standards No. 123 (Revised
2004), Share-Based Payment, revising FASB Statement No. 123, Accounting for Stock-Based
Compensation and superseding APB Opinion No. 25, Accounting for Stock Issued to Employees.
This statement requires a public entity to measure the cost of services provided by employees
and directors received in exchange for an award of equity instruments, including stock options,
at a grant-date fair value. The fair value cost is then recognized over the period that
services are provided. FAS 123 (Revised 2004) is effective for interim and annual periods that
begin after June 15, 2005 and will be adopted by the Company in third quarter of 2005. See
Note 1 of these financial statements for a disclosure of the effect on net income and earnings
per share for the years 2003 and 2004 if the Company had applied the fair value recognition
provision of FAS 123 to stock-based employee compensation. F-16




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003 
  2
    Liquidity and Capital ResourcesThe Company has no current borrowing capacity with any lender. The Company has sustained
substantial losses in 2004 and 2003, totaling approximately $14.9 and $5.7 million, and has a
working capital deficiency and an accumulated deficit at December 31, 2004, 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 pay its current
liabilities and 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 the private offering of its securities. Cash flow from operations is
sensitive to 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 and its
underlying oil and gas properties, 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 drilling
participations, joint ventures, 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 AgreementOn 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 F-17




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003 
  the agreement (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 2007.4
    Property, plant and equipmentThe carrying value of equipment and other fixed assets as of December 31, 2004 and 2003
included the following components: 2004
    
    
    2003$
    
    
    $Computer and office furniture and equipment
    
    
    150,783
    
    
    
    102,792Leasehold improvements
    
    
    5,520
    
    
    
    5,520Barges and field equipment
    
    
    734,361
    
    
    
    747,281Gas gathering and production facility expansion
    
    
    183,685
    
    
    
    107,4031,074,349
    
    
    
    962,996Less: Accumulated depreciation
    
    
    (361,954
    )
    
    
    (205,237
    )712,395
    
    
    
    757,759
  5
    Asset retirement obligationsEffective 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.The Company identified and estimated all of its 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, the Company included
an estimate of its asset retirement obligations related to its oil and gas properties in its
calculation of oil and gas depreciation, depletion and amortization expense. Upon adoption of
SFAS 143, the Company recorded the discounted fair value of its 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. The
effect of SFAS 143 for the years ended December 31, 2004 and 2003 was an increase in the net
loss before cumulative effect of accounting change of approximately $160,000 and $145,000,
respectively. F-18




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003 
  The components of the change in the Companys asset retirement obligations for the years ended
December 31, 2004 and 2003 are shown below. For the years ended December 31,2004
    
    
    2003$
    
    
    $Asset retirement obligations,
January 1
    
    
    1,438,774
    
    
    
    1,435,460Additions and revisions
    
    
    4,368
    
    
    
    18,609Settlements and disposals
    
    
    
    
    
    
    (160,714
    )Accretion expense
    
    
    159,922
    
    
    
    145,419Asset retirement obligations,
December 31
    
    
    1,603,064
    
    
    
    1,438,774
  6
    Notes payable and long-term debtNotes payable and long-term debt as of December 31, 2004 and 2003 consisted of the
following: 2004
    
    
    2003$
    
    
    $8% Convertible secured debentures
    
    
    11,675,000
    
    
    
    12,000,000Discount for beneficial conversion
feature, net of amortization of
$3,656,369 and $398,962
    
    
    (3,868,386
    )
    
    
    (6,267,705
    )Total notes payable and long-term
debt
    
    
    7,806,614
    
    
    
    5,732,295Less: Current portion
    
    
    (7,806,614
    )
    
    
    Total notes payable and long-term
debt, net of current portion
    
    
    
    
    
    
    5,732,295
  8% Convertible secured debenturesOn 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. At the dates of issuance, the
outstanding principal of the Debentures was 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 F-19




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003 
  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. The
Company used 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.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.During the third quarter of 2004, the Company completed a Rights Offering. Due to the
antidilution adjustment provisions contained in the Debenture Agreement, such transaction
changed the conversion price of the debentures from $0.45 to $0.43 per share and as a result
changed the related Beneficial Conversion Feature by $858,000. The change in the Beneficial
Conversion Feature caused the effective rate of the debentures to increase from 55% to 62%.
During 2004 $325,000 of the Debentures converted to common stock. At December 31, 2004,
Debentures totaling $11,675,000 are outstanding. Amortization of the discount amounted to
approximately $3,257,000 and $399,000 for 2004 and 2003, respectively.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 stockOptionsThe 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 adopted
by Gothic prior to the reorganization (see Note 11), the board
had the right from time to time to 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 should 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 F-20




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003 
  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, 2004 and 2003 is as follows: WeightedNumber of
    
    
    AverageOptions
    
    
    Exercise price$Outstanding
-  December 31, 2002
    
    
    1,950,000
    
    
    
    0.33Granted
    
    
    450,000
    
    
    
    0.68Expired
    
    
    (400,000
    )
    
    
    0.32Outstanding  December 31, 2003
    
    
    2,000,000
    
    
    
    0.41Exercised
    
    
    (1,300,000
    )
    
    
    0.32Outstanding  December 31, 2004
    
    
    700,000
    
    
    
    0.58
  Exercise prices of options outstanding at December 31, 2004 ranged from $0.32 to $0.68. At
December 31, 2004, 575,000 (2003  1,550,000) options have vested and are exercisable at a
weighted average price of $0.56. The weighted average remaining contractual life of options
granted at December 31, 2004 is 34 months (2003  40 months). On April 22, 2004, the Board of
Directors granted to employees and employee Directors of the Company options to purchase an
aggregate of 1.0 million shares of common stock under the Companys 2001 Stock Incentive Plan
exercisable at a price of $0.45 per share and on October 15, 2004 50,000 options pursuant to
the new director automatic grant provisions of the Plan exercisable at a price of $0.33, both,
subject, however, to the adoption by shareholders of certain amendments to the Plan. Pending
shareholder approval, stock options provisionally granted by the Board of Directors are not
considered outstanding.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. F-21




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003 
  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, 2004 and 2003, there were options to
purchase 600,000 and 1,900,000 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, 2004 and 2003, 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,
2004 and 2003, 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, 2004 and 2003 there were 100,000
options outstanding under the Automatic Option Grant Program.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, 2004 and 2003, there were no options outstanding under the
Director Fee Option Grant Program. F-22




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003 
  8
    Commitments and contingenciesThe Company rents office space and equipment under long-term operating leases that expire
through 2009. The future minimum lease payments required under the operating leases that have
initial non-cancelable lease terms in excess of one year amounted to $399,000 of which $90,000
is to be paid in 2005, $87,000 is to be paid in 2006, $60,000 is to be paid in 2007 and 2008,
and $50,000 is to be paid in 2009.Rent expense on all operating leases amounted to approximately $74,300 and $85,300 in 2004 and
2003, respectively.Bank of Oklahoma, N.A. has issued an irrevocable standby letter of credit, dated December 24,
2004 and expiring December 24, 2005, 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.The Company 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.The Company agreed that, after repayment to it 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 it directly from Couba Operating Company at the time of
confirmation and as a result of the plan of reorganization of Couba Operating Company.The Company is a defendant in a number of legal proceedings which management considers to be
routine litigation that is incidental to its business. Management does not expect to incur any
material liability as a consequence of such litigation.9
    Related party transactionsThe Company reimbursed $3,980 of office administration expense to a company with a common
director of the Company during 2004. No such expenses were incurred in 2003.In 2003, the Company entered into financing transactions with Quest Investment, Inc. and
TransAtlantic Petroleum (USA) Corp. A director of the Company was also a director of both
entities. F-23




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003   Additionally in 2003, Quest Investment, Inc. and TransAtlantic Petroleum (USA) Corp.
purchased $500,000 and $3,000,000, respectively, of the Debentures issued in October 2003. A
director of the Company was also a director of both entities.10
    Income taxesThe provision for income taxes for the year ended December 31, 2004 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,
2004 and 2003 are presented below: 2004
    
    
    2003$
    
    
    $Deferred tax assetsAsset retirement costs
    
    
    608,499
    
    
    
    546,158Foreign exchange loss
    
    
    268,862
    
    
    
    651,230Acquisition, exploration and development
costs and related depreciation, depletion
and amortization
    
    
    6,834,694
    
    
    
    1,699,127Contribution carryovers
    
    
    1,871
    
    
    
    1,967Change in accounting principle
    
    
    123,894
    
    
    
    Net operating loss carryforwards
    
    
    3,562,386
    
    
    
    2,677,805Deferred tax asset
    
    
    11,400,206
    
    
    
    5,576,287Less: Valuation allowance
    
    
    (11,400,206
    )
    
    
    (5,576,287
    )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, 2004 and
2003 are summarized as follows: 2004
    
    
    2003$
    
    
    $Federal tax benefit at statutory rate
    
    
    5,061,735
    
    
    
    1,978,730State taxes, net of federal taxes
    
    
    637,927
    
    
    
    167,623Other
    
    
    458,026
    
    
    
    (20,335
    )Less: valuation allowance
    
    
    (6,157,688
    )
    
    
    (2,126,018
    )Total provision for income taxes
    
    
    
    
    
    
    
 F-24




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##### Table of Contents



American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003   As of December 31, 2004, the Company has a net operating loss carry-forward of
approximately $9,361,600 which is available to reduce future taxable income, if any, through
2025. 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
    ReorganizationOn 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.12
    Subsequent EventsIn February 2002, the Company leased 1,729 acres from the State of Louisiana which was
subject to annual lease renewals in the absence of oil and gas development. This lease was
renewed annually in 2003 and 2004 and has expired in February 2005. The Company had a total of
$1,117,020 invested in the lease and renewals including capitalized interest. Because these
undeveloped properties are deemed to be impaired at December 31, 2004, these costs have been
included in proved oil and gas properties and thus are subject to depletion, depreciation, and
amortization and the annual ceiling test limitation. F-25




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##### Table of Contents



American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003   In February 2005, inter-company accounts of the Company and Gothic were cancelled and an
application to liquidate the Gothic subsidiary was made. Therefore, upon liquidation in 2005,
amounts reflected in accumulated other comprehensive income will be reclassified to earnings.13
    Changes in accounting principleIn the third quarter of 2004, the Company changed its method of capitalizing interest on
qualifying expenditures related to unproved properties. The Company changed from using a
capitalization rate which includes deemed interest from amortization of a beneficial conversion
feature associated with the Companys convertible secured debentures to a rate which excludes
the impact of the beneficial conversion feature. The Company believes that the revised method
of determining the interest rate subject to capitalization is preferable because it results in
improved financial reporting as the recognition of this non cash deemed interest element is not
deferred over the evaluation period of the unproved properties and the life of the Companys
proved reserves.The Company began capitalizing the non cash deemed interest during the quarter ended December
31, 2003, consistent with the issuance dates of the convertible secured debentures. As a
result of applying the new method, the cumulative effect of the change on the prior year of
$326,381 is included in the loss for the year ended December 31, 2004. The new method decreased
depletion, depreciation, and amortization, increased interest expense, and decreased the
Companys impairment charge recorded for the year ended December 31, 2004. The net effect of
the change on the year ended December 31, 2004 was to increase the loss before the cumulative
effect of a change in accounting principle by $1,123,049 ($0.04 per share). The pro forma
effect of the change on net loss for the year ended December 31, 2003 was to increase the loss
by $326,381 ($0.01 per share).In accordance with the provisions of Statement of Financial Accounting Standard No. 143,
Accounting for Asset Retirement Obligations, effective January 1, 2003, the Company incurred a
cumulative effect of a change in accounting principle of $1.0 million.14
    Disclosures About Oil and Gas Producing ActivitiesNet Capitalized CostsThe following summarizes net capitalized costs as of December 31, 2004 and 2003. 2004
    
    
    2003$
    
    
    $Oil and gas propertiesProved
    
    
    20,334,238
    
    
    
    12,058,920Unproved
    
    
    3,445,522
    
    
    
    3,773,136Total
    
    
    23,779,760
    
    
    
    15,832,056Less accumulated depreciation, depletion and
amortization and impairment
    
    
    (18,456,138
    )
    
    
    (8,356,023
    )Net capitalized costs
    
    
    5,323,622
    
    
    
    7,476,033
 F-26




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003  Unproved Property Costs The following summarizes the capitalized unproved property costs excluded from amortization as
of December 31, 2004. All costs represent investment in unproved property in Louisiana and
will be evaluated over several years as the properties are explored. 2004
    
    
    2003
    
    
    Prior Years
    
    
    Total$
    
    
    $
    
    
    $
    
    
    $Property acquisition costs
    
    
    447,606
    
    
    
    
    
    
    
    1,986,640
    
    
    
    2,434,246Capitalized interest
    
    
    384,277
    
    
    
    351,142
    
    
    
    275,857
    
    
    
    1,011,276831,883
    
    
    
    351,142
    
    
    
    2,262,497
    
    
    
    3,445,522
 Costs Incurred in Oil and Gas Acquisition, Exploration and Development 2004
    
    
    2003$
    
    
    $Development costs
    
    
    2,385,689
    
    
    
    2,953,794Exploration costs
    
    
    5,259,630
    
    
    
    1,331,286Acquisition costs(1)Proved
    
    
    
    
    
    
    Unproved
    
    
    668,808
    
    
    
    974,959Sales of properties
    
    
    
    
    
    
    (618,855
    )8,314,127
    
    
    
    4,641,184
   (1)
    
    Acquisition costs for 2003 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 2004 and 2003. 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. F-27




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003  2004
    
    
    2003$
    
    
    $Oil and gas sales
    
    
    3,137,202
    
    
    
    1,698,992Operations income
    
    
    116,643
    
    
    
    43,902Lease operating expenses
    
    
    (429,315
    )
    
    
    (495,409
    )Production taxes
    
    
    (232,135
    )
    
    
    (66,807
    )Net gain (loss) from sale of oil and gas properties
    
    
    (44,411
    )
    
    
    43,937Impairment of oil and gas properties
    
    
    (7,676,670
    )
    
    
    (653,886
    )Depreciation, depletion and amortization
    
    
    (2,558,719
    )
    
    
    (1,024,676
    )Results of operations from oil and gas activities
    
    
    (7,687,405
    )
    
    
    (453,947
    )
 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. 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, 2004 Oil
    
    
    Gas
    
    
    Total(mbbl)
    
    
    (mmcf)
    
    

(mbble)Proved reserves, beginning of period
    
    
    179.55
    
    
    
    272.47
    
    
    
    224.96Extensions, discoveries and other additions
    
    
    20.83
    
    
    
    12.78
    
    
    
    22.96Revisions of previous estimates
    
    
    (50.08
    )
    
    
    (100.36
    )
    
    
    (66.81
    )Production
    
    
    (59.79
    )
    
    
    (134.57
    )
    
    
    (82.21
    )Sale of reserves in place
    
    
    
    
    
    
    
    
    
    
    Purchase of reserves in place
    
    
    
    
    
    
    
    
    
    
    Proved reserves, end of period
    
    
    90.51
    
    
    
    50.32
    
    
    
    98.90Proved developed reserves:Beginning of period
    
    
    110.93
    
    
    
    212.43
    
    
    
    146.34End of period
    
    
    90.51
    
    
    
    50.32
    
    
    
    98.90
 December 31, 2003 F-28




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003  Oil
    
    
    Gas
    
    
    Total(mbbl)
    
    
    (mmcf)
    
    

(mbble)Proved reserves, beginning of period
    
    
    114.53
    
    
    
    40.01
    
    
    
    121.20Extensions, discoveries and other additions
    
    
    77.09
    
    
    
    203.71
    
    
    
    111.04Revisions of previous estimates
    
    
    71.09
    
    
    
    56.70
    
    
    
    80.54Production
    
    
    (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
    
    
    
    224.96Proved developed reserves:Beginning of period
    
    
    18.02
    
    
    
    
    
    
    
    18.02End of period
    
    
    110.93
    
    
    
    212.43
    
    
    
    146.34
 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, 2004 and December 31, 2003 were $40.25 and $29.25 per barrel for
oil and $6.18 and $5.97 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: F-29




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American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2004 and 2003  December 31,2004
    
    
    2003$
    
    
    $Future cash inflows
    
    
    3,925,700
    
    
    
    7,464,800Future production taxes
    
    
    (338,000
    )
    
    
    (574,200
    )Future development costs
    
    
    (213,000
    )
    
    
    (1,178,400
    )Future production costs
    
    
    (1,276,100
    )
    
    
    (1,323,600
    )Estimated future Net Profits payments
    
    
    
    
    
    
    (22,800
    )Future income tax provision
    
    
    
    
    
    
    Net future cash flows
    
    
    2,098,600
    
    
    
    4,365,800Less effect of a 10% discount factor
    
    
    (220,500
    )
    
    
    (676,100
    )Standardized measure of discounted future net cash flows
    
    
    1,878,100
    
    
    
    3,689,700Discounted (at 10%) future net cash flows before income taxes
    
    
    1,878,100
    
    
    
    3,689,700
 The principal sources of change in the standardized measure of discounted future net cash flows
are as follows: December 31,2004
    
    
    2003$
    
    
    $Standardized measure, beginning of period
    
    
    3,689,700
    
    
    
    1,089,200Sales of oil and gas produced, net of production costs
    
    
    (1,719,178
    )
    
    
    (464,630
    )Changes in future development costs
    
    
    814,622
    
    
    
    (296,518
    )Extensions and discoveries and revisions, net of
future production and development costs
    
    
    (1,116,063
    )
    
    
    4,014,319Net change in price and production costs
    
    
    52,147
    
    
    
    (319,971
    )Change in estimated net profits payments
    
    
    22,800
    
    
    
    343,400Accretion of discount
    
    
    134,072
    
    
    
    (676,100
    )Standardized measure, end of period
    
    
    1,878,100
    
    
    
    3,689,700
 F-30