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, 2007; or

o Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from ___ to ___.

Commission File No. 0-18956

American Natural Energy Corporation

(Name of Small Business Issuer in its Charter)

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

6100 South Yale, Suite 300, Tulsa, Oklahoma	74136
(Address of Principal Executive Offices)	(Zip Code)

918-481-1440

(Issuer’s Telephone Number, Including Area Code)

Securities registered under Section 12(b) of the Exchange Act:

Title of Each Class	Name of Each Exchange on Which Registered
	None

Securities Registered Pursuant to Section 12(g) of the Exchange Act:

Common Stock, par value $.001 per share
(Title of Each Class)

     Check whether the issuer is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. o

     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

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

     State Issuer’s revenues for its most recent fiscal year: $1,352,889.

     State 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 July 25, 2007, was $1,854,919. (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 May 20, 2008, was 52,997,673 shares of Common Stock.

DOCUMENTS INCORPORATED BY REFERENCE
None

Table of Contents

	Page
Part I
Item 1. Description of Business	3
Item 2. Description of Property	18
Item 3. Legal Proceedings	18
Item 4. Submission of Matters to a Vote of Security Holders	18
Part II
Item 5. Market for Common Equity, Related Stockholder Matters and Small Business Issuer Purchases of Equity Securities	19
Item 6. Management’s Discussion and Analysis or Plan of Operation	21
Item 7. Financial Statements	43
Item 8. Changes In and Disagreements With Accountants On Accounting and Financial Disclosure	43
Item 8A Controls and Procedures	43
Item 8B Other Information	45
Part III
Item 9. Directors, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of the Exchange Act.	46
Item 10. Executive Compensation	49
Item 11. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	51
Item 12. Certain Relationships and Related Transactions	54
Item 13. Exhibits	54
Item 14. Principal Accountant Fees and Services	56
CHIEF EXECUTIVE OFFICER CERTIFICATION RULE 13A-14(A)
CHIEF FINANCIAL OFFICER CERTIFICATION RULE 13A-14(A)
PRINCIPAL EXECUTIVE OFFICER CERTIFICATION SECTION 1350
PRINCIPAL EXECUTIVE OFFICER CERTIFICATION SECTION 1350

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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.

Our Oil and Natural Gas Interests

     Both through our ownership and as a party to joint development agreements, we hold interests in approximately 7,287 acres of land in St. Charles Parish, Louisiana. This acreage includes approximately 1,319 acres in which we hold a 72% working interest resulting from our acquisition on December 31, 2001, of the assets and outstanding stock of Couba Operating Company (“Couba”) and 167 acres of leases situated between the 1,319 lease tract and lake Salvador, in which we hold a 100% working interest. It also currently includes a total of approximately 5,800 acres owned by ExxonMobil Corp. (“ExxonMobil”), including 2,560 acres to a depth of 14,000 feet, which are the subject of a Joint Development Agreement we entered into with ExxonMobil which, as extended, currently expires on November 22, 2009. Our agreement with ExxonMobil also creates an area of mutual interest in a total of approximately 11,486 acres. Since our acquisition of the Couba properties, we have entered into several participation interests with others in order to finance our drilling and exploration activities. These participation agreements are described below. We continue to need and seek material amounts of additional capital to further our oil and natural gas development and exploitation activities.

     Since 2002 through December 31, 2007, we returned to production 9 (7.31 net) well bores drilled by the prior owners on the Couba properties we acquired. Our drilling activities commenced in February 2003 and as of December 31, 2007, we had drilled and completed 12 (3.29 net) wells. By December 31, 2007, our combined production from all our producing wells (21 gross, 10.60 net) was approximately 166 (42 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.

     Our Couba Properties. 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 had never been produced in commercial quantities, and all gas production wells from the original development of the property were plugged.

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     The principal asset of Couba that we acquired was the Bayou Couba Lease. The lessor is Exxon-Mobil and the lease is held by production of oil and gas on the property. The additional 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 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.

     Our ExxonMobil Joint Development Agreement. In November 2002, we entered into a four-year joint development agreement with ExxonMobil relating to both our Couba properties and additional properties owned by ExxonMobil. In December 2003, we entered into an amendment to that agreement (the “Expansion Amendment”). The agreement, as amended, creates an area of mutual interest (“AMI”) covering approximately 11,000 acres, all within the 23.5 square mile area that is the subject of the seismic information acquired from Couba, and calls for both parties to make available for development, leases and/or mineral interests each owns within the AMI. The Expansion Amendment 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, both of which were drilled to depth. The first well was plugged and the second well was abandoned but is the subject of further evaluation.

     In exchange for entering into the Expansion Amendment, ExxonMobil 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 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 joint development 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 ExxonMobil. As is further described below, Dune Energy, Inc. (“Dune Energy”) is the operator of the wells within the AMI.

     Our Dune Energy Agreements. In September 2005, we entered into a participation agreement with Dune Energy, Inc. (“Dune Energy”). Pursuant to the agreement, Dune Energy

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acquired certain exploration and development rights in our ExxonMobil Corp. joint development agreement. The agreement also creates an area of mutual interest in a total of 31,367 acres including the ExxonMobil lands as well as certain additional lands including our Bayou Couba Lease lands. Dune Energy paid a prospect fee of $1.0 million upon execution of the agreement. An additional fee of $500,000 was waived by us in consideration of Dune paying 100% of the costs of a new seismic survey in 2006. The agreement provides Dune Energy with the right to participate in 50% of our development rights in the Bayou Couba lease as well as our exploration rights in the ExxonMobil Corp. acreage. On June 26, 2007, in consideration of the payment of $3,000,000 Dune Energy increased its participation to 75% of our interest under these agreements, excluding the area under the Bayou Couba lease where it retained a participation of 50% of our interest. On September 1, 2007 Dune Energy was elected successor operator under the ExxonMobil joint development agreement and in consideration Dune Energy paid us an additional $500,000. Each party will pay their respective share of drilling, completion and operations costs.

     The area of mutual interest created by our agreement with Dune Energy, in which we have agreed to share all rights, title and interest owned or acquired on an equal basis, includes our Bayou Cuba lease acreage of approximately 1,319 acres, the acreage covered by our joint development agreement with ExxonMobil of approximately 11,486 acres which are included in the 31,367 acre area, as well as any additional acreage offered to us or Dune Energy by ExxonMobil as the result of the acquisition of additional 3-D seismic data by the parties under the terms of the Agreement. If either party acquires any interests in lands included in the area of mutual interest created by the Agreement, the acquiring party is required to notify the non-acquiring party which will have the opportunity to participate in the acquisition by paying its proportionate share of the price for such properties.

     Under the terms of the Dune Energy agreement, we agreed to share with Dune Energy our 3-D seismic data covering an area of approximately 23.138 square miles within the area of mutual interest. The Agreement provides that either party can propose drilling prospects with the non-proposing party given the right to participate in the drilling prospect and pay its proportionate share of all drilling and completion costs. The Agreement will remain in effect so long as our development agreement with ExxonMobil remains in effect. The Agreement excludes certain specified existing wells which we own, certain of our litigation rights, and our production facility and equipment and personal property. Our interest in the area of mutual interest created by the Agreement is subject to the terms of other agreements to which we are a party.

     Our TransAtlantic Agreements. In March 2003, we assigned a 10% participation interest in the Bayou Couba Lease, a lease we had entered into with the State of Louisiana which has since expired, and the ExxonMobil Corp. AMI to TransAtlantic Petroleum Corp. (“TransAtlantic”) in partial consideration for a $2.0 million financing. This agreement, which has a term of four years or the expiration of our agreement with ExxonMobil Corp., whichever is longer, granted to TransAtlantic the right to acquire a 10% interest in any property we acquire in

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the 23.5 square mile seismic survey area, including any property interests acquired through our agreement with ExxonMobil Corp.

     Effective December 22, 2006, TransAtlantic sold its 10% participation interest in the AMI to Dune Energy. Dune Energy also acquired $3.0 million principal amount of our 8% Convertible Subordinated Debentures formerly held by TransAtlantic. In addition, subsequent to December 31, 2006, Dune Energy acquired from the holders an additional $4,895,000 principal amount of Debentures, bringing Dune Energy’s total holdings of our Debentures outstanding to $7,895,000 principal amount as of December 31, 2007. The principal of the Debentures was due and payable on September 30, 2006 and is currently in default.

     Seismic Survey Participation Agreement. On March 8, 2006, we agreed to participate in a 3D seismic survey covering the 23.5 square mile area over which we and Dune Energy presently have 3D seismic coverage as well as approximately 36.5 additional square miles.  The one year exclusive license to the survey results over the 60 square miles acquired by us is part of a larger regional survey being conducted by Seismic Exchange, Inc. (“SEI”) which includes all of our Bayou Couba project area subject to our ExxonMobil Corp. joint development agreement. The new survey images more effectively formations deeper than are currently imaged by our 1997 3D seismic survey.  As a result of Dune paying 100% of the seismic costs, the terms of the Exploration and Development Agreement between us and Dune Energy were amended to waive any additional prospect fees that may be due from Dune. Upon the completion of the survey and seismic interpretation, we and ExxonMobil Corp. agreed to extend our Joint Development Agreement by two years to November 2009.

     Our State of Louisiana Lease. From February 2002 to February 2005, we leased 1,729 acres from the State of Louisiana, all within the boundaries of the proprietary 1997 3-D seismic data we acquired from Couba. In January 2007, Dune Energy re-leased the acreage plus an additional 769 acres for a total of 2,498 acres that became subject to the terms of the ExxonMobil AMI, and is intended to be explored and developed pursuant to the participation percentages and terms and conditions of our agreement with Dune Energy and the ExxonMobil Joint Development Agreement.

     As of May 20, 2008, TransAtlantic remains the beneficial holder of a total of 2,237,136 shares of our common stock.

     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.

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Oil and Gas Reserves

     The tables below set forth information as of December 31, 2007 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 Summa Engineering, Inc. The calculations which Summa Engineering, Inc. used in preparation of such report were prepared using geological and engineering methods generally accepted by the petroleum industry and in accordance with Securities and Exchange Commission (“SEC”) guidelines. All estimates were prepared based upon a review of production histories and other geologic, economic, ownership and engineering data we believe to be accurate. The present value of estimated future net revenue shown is not intended to represent the current market value of the estimated oil and gas reserves we own.

	OIL		GAS		TOTAL
	(Mbbl)		(Mmcf)		(Mbble)
Proved developed producing		58.02		3.71		58.64
Proved developed non-producing		—		—		—
Proved undeveloped		238.62		765.23		366.16
Total proved		296.64		768.94		424.80

			Proved
	Proved		Developed
	Developed		Non-		Proved		Total
	Producing		producing		Undeveloped		Proved
Estimated future net revenue(a)	$	2,982,747		—	$	14,367,471	$	17,350,218
Present value of future net revenue(b)	$	2,143,106		—	$	9,005,498	$	11,148,604
Standardized measure of discounted future net cash flows	$	2,143,106		—	$	9,005,498	$	11,148,604

(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, 2007. 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 $94.45 per barrel of oil and $6.83 per mcf of gas.

(b)

Present value of future net revenues represents estimated future net revenues discounted using an annual discount rate of 10%. The present value of future net revenue is equivalent to the standardized measure of discounted future net cash flows at December 31, 2007 as there is no future income tax provision.

     The future net revenue attributable to our estimated proved undeveloped reserves is calculated to be $14.4 million at December 31, 2007, with the present value thereof to be $9.0 million, based on us expending approximately $188,000 during 2009 and an additional $3.6 million in future periods to develop these reserves. 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, 2007, the capital necessary to develop these

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additional reserves was unavailable to us. Through December 31, 2007, we had expended approximately $14.4 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.

     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, 2007, 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,
	2005(1)				2006				2007
	Gross		Net		Gross		Net		Gross		Net
Development Productive		3.0		0.61		2.0		0.05		0.0		0.0
Non-productive		-0-		-0-		-0-		-0-		-0-		-0-
Exploratory Productive		-0-		-0-		-0-		-0-		-0-		-0-
Non-productive		-0-		-0-		-0-		-0-		-0-		-0-

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⁽¹⁾ Excludes 1 (.81 net) well drilled by prior owners on the Bayou Couba properties which we returned to production during 2005.

Past Drilling and Development Activities

     In July 2002, we completed the restoration activities on the Bayou Couba Lease and brought the operation into compliance with applicable regulatory requirements. We also completed reprocessing the 1997 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.

     During 2005, we restored to production 1 (.81 net) well that had been acquired as part of the original Bayou Couba acquisition. We also drilled and completed 3 (.61 net) development wells.

     During 2006, we drilled and completed 2 (.05 net) development wells.

     At December 31, 2007, combined production from all our producing wells on the property was approximately 166 (42 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.

Activities During 2007 and Present Activities

     Because of our limited available capital, our drilling activities are contingent on our securing industry participation or other financing for the drilling and completion costs. Such participation or financing has not yet been secured and we are unable to state at this time the expected terms of such participation or financing. At December 31, 2007, we have no commitments to expend funds for drilling activities in 2008 and presently have no plans to drill any additional wells in 2008.

     Additionally, we are subject to industry limitations on the availability of drilling rigs of sufficient size and configuration that are required to drill wells in our area of operations.

     A “development well” is defined as a well drilled within a proved area of an oil or gas reservoir to a depth of a stratagraphic horizon known to be productive. An “exploratory well” is

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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, 2007.

	Well Count
Area	Gross(1)		Net(1)
St. Charles Parish, Louisiana		21.0		10.60

⁽¹⁾ 18 (9.25 net) of the 21 wells have been classified as primarily oil producing wells. 3 (1.35 net) 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, 2007. All of our production was from our properties located in St. Charles Parish, Louisiana.

	Year Ended December 31,
	2007		2006		2005
Net Production: (1)(2)
Oil (Mbbl)		16.5		23.5		42.8
Natural Gas (Mmcf)		3.5		14.9		6.1
Oil Equivalent (Mbble )		17.1		26.0		43.8
Oil and Natural Gas Sales: (2)
Oil	$	1,199,893	$	1,525,194	$	2,458,123
Natural Gas	$	19,568	$	97,058	$	55,963
Total	$	1,219,461	$	1,622,252	$	2,514,086
Average Sales Price:
Oil ($per Bbl)	$	72.54	$	64.88	$	57.41
Natural Gas ($per Mcf)	$	5.65	$	6.51	$	9.24
Oil Equivalent ($per Bble)	$	71.24	$	62.41	$	57.36
Oil and Natural Gas Costs:
Lease operating expenses	$	470,730	$	345,854	$	496,275
Production Taxes	$	102,968	$	103,111	$	241,854
Depreciation, depletion and amortization	$	441,764	$	638,104	$	1,003,961
Average production cost per unit of production ($  per Bble)	$	33.51	$	17.27	$	16.84

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(1)	Includes only production owned by us and produced to our interest, less royalties and production due others. 265, 228, and 366 barrels of oil were produced in December 2007, 2006 and 2005 but not sold until January 2008, 2007 and 2006, respectively, and are included in inventory at December 31, 2007, 2006 and 2005 at the lower of production cost and DD&A, or market.
(2)	Reflects effects of prior period adjustments resulting from joint interest audits which decreased 2005 production by 8.0 Mbble and revenue by $279,874

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 Ended
	December 31,			December 31,			December 31,
	2005			2006			2007
Development Costs	$	2,043,759		$	1,150,721		$	231,949
Exploration Costs		—			—			—
Acquisition Costs		—			—			—
Sales of Properties	$	(837,500	)	$	(162,500	)	$	(3,500,000	)
Capitalized Interest	$	417,934			—			—
Total	$	1,624,193		$	988,221		$	(3,268,051	)

Acreage

     The following table sets forth as of December 31, 2007, the gross and net acres of both developed and undeveloped oil and natural gas leases which we hold. “Gross” acres are the total number of acres in which we own a working interest. “Net” acres refer to gross acres multiplied by our fractional working interest.

									Total Developed and
	Developed(1)(2)				Undeveloped(1)(2)				Undeveloped
Area	Gross		Net		Gross		Net		Gross		Net
Louisiana		1,319		866		—		—		1,319		866
Total		1,319		866		—		—		1,319		866

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

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agreed to provide an additional 2,560 gross acres (to a depth of 14,000 feet) to the joint development agreement.

(2)

Assumes participation by Dune Energy pursuant to rights granted under an Exploration and Development Agreement. Pursuant to the terms of the agreement we entered into on October 19, 2005 with Dune Energy, we and Dune Energy created an area of mutual interest in which we have agreed with Dune Energy to share all rights, title and interest owned or acquired on an equal basis on our Bayou Cuba lease acreage of approximately 1,319 acres, the acreage covered by our development agreement with ExxonMobil Corporation (“ExxonMobil”) of approximately 11,486 acres which are included in the 31,367 acre area, as well as any additional acreage offered to us or Dune Energy by ExxonMobil as the result of the acquisition of additional 3-D seismic data by the parties under the terms of the Agreement.  On June 26, 2007 Dune Energy acquired additional rights from us relating to the contract areas subject to the ExxonMobil joint development agreement but such rights do not affect the net acres reflected.

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 2007, our oil sales to Teppco Crude Oil, L.P. and Texon L.P. of $1,199,893 accounted for 98% of our total oil and gas sales. We believe we are not materially dependent upon Teppco or Texon for our sales as we believe there are numerous other purchasers for our oil production at competitive prices. Our gas sales to Transcontinental Pipeline Corporation of $19,568 accounted for 2% 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, as it relates to market access, 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

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also be presented by alternative fuel sources, including heating oil and other fossil fuels. Because the primary markets for natural gas liquids are refineries, petrochemical plants and fuel distributors, prices are generally set by or in competition with the prices for refined products in the petrochemical, fuel and motor gasoline markets.

Regulation

     General

     Numerous departments and agencies, federal, state and local, issue rules and regulations binding on the oil and gas industry, some of which carry substantial penalties for failure to comply. The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability. At December 31, 2007, 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 (including Louisiana) 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

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thereunder and claims for damages for injuries to property, employees, other persons and the environment resulting from our operations could have on our activities.

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

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

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responsible classes of persons the costs of such action. In the course of our operations, we may generate wastes that fall within CERCLA’s definition of “hazardous substances”. We may also be an owner of sites on which “hazardous substances” have been released. We may be responsible under CERCLA for all or part of the costs to clean up sites at which such wastes have been released. To date, however, we have not and, to our knowledge, our predecessors or successors have not been named a potentially responsible party under CERCLA or similar state superfund laws affecting property we owned or leased.

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

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

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

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

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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.

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Operating Hazards and Insurance

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

     We maintain comprehensive general liability policies with coverage considered adequate by management. Dune Energy carries insurance coverage covering their activities as operator of the Bayou Couba field. 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, 2007, we employed six persons, of whom two were executive officers and two were operations personnel and two were accounting staff. We do not employ a significant number of temporary employees. None of our employees is represented by a labor union, and we believe our relationship with our employees is good.

Organization

     We are an Oklahoma corporation organized in January 2001. In June 2001, we became a wholly-owned subsidiary of Gothic Resources Inc., a British Columbia corporation. 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.

     Prior to our acquisition of Couba, 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. In early 2000, Couba had depleted its borrowing availability under a bank line of credit and had insufficient capital to continue in operations. 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 was finally confirmed by the Court on November 16, 2001.

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Office

     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 $91,592. 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, 2007 to a vote of security holders through the solicitation of proxies or otherwise.

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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 not currently traded on any United States or Canadian 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 either the United States or Canada. Effective July 25, 2007, the TSX Venture Exchange suspended trading in our securities as a result of a Cease Trade Order issued by the British Columbia Securities Commission.

     The reported high and low sales prices, reported in United States dollars, 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, 2006 and through July 25, 2007 (the last date of trading on the Exchange) were as follows.

	Prices
	High		Low		Share Volume
2005
First Quarter	$	0.31	$	0.12		4,200,014
Second Quarter	$	0.27	$	0.09		2,953,769
Third Quarter	$	0.15	$	0.10		1,918,963
Fourth Quarter	$	0.12	$	0.06		4,350,110
2006
First Quarter	$	0.15	$	0.05		3,822,078
Second Quarter	$	0.25	$	0.08		2,224,343
Third Quarter	$	0.08	$	0.03		5,130,461
Fourth Quarter	$	0.12	$	0.02		6,073,607
2007
First Quarter	$	0.10	$	0.05		2,347,654
Second Quarter	$	0.05	$	0.03		2,500,333
Third Quarter through July 25, 2007*	$	0.05	$	0.03		378,331

* Effective July 25, 2007, TSX Venture Exchange suspended trading in our securities as a result of the Cease Trade Order issued by the British Columbia Securities Commission.

     As of May 20, 2008, we had 2,984 stockholders of record.

     On May 1, 2007, the British Columbia Securities Commission issued a cease trade order (the “Management Cease Trade Order”) restricting trading in our securities by certain of our insiders until we file the Annual Financial Statements and related annual filings. We filed a

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Notice of Default dated May 1, 2007 (the “Notice of Default”), and subsequently filed Default Status Report updates dated May 15, 2007 (the “First Default Status Report”), May 29, 2007 (the “Second Default Status Report”), June 12, 2007 (the “Third Default Status Report”) and June 26, 2007 (the “Fourth Default Status Report”) as required by 57-301. Effective July 25, 2007, TSX Venture Exchange suspended trading in our securities as a result of the Cease Trade Order issued by the British Columbia Securities Commission.

     We had been unable to complete the Annual Financial Statements and related annual filings and were unable to file the Annual Financial Statements and related annual filings prior to June 30, 2007 due to our inability to make payment on outstanding invoices to our auditors for services previously performed. As a result of the delays in completing the Annual Financial Statements, we were also delayed in filing our interim financial statements for the three-months ended March 31, 2007, the six-months ended June 30, 2007 and the nine-months ended September 30, 2007 (the “Interim Financial Statements”) which were due by May 15, 2007, August 14, 2007 and November 14, 2007, respectively.

     We intend to seek to have a trading market for our common shares develop in the United States. There can be no assurance that we will be successful in this regard. We do not meet the requirements to have our common shares included in any NASDAQ trading system or listed on any national securities exchange. However, we do intend to seek to have our shares quoted on the OTC Bulletin Board®. 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.

Small Business Issuer Purchases of Equity Securities

     No purchases of shares of our Common Stock, par value $.001 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 year ended December 31, 2007.

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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 and 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 2007 and 2006 of approximately $3.2 and $2.5 million, respectively, and have a working capital deficiency and an accumulated deficit at December 31, 2007 which leads to questions concerning our ability to meet our obligations as they come due. At December 31, 2007, we have $10.8 million principal amount of secured Debentures outstanding that are in default and are immediately due and payable. 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 drilling participations, 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 in addition to the quantities of oil and natural gas we sell. 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, 2007 includes an explanatory paragraph which states that we have sustained substantial losses in 2007 and have a working capital deficiency and an accumulated deficit at December 31, 2007 that raise substantial doubt about our ability to continue as a going concern.

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Statements of Operations

A Comparison of Operating Results for the Years Ended December 31, 2007 and December 31, 2006

     We incurred a net loss of $3,229,000 during the year ended December 31, 2007 compared to a net loss of $2,452,000 for the year ended December 31, 2006. During the year ended December 31, 2007, our revenues were comprised of oil and gas sales and operations income totaling $1,353,000 compared with oil and gas sales and operations income of $1,783,000 in 2006. Our oil and gas sales and operations income for the year ended December 31, 2007 decreased as a result of decreased oil and gas production; however, this decrease was partially offset by higher oil prices in 2007. Production on a barrels equivalent basis decreased 34% from 2006 to 2007. Oil prices increased on average 13% from 2006 to 2007. At December 31, 2007, we had 21 (10.60 net) wells producing approximately 166 (42 net) barrels of oil equivalents per day, whereas at December 31, 2006, we had 21 (10.39 net) wells producing approximately 464 (75 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 and typically will decrease over time.

     Our total expenses were $4,582,000 for the year ended December 31, 2007 as compared to $4,235,000 for the year ended December 31, 2006. Total expenses increased by $347,000. An increase in foreign exchange loss and lease operating expenses were partially offset by a decrease in general and administrative expenses, interest and depreciation, depletion and amortization charges. In addition, an increase in gain on settlement of debt had a positive impact on total expenses for the year ended December 31, 2007.

     Lease operating expenses in 2007 were $471,000 compared to $346,000 in 2006. Lease operating expenses increased on a per unit basis of production after field operations were transferred to Dune Energy. Production taxes remained consistent at $103,000 for the years 2007 and 2006. Depletion, depreciation and amortization of $601,000 in 2007 decreased from $977,000 in 2006. This was primarily the result of decreased production of oil and natural gas and the related depletion expense.

     Our general and administrative expenses decreased from $1,597,000 in 2006 compared to $1,227,000 in 2007. The decrease is primarily due to reduced fees for professional services and a reduction in the estimated Canadian taxes due on dissolution of Gothic Resources.

     We had a foreign exchange loss of $1,976,000 and $46,000 in 2007 and 2006, 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 January 31, 2005, an application has been made to liquidate the Gothic subsidiary and terminate its charter. Therefore, upon final liquidation, amounts reflected in accumulated other comprehensive income will be included in the gain or loss recognized from the disposal of the subsidiary.

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     We settled $1.4 million of debt for a net gain of $837,000 in 2007. In 2006, we settled $314,000 of debt for a net gain of $108,000.

     Interest and financing costs decreased from $1,274,000 for the year ended December 31, 2006 to $1,014,000 for the year ended December 31, 2007. Interest expense decreased in the 2007 period due to the lack of amortization of financing costs related to amending our debentures as these costs were fully amortized by September 30, 2006.

     Depreciation, depletion and amortization expense attributable to oil and gas properties decreased to $442,000 during the year ended December 31, 2007 from $638,000 during the year ended December 31, 2006 due to our decreased production.

     We recorded an allowance for doubtful accounts of $26,000 in 2007. There was no such charge in 2006.

A Comparison of Operating Results for the Years Ended December 31, 2006 and December 31, 2005

     We incurred a net loss of $2,452,000 during the year ended December 31, 2006 compared to a net loss of $6,172,000 for the year ended December 31, 2005. During the year ended December 31, 2006, our revenues were comprised of oil and gas sales and operations income totaling $1,783,000 compared with oil and gas sales and operations income of $2,627,000 in 2005. Our oil and gas sales and operations income for the year ended December 31, 2006 decreased as a result of decreased oil and gas production; however, this decrease was partially offset by higher oil prices in 2006. Production on a barrels equivalent basis decreased 39% from 2005 to 2006. Oil prices increased on average 13% from 2005 to 2006, while natural gas prices decreased on average 30% from 2005 to 2006. At December 31, 2006, we had 21 (10.39 net) wells producing approximately 464 (75 net) barrels of oil equivalents per day, whereas at December 31, 2005, we had 19 (10.52 net) wells producing approximately 606 (122 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 and typically will decrease over time.

     Our total expenses were $4,235,000 for the year ended December 31, 2006 as compared to $8,799,000 for the year ended December 31, 2005. Total expenses primarily decreased due to lower interest and lower depreciation, depletion and amortization charges in 2006. In addition, costs were incurred for loss on extinguishment of debt and taxes due on dissolution of subsidiary in 2005 with no similar charges in 2006.

     Lease operating expenses in 2006 were $346,000 compared to $496,000 in 2005. Lease operating expenses were lower in 2006 as a result of decreased production. Production taxes also decreased from $242,000 in 2005 to $103,000 in 2006 due to decreased production and consequently, revenue from oil and gas sales. Depletion, depreciation and amortization of $977,000 in 2006 decreased from $1,589,000 in 2005. This was primarily the result of decreased production of oil and natural gas and the related depletion expense.

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     Our general and administrative expenses remained consistent at $1,597,000 in 2006 compared to $1,564,000 in 2005.

     We accrued an estimate of tax due on dissolution of our Canadian subsidiary in the amount of $303,000 as the result of a possible tax exposure relating to the liquidation of Gothic. There was no such expense in 2006.

     We had a foreign exchange loss of $46,000 and $347,000 in 2006 and 2005, 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 January 31, 2005, an application has been made to liquidate the Gothic subsidiary and terminate its charter. Therefore, upon final liquidation, amounts reflected in accumulated other comprehensive income will be included in the gain or loss recognized from the disposal of the subsidiary.

     We had a gain of $108,000 in 2006 due to the settlement of debt with various vendors. There was no such gain in 2005.

     We had a loss on the extinguishment of debt in 2005 of $1,147,000 as a result of amending our Debentures as is described below. We had no such loss in 2006.

     Interest expense, net of interest capitalized of $418,000 in 2005, decreased from $3,110,000 in 2005 to $1,274,000 in 2006. While debt outstanding increased during 2006, interest expense decreased as a result of amending our Debentures. Prior to the amendment, interest expense reflected the amortization of a beneficial conversion feature related to the issuance in October 2003 of our 8% Convertible 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 $0.45 to $0.43 per share resulting in the additional beneficial conversion feature. Such amount was amortized to interest expense over the life of the Debentures prior to the amendment. In June 2005, the Debentures were amended with approval by approximately 86% of the Debentureholders. The amendments extended the maturity date of the Debentures by one year to September 30, 2006, reduced through the maturity date of the Debentures the per share price at which the principal of the Debentures could be converted into shares of Common Stock to $0.15 per share, and provided for the partial release of the lien collateralizing the Debentures in the event a third party entered into an agreement with us pursuant to which the third party is granted the right to drill one or more wells on our properties and commenced that drilling activity.

     Under the amendments at December 31, 2006, 72,166,667 shares were issuable upon full conversion of the Debentures at the reduced conversion price; however, the conversion rights

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feature expired on September 29, 2006 and have not been renewed. On June 23, 2005, our stockholders voted to amend the Certificate of Incorporation to increase the number of shares of Common Stock we are authorized to issue from 100 million to 250 million and adjust the par value from $0.01 to $0.001 per share. This increase in authorized shares, along with the approval of the TSX Venture Exchange to the transactions, provided final approval of the Debenture amendments. As a result of the amendment, a loss on extinguishment of debt of $1,147,000 was recognized and the Debentures were recorded on June 23, 2005 at their fair market value, reflecting the present value of future cash flows and the option value of the underlying convertible shares. Costs associated with the amendment totalling $303,000 were amortized to interest expense over the remaining life of the Debentures. The Debentures were due on September 30, 2006 and are currently in default.

     Depreciation, depletion and amortization expense attributable to oil and gas properties decreased to $638,000 during the year ended December 31, 2006 from $1,004,000 during the year ended December 31, 2005 due to our decreased production.

Liquidity and Capital Resources

     General

     At December 31, 2007, we do not have any available borrowing capacity under existing credit facilities and our current assets are $274,000 compared with current liabilities of $18.4 million. Our current liabilities include approximately $10.8 million of secured indebtedness, which was due September 2006 and is currently in default, and accounts payable, revenues payable, notes payable, and other current obligations aggregating to approximately $7.6 million. We have substantial needs for funds to pay our outstanding payables and debt due during 2008.

     We have substantial need for capital to develop our oil and gas prospects and opportunities we believe that have been identified in our ExxonMobil AMI. Since 2001, we have funded our capital expenditures and operating activities through a series of debt and equity capital-raising transactions, drilling participations and through an increase in vendor payables and notes payable. We expect any future capital expenditures for drilling and development to be funded from the sale of drilling participations and equity capital. It is management’s plan to raise additional capital through the sale of interests in our drilling activities or other strategic transactions; 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, 2007 and December 31, 2006

     Our net cash used by operating activities was $1,818,000 in 2007 as compared to net cash provided by operating activities of $1,700,000 in 2006, a decrease of $3,518,000. The decrease in net cash provided by operating activities for 2007 was primarily due to a non-cash gain on settlement of debt and negative changes in accounts payable, partially offset by a larger foreign exchange loss and positive changes in accounts receivable during the period. Changes in

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working capital items had the effect of decreasing cash flows from operating activities by $356,000 during 2007 due to a decrease in accounts receivable of $633,000. Changes in working capital items had the effect of increasing cash flows from operating activities by $2.9 million during 2006 due to an increase in accounts payable.

     We generated $1,405,000 of net cash from investing activities during 2007 compared to net cash used of $1,347,000 in 2006. The 2007 cash provided by investing activities included $2,946,000 in proceeds from the sale of participation rights (which were accounted for as a reduction in unproved properties), partially offset by $310,000 for the purchase and development of oil and gas properties. We used $253,000 for the purchase of fixed assets and received proceeds of $22,000 from the sale of fixed assets. The 2006 cash used in investing activities includes $1,501,000 for the purchase and development of oil and gas properties and $9,000 for the purchase of fixed assets. Additionally in 2006, we had proceeds from the sale of participation rights of $163,000. The expenditures for oil and gas properties in 2007 and 2006 are primarily the result of the development of oil and gas properties acquired in prior periods.

     We used $450,000 of net cash in financing activities for the year ended December 31, 2007 compared to $537,000 of net cash used in financing activities for the same period in 2006. For the years ended December 31, 2007 and 2006, net cash outflows from financing activities were primarily a result of payments against outstanding notes and bank overdrafts.

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

Years Ended December 31, 2006 and December 31, 2005

     Our net cash provided by operations was $1,700,000 for the year ended December 31, 2006 as compared to net cash provided by operations of $856,000 for 2005.

     The increase in cash provided by operations in 2006 compared to 2005 was a result of increased revenues payable and accrued liabilities. While reductions in oil and gas production decreased cash provided by operations, this was offset by a decrease in production taxes and lease operating expenses and an increase in revenues payable and accrued liabilities. Cash flow attributable to working capital items increased by $1,549,000 from 2005 to 2006, which was principally due to increases in revenues payable and accrued liabilities.

     We used $1,347,000 of net cash in investing activities during the year ended December 31, 2006 compared to net cash used of $1,885,000 in 2005. The 2006 cash used in investing activities includes $1,501,000 for the purchase and development of oil and gas properties and $9,000 for the purchase of fixed assets compared to $2,695,000 and $28,000, respectively, in 2005. Additionally, we had proceeds from the sale of participation rights of $163,000 and $838,000 for the years ended December 31, 2006 and 2005 respectively.

     Our net cash used by financing activities for the year ended December 31, 2006 was $537,000 compared to $911,000 provided in 2005. The activity in 2006 was the result of the

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issuance of a note payable, offset by payments of notes payable. The activity in 2005 was the result of the private sale of 12.2 million shares of our common stock and the issuance of a note payable, offset by payments of notes payable.

     How We Have Financed Our Activities

     Our activities since 2002 have been financed primarily from sales of debt and equity securities and drilling participations.

     On October 21, 2003 and October 31, 2003 we completed financing transactions of $11.695 million and $305,000, respectively, by issuing our Convertible Secured Debentures (the “Debentures”). Initially, the Debentures were 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 our common shares at a conversion price of $0.45 per share, subject to antidilution adjustment. The Debentures are collateralized by substantially all of our assets and have covenants limiting unsecured borrowings to $2 million and restricting the payment of dividends and capital distributions. A finder’s fee in the amount of $360,000 was paid to Middlemarch Partners Limited of London, England in connection with the financing.

     In June 2005, the Debentures were amended with approval by approximately 86% of the Debentureholders. The amendments extended the maturity date of the Debentures by one year to September 30, 2006, reduced through the maturity date of the Debentures the per share price at which the principal of the Debentures could be converted into shares of common stock to $0.15 per share, and provided for the partial release of the lien collateralizing the Debentures in the event a third party entered into an agreement with us pursuant to which the third party is granted the right to drill one or more wells on our properties and commenced that drilling activity. Under the amendments, 72,166,667 shares were issuable upon full conversion of the Debentures at the reduced conversion price; however, the conversion rights feature expired on September 29, 2006 and was not renewed.

     Out of the proceeds from the sale of the Debentures in 2003, we used approximately $5.9 million 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 Agreement in St. Charles Parish, Louisiana. In addition, we paid out of the proceeds a $1.7 million production payment owing to TransAtlantic. TransAtlantic retained a 10% participation right in our AMI with ExxonMobil which we granted in March 2003 as partial consideration for the $2.0 million financing entered into at that time. 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.

     Purchasers of the Debentures included TransAtlantic $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. Quest Capital Corp. is engaged in merchant banking

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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.

     In connection with the Debenture financing and under the terms of the transaction, two persons were designated to serve as Directors of our company. At present, both of such Director positions are vacant and the holders of the Debentures have not designated any persons to fill the vacancies.

     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.

     During the third quarter of 2005, we completed a private sale of 12,193,333 shares of our common stock for gross proceeds of $1,463,000 ($1,428,000 net). Additionally, 2,170,000 shares were issued as payment for professional services in the amount of $250,000 relating to restructuring of our Debentures. The net proceeds were used for working capital and the drilling of three wells.

          On October 19, 2005 we executed the definitive Exploration and Development Agreement (the “Agreement”) with Dune Energy, providing for the creation of an area of mutual interest covering an area of approximately 31,367 acres. Pursuant to the terms of the Agreement, Dune Energy agreed to pay us in instalments a prospect fee in the amount of $1.0 million, all of which has been paid. Under the original Agreement, in the event we and Dune Energy elect to complete the first two exploratory wells drilled pursuant to the Agreement, upon the receipt by Dune Energy of a log from either of those two wells, Dune Energy would pay to us an additional prospect fee of $500,000. However, as a result of Dune Energy paying 100% of the costs for our participation in the 3D seismic survey being conducted by SEI and described above, the terms of the Agreement between us and Dune Energy were amended to waive any additional prospect fees that may be due from Dune. On June 26, 2007, Dune Energy increased its participation to 75% of our interest under these agreements, excluding the area under the Bayou Couba lease itself where it retains a participation of 50% of our interest, with the payment of $3 million. On September 1, 2007 Dune Energy was elected successor operator under the joint development agreement and Dune Energy paid us an additional $500,000. We used the proceeds from these payments to reduce outstanding obligations.

     During the year ended December 31, 2005, we converted an aggregate of approximately $1.74 million of accounts payable and other current obligations into notes payable. During the year 2006, we converted an aggregate of approximately $340,000 of accounts payable into notes payable. At December 31, 2006, $1.0 million principal amount of such notes were outstanding of which $739,000 was due prior to year end and past due. The balance was due on various dates through December 31, 2007. At December 31, 2007, $75,000 principal amount of such notes was outstanding and past due.

Future Capital Requirements and Resources

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     At December 31, 2007, we do not have any available borrowing capacity under existing credit facilities and our current assets are $274,000 compared with current liabilities of $18.4 million. Our current liabilities include approximately $10.8 million of secured indebtedness, which was due September 2006 and is currently in default, and accounts payable, revenues payable, notes payable (a portion of which is past due), and other current obligations aggregating to approximately $7.6 million. We have substantial needs for funds to pay our outstanding payables and debt due during 2008. In addition, we have substantial need for capital to develop our oil and gas prospects and opportunities identified in our ExxonMobil AMI. At December 31, 2007, we have no commitments for additional capital to fund drilling activities in 2008.

     Since 2001, we have funded our capital expenditures and operating activities through a series of debt and equity capital-raising transactions, drilling participations and, during the last two quarters of 2004 and all of 2005 and 2006, through an increase in vendor payables and notes payable. Any capital expenditures for drilling purposes during 2008, we expect will be funded from the sale of drilling participations and equity capital. It is our intention to raise additional capital through the sale of interests in our drilling activities or other strategic transactions; however, we currently have no firm commitment from any potential investors and such additional capital may not be available to us in the future.

     Our business strategy requires us to obtain additional financing and our failure to do so can be expected to adversely affect our ability to further the development of our ExxonMobil AMI, grow our revenues, oil and gas reserves and achieve and maintain a significant level of revenues and profitability. There can be no assurance we will obtain this additional funding. Such funding may be obtained through the sale of 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.

Critical Accounting Policies

Oil and Gas Properties

     We account for our oil and gas exploration and development activities using the full cost method of accounting prescribed by the SEC. Accordingly, all our productive and non-productive costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves are capitalized and depleted using the units-of-production method based on proved oil and gas reserves. We capitalize our costs including salaries and related fringe benefits of employees directly engaged in the acquisition, exploration and development of oil and natural gas properties, asset retirement costs, as well as other directly identifiable general and administrative costs associated with these activities. These costs do not include any costs related to production, general corporate overhead, or similar activities. Our oil and natural gas reserves will be estimated annually by independent petroleum engineers. Our calculation of

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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.

     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

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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 carryforwards prior to their expiration. Accordingly, we are required to provide a valuation allowance against our deferred tax asset. As of December 31, 2007 and 2006, we have a deferred tax asset of approximately $15.2 million and $15.1 million for which we have recognized a $15.2 million and $15.1 million valuation allowance, respectively.

Notes payable and long-term debt

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     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. Any un-amortized premium or discount remaining at early retirements of a debt instrument is recorded as a gain or loss as applicable.

Asset Retirement Obligation

     Effective January 1, 2003, we 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.

     Under SFAS 143 we recognize the fair value of a liability for a retirement obligation 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.

Accounting Matters

     In December 2004, the FASB issued Statement on Financial Accounting Standards (“SFAS”) No. 123 (Revised 2004), Share-Based Payment, revising FASB Statement 123, Accounting for Stock-Based Compensation and superseding APB opinion No. 25, Accounting for Stock Issued to Employees (“SFAS 123R”). 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. We adopted SFAS 123R in the first quarter of 2006 using the modified prospective method with no restatement of prior periods. The adoption of SFAS 123R did not have a material impact on our financial position or results of operations.

     In July 2006, the FASB issued FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109. FIN 48 provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS 109, Accounting for Income Taxes. FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 did not have a material impact on our financial position, results of operations or cash flows.

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          In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company does not expect that SFAS 157 will have a material impact on its financial position, results of operations or cash flows.

     In September 2006, the SEC issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 provides guidance on how to evaluate prior period financial statement misstatements for purposes of assessing their materiality in the current period.  If the prior period effect is material to the current period, then the prior period is required to be corrected.  Correcting prior year financial statements would not require an amendment of prior year financial statements, but such corrections would be made the next time the company files the prior year financial statements.  Upon adoption, SAB 108 allows a one-time transitional cumulative effect adjustment to retained earnings for corrections of prior period misstatements required under this statement.  SAB 108 is effective for fiscal years beginning after November 15, 2006. We do not anticipate any material changes as a result of application of this Bulletin.

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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 2006 and 2007, totaling approximately $2.5 million and $3.2 million, respectively, and had a working capital deficiency at December 31, 2007 of approximately $18.1 million. Production from our drilling program decreased during 2007 compared to 2006 resulting in decreased revenue during 2007. Our revenue has not been sufficient to fund our operations. At December 31, 2007, we do not have any available borrowing capacity under existing credit facilities and our current assets are $274,000 compared with current liabilities of $18.4 million. Our current liabilities include approximately $10.8 million of secured indebtedness, which was due September 2006 and is currently in default and accounts payable, revenues payable, notes payable, and other current obligations aggregating to approximately $7.6 million. We have substantial needs for funds to pay our outstanding payables and debt due during 2008. 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, 2007 includes an explanatory paragraph which states that we have sustained substantial losses in 2007 and have a working capital deficiency and an accumulated deficit at December 31, 2007 that raise substantial doubt about our ability to continue as a going concern.

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     We Defaulted in the Repayment of $10.825 Million of Secured Indebtedness on September 30, 2006. There Are Risks That the Holders of This Indebtedness May Seek to Assert Their Rights as Secured Creditors and Foreclose On Our Assets.

     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. As of December 31, 2007, a total of $1.175 million of Debentures was converted to common stock. The remaining $10.825 million borrowing was due to be repaid on September 30, 2006. In addition, as of December 31, 2007, we are in default in the payment of $1.5 million of interest on the Debentures. 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. As a consequence of the indebtedness being in default, 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 paying such amounts or 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, 2007 Exceed Our Current Assets by $18.1 Million

     As of December 31, 2007, our current assets were approximately $274,000 and our current liabilities were approximately $18.4 million. In order to meet our current obligations, we will need to raise additional capital. At May 20, 2008, 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 Will Be Unable To Fund The Exploration and Development Activities To Further Develop Our Area Of Mutual Interest With ExxonMobil

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     We also have substantial needs for funds to further develop our oil and gas prospects and opportunities identified in our AMI with ExxonMobil. At December 31, 2007, we have no plans or commitments for drilling activities in 2008 and currently lack the funds to engage in such activities. Any capital expenditures must 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 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;

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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, Borrowing Capacity and Ability to Repay Notes Payable .

     In the ordinary course of business and in order to pursue successfully our business plan, we must 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 out of our cash flow, through increases in vendor payables and notes payable and 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 repay outstanding notes payable, 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 will 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 potential 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

     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

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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.

     We intend to seek to refinance our existing indebtedness .The issuance of material amounts of indebtedness would expose us to significant 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.

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.

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     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, 2007, based on the report of Summa Engineering, Inc., we claimed total estimated proved reserves of 424.8 Mbble of oil and gas. Through December 31, 2007, we were able to return to production 9 (7.31 net) well bores drilled by prior owners on the Couba properties we acquired, and we had successfully completed 12 (3.29 net) wells. As of that time, our combined production from all our producing wells was approximately 166 (42 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

39

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.

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

40

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.

Shortages of Oil Field Equipment, Services and Qualified Personnel Could Adversely Affect Our Results Of Operations.

     The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. There have also been shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher natural gas and oil prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. We cannot be certain when we will experience shortages or price increases, which could adversely affect our

41

profit margin, cash flow and operating results or restrict our ability to drill wells and conduct ordinary operations.

Risks Relating to the Market for Our Securities

Absence of a Public Market for Our Common Shares.

     Our common shares presently have no trading market in the United States or Canada, and there can be no assurance as to the liquidity of any markets that may develop in the future for the common shares, the ability of the holders of common shares to sell their common shares in the United States or Canada 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 ability to repay or extend the maturity of our Debentures that matured in September 2006, our ability to raise capital and fund our oil and gas well drilling and development plans, our ability to fund the repayment of our 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.

     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

42

2008 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:

          On July 16, 2007, we dismissed PricewaterhouseCoopers, LLP (“PwC”) as our independent registered public accounting firm. Our audit committee and board of directors approved the dismissal of PwC. During the fiscal years ended December 31, 2004 and 2005, the last fiscal years audited by PwC, and through July 16, 2007, the date of dismissal of PwC, we had no disagreements with PwC with respect to accounting principles or practices, financial statement disclosure, or auditing scope or procedure which, if not resolved to the satisfaction of PwC, would have caused PwC to make reference to the subject matter of its disagreement in connection with its reports on such financial statements for such years.

Item 8A(T) — Controls and Procedures

   (a) Managements Annual Report on Internal Control Over Financial Reporting

     Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act, as amended, as a process designed by, or under the supervision of, a company’s principal executive and principal financial officers and effected by a company’s board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:

*   pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

*   provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors;

*   and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

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     Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate. In order to evaluate the effectiveness of our internal control over financial reporting as of December 31, 2007, as required by Sections 404 of the Sarbanes-Oxley Act of 2002, our management commenced an assessment, based on the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “ COSO Framework “). A material weakness is a control deficiency, or a combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. In assessing the effectiveness of our internal control over financial reporting, our management, including the chief executive officer and chief financial officer, identified the following deficiencies: (1) Deficiencies in Segregation of Duties. The Chief Executive Officer and the Chief Financial Officer are actively involved in the preparation of the financial statements, and therefore cannot provide an independent review and quality assurance function within the accounting and financial reporting group. The limited number of qualified accounting personnel discussed above results in an inability to have independent review and approval of financial accounting entries. Furthermore, management and financial accounting personnel have wide-spread access to create and post entries in the Company’s financial accounting system. There is a risk that a material misstatement of the financial statements could be caused, or at least not be detected in a timely manner, due to insufficient segregation of duties, and (2) Our financial statement closing process did not identify all the journal entries that needed to be recorded as part of the closing process for certain complex and non-routine transactions. As part of the audit, our independent registered public accounting firm proposed certain entries that should have been recorded as part of the normal closing process. Our internal control over financial reporting did not detect such matters and, therefore, was not effective in detecting misstatements in the financial statements.

To address the material weakness, we performed additional analysis and other post-closing procedures in an effort to ensure our consolidated financial statements included in this annual report have been prepared in accordance with generally accepted accounting principles. Accordingly, management believes that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented. As a result, we have put an implementation plan in place whereby in 2008 sufficient testing to satisfy COSO requirements will be performed. The absence of the ability to conclude as to the sufficiency of internal controls, is a material weakness.

     This annual report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Our internal controls were not subject to attestation by our independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only managements report in this annual report.

(b) Changes in Internal Control Over Financial Reporting

     There have been no changes in our internal controls over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal controls over financial reporting.

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     Despite the internal control deficiencies, we believe that our financial statements contained in this Form 10-KSB filed with the SEC fairly present our financial position, results of operations and cash flows for the fiscal year ending December 31, 2007 in all material respects.

Item 8B — Other Information

     No information is required to be disclosed in response to this Item 8B.

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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		Position
Directors and Executive Officers:
Michael K. Paulk (1)		59	President and Director
Steven P. Ensz		56	Vice President, Finance, and Chief Financial Officer and Director
Brian E. Bayley(1)		55	Director
John K. Campbell(1)		74	Director
Significant Employees:
Richard O. Mulford		55	Manager of Operations
Robert G. Snead		69	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 18 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 producer, for more than 21 years. He is a certified public accountant.

46

     Brian E. Bayley: Mr. Bayley was elected a Director of the Company in June 2001. Mr. Bayley is Co-Chair of Quest Capital Corp. Previously he was the President (June 2003-January 1, 2008) and Chief Executive Officer (June 2003 to March 17, 2008) of Quest Capital Corp. Quest Capital Corp. trades on the Toronto Stock Exchange and Amex under the symbol QC. Quest Capital Corp. is a public mortgage investment company. Since December 1996, he has served as President and Director of Ionic Management Corp. (formerly Quest Management Corp.), a management company that 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, four of which are reporting issuers 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, 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.

     In connection with our October 2003 Debenture financing and under the terms of the transaction, two persons were designated to serve as Directors of our company. At present, both of such Director positions are vacant and the holders of the Debentures have not designated any persons to fill the vacancies.

     Our Board of Directors has not adopted procedures by which security holders may recommend nominees to our Board of Directors.

Significant Employees:

     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 from April 1997 to January 2001. 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 October 31, 2007, the members of our Audit Committee of our Board of Directors are Messrs. Bayley (Chairman), Campbell and Paulk. Messrs. Bayley and Campbell have been

47

members of the Audit Committee since 2002 and Mr. Paulk was added in December 2006. Our securities are not listed on any national securities exchange or listed on an automated inter-dealer quotation system.

     Our Board of Directors has adopted an Audit Committee Charter. Our Audit Committee Charter, as adopted on April 22, 2004, was attached as Annex A to our Proxy Statement dated June 14, 2004. 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.

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Item 10 — Executive Compensation:

     The following table sets forth the compensation of our principal executive officer and all of our other executive officers for the two fiscal years ended December 31, 2007 who received total compensation exceeding $100,000 for the year ended December 31, 2007 and who served in such capacities at December 31, 2007.

SUMMARY COMPENSATION TABLE
Annual Compensation

							Nonqualified
Name						Non-Equity	Deferred
and				Stock	Option	Incentive Plan	Compensation	All Other
Principal		Salary	Bonus	Awards	Awards	Compensation	Earnings	Compensation	Total
Position	Year	($)	($)	($)(1)	($)(1)	($)	($)	($)	($)
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
Michael K. Paulk, President and CEO(2)	2007 2006	$150,000 $125,000	-0- -0-	-0- -0-	-0- -0-	-0- -0-	-0- -0-	-0- -0-	$150,000 $125,000
Steven P. Ensz Executive Vice President and CFO(2)	2007 2006	$150,000 $125,000	-0- -0-	-0- -0-	-0- -0-	-0- -0-	-0- -0-	-0- -0-	$150,000 $125,000

(1)	Represents the dollar amount recognized for financial statement reporting purposes with respect to the fiscal year in accordance with FAS 123R. See Note 1 to Notes to Financial Statements for the year ended December 31, 2006.
(2)	Messrs. Paulk and Ensz are also Directors of our company; however they receive no additional compensation for serving in those capacities.

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

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Outstanding Equity Awards at December 31, 2007.

     The following table provides information with respect to our named executive officers above regarding outstanding equity awards held at December 31, 2007.

Option Awards

Stock Awards

Number

Market

Equity

of

value of

Incentive

shares

shares

Plan

Equity Incentive

Equity

or units

or units

Awards:

Plan Awards:

Number of

Incentive

of

of

Number of

Market or

securities

Plan Awards:

Stock

Stock

Unearned

payout value of

underlying

Number of

held

held

Shares,

Unearned

unexercised

Securities

that

that

Units or

Shares, Units or

Options

Underlying

Option

have

have

Other Rights

Other Rights

(#)

Unexercised

Exercise

Option

not

not

That Have

That Have Not

Exercisable/

Unearned

Price

Expiration

vested

vested

Not Vested

Vested

Name

Unexercisable

Options (#)

($)

Date

(#)

($)

(#)

($)

(a)

(b-c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

Michael K. Paulk

250,000

-0-

0.45

4/22/09

-0-

-0-

-0-

-0-

Steven P. Ensz

250,000

-0-

0.45

4/22/09

-0-

-0-

-0-

-0-

Director Compensation

     The following table provides information with respect to compensation of our Directors during the year ended December 31, 2007. The compensation paid to our named executive officers who are also Directors is reflected in the Summary Compensation Table above.

	Fees								Non-
	earned						Non-Equity		Qualified
	or paid		Stock		Option		Incentive Plan		Deferred		All Other
	in cash		Awards		Awards		Compensation		Compensation		Compensation		Total
Name	($)		($)(1)		($)(1)		($)		Earnings		($)		($)
(a)	(b)		(c)		(d)		(e)		(f)		(g)		(h)
Brian E. Bayley		-0-		-0-		-0-		-0-		-0-		-0-		-0-
John K. Campbell		-0-		-0-		-0-		-0-		-0-		-0-		-0-

(1) Represents the dollar amount recognized for financial statement reporting purposes with respect to the fiscal year in accordance with FAS 123R. See Note 1 to Notes to Financial Statements for the year ended December 31, 2007.

     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-

50

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 May 20, 2008 (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 May 20, 2008, we had 52,997,673 common shares outstanding.

				Percentage of
	Number of Shares			Outstanding
Name and Address(1)(2)	Owned			Shares(3)
Michael K. Paulk		2,398,875	(4)		4.5	%
Steven P. Ensz		3,398,313	(5)		6.4	%
Brian E. Bayley Suite 300 — 570 Granville Street Vancouver, BC V6C 3P1		1,645,625	(6)		3.1	%
John K. Campbell 750 West Pender Street — Suite 710 Vancouver, BC V6C 2T7		115,528	(7)		0.2	%
TransAtlantic Petroleum Corp(8) 1550, 340 — 12th Avenue, SW Calgary, Alberta T2R 1L5		2,237,136	(9)		4.2	%(10)
All Directors and officers as a group (4 persons)		7,558,341			14.3	%

(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 52,997,673 shares outstanding as of May 20, 2008, except as otherwise noted.
(4)	Includes 250,000 shares issuable at an exercise price of $0.45 on exercise of an option.
(5)	Includes 250,000 shares issuable at an exercise price of $0.45 on exercise of an option.
(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.
(7)	Includes 65,528 shares held by Mr. Campbell and 50,000 shares issuable on exercise of options at an exercise price of $0.68 per share.
(8)	TransAtlantic 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, Scott Larsen and Alan C. Moon.
(9)	Includes 2,237,136 shares held by TransAtlantic. Mr. Bayley, one of our Directors, is also a Director of TransAtlantic and also disclaims a beneficial interest in the Debentures and shares.
(10)	The percentage of outstanding shares calculation is based upon 52,997,673 shares outstanding as of May 20, 2008.

51

Dune Energy Debenture Holdings

          Dune Energy holds, as of December 31, 2007, $7,895,000 principal amount as of our 8% Convertible Subordinated Debentures December 31, 2007 which are secured by substantially all of our assets. The principal of the Debentures was due and payable on September 30, 2006 and is currently in default. In a Schedule 13D filing by Dune Energy with the U.S. Securities and Exchange Commission, Dune Energy stated, “Given Dune Energy’s past investment in this joint development project, coupled with the potential for substantial oil and gas within the area of mutual interest, Dune Energy has determined that it is in its best interests to acquire the Purchased Debentures and the corresponding security interest in the Lease.” Dune Energy further disclosed in the Schedule 13D that, “except for the foregoing, neither it nor any control person of it has any plan or proposal which relates to or which would have the effect of any acquisition of additional, or disposition of any, securities of ours, does not have any plan or proposal which relates to or would result in an extraordinary transaction involving us, does not have any plan or proposal which relates to or would result in a sale or transfer of a material amount of our assets, does not have any plan or proposal which relates to or would result in any change in our present board of directors or management, including any plans or proposals to change the number or term of directors or to fill any existing vacancies on the board, does not have any plan or proposal which relates to or would result in a material change in our present capitalization or dividend policy...” Dune Energy further disclosed that it does not have any plan or proposal which relates to or would result in a material change in our business or corporate structure, does not have any plan or proposal which relates to or would result in a change in our charter, by-laws or instruments corresponding thereto which may impede the acquisition of us by any person, does not have any plan or proposal which relates to or would result in causing a class of our securities to be de-listed from a national securities exchange or to cease to be authorized to be quoted in an inter-dealer quotation system of a registered national securities association, and does not have any plan or proposal which relates to or would result in a class of our equity securities becoming eligible for termination or registration pursuant to Section 12(g)(4) of the Securities Exchange Act of 1934, as amended.

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 8 to the Notes to Financial Statements for further information on the material terms of this plan.

     The following table provides information as of December 31, 2007 with respect to our compensation plans (including individual compensation arrangements), under which securities are authorized for issuance aggregated as to (i) compensation plans previously approved by stockholders, and (ii) compensation plans not previously approved by stockholders:

Equity Compensation Plan Information

52

	(a)		(b)		(c)
					Number of securities
	Number of securities				remaining available
	to be issued upon				for future issuance
	exercise of				under equity
	outstanding		Weighted-average		compensation plans
	options, warrants		exercise price of		(excluding securities
	and		outstanding options,		reflected in column
Plan Category	rights		warrants and rights		(a))
Equity compensation plans approved by security holders		1,050,000	$	0.46		3,950,000
Equity compensation plans not approved by security holders		-0-		-0-		-0-
Total		1,050,000	$	0.46		3,950,000

53

Item 12 — Certain Relationships and Related Transactions:

On May 4, 2006, we entered into a note payable with Mike Paulk, our President and a Director, in the amount of $198,000. On August 9, 2006, Mr. Paulk loaned us an additional $10,000. In November 2006, $12,000 was repaid. Interest accrues at the rate of 10% per annum.

We paid Mr. Paulk $21,885 in interest in 2007 on the loans provided to us.

Item 13 — Exhibits:

Exhibit	Description
2.0	Second Amended Joint Plan of Reorganization Proposed by Couba Operating Company, American Natural Energy Corporation and Gothic Resources Inc. filed in the United States Bankruptcy Court, Western District of Oklahoma. Case No. 00-11837-W (Chapter 11)(4)
2.1	Order Confirming Plan, filed November 16, 2001 with U.S. Bankruptcy Court, Western District of Oklahoma(1)
3.1	Certificate of Incorporation of American Natural Energy Corporation(1)
3.2	Certificate of Amendment filed March 23, 2001(1)
3.3	Certificate of Amendment filed December 20, 2001(1)
3.4	Amended Certificate of Incorporation filed June 30, 2005.(5)
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)

54

Exhibit	Description
10.5.3	Trust Indenture (Amended and Restated as of June 29, 2005) between the Registrant and Computershare Trust Company of Canada.(6)
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)
10.7	Letter Agreement between the Registrant and Dune Energy, Inc.(7)
10.7.1	Consent accepted September 12, 2005 received from ExxonMobil Production Corporation pertaining to Letter Agreement between the Registrant and Dune Energy, Inc.(7)
10.7.2	Exploration and Development Agreement between the Registrant and Dune Energy, Inc.(8)
10.8	Participation Agreement dated March 8, 2006 between the Registrant and Seismic Exchange, Inc.(9)
14.1	Code of Ethics(4)
21.0	Subsidiaries of the Registrant as of December 31, 2005:

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

31.1	Certification of President and Chief Executive Officer Pursuant to Rule 13a-14(a)(10)
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)(10)
32.1	Certification of President and Chief Executive Officer Pursuant to Section 1350 (furnished, not filed)(10)
32.2	Certification of Chief Financial Officer Pursuant to Section 1350 (furnished, not filed)(10)

(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).

55

(4)	Filed with the Registrant’s Annual Report on Form 10-KSB for the year ended December 31, 2003.
(5)	Filed as an Exhibit to the Registrant’s Quarterly Report on Form 10-QSB for the quarterly period ended June 30, 2005.
(6)	Filed as an Exhibit to the Registrant’s Current Report on Form 8-K for June 29, 2005.
(7)	Filed as an Exhibit to the Registrant’s Quarterly Report on Form 10-QSB for the quarterly period ended September 30, 2005.
(8)	Filed as an Exhibit to the Registrant’s Current Report on Form 8-K for October 19, 2005.
(9)	Filed as an Exhibit to the Registrant’s Current Report on Form 8-K for March 8, 2006.
(10)	Filed with this Annual Report on Form 10-KSB for the year ended December 31, 2005.

Item 14. Principal Accountant Fees and Services

          The following sets forth fees we incurred for services provided by Malone & Bailey, PC for the years ended December 31, 2007, and 2006, our independent registered public accountants at those year ends. Also included are fees we incurred for services provided by PricewaterhouseCoopers LLP for the review of December 31, 2005 financial results included in the annual filing for the year ended December 31, 2006.

			Audit Related
	Audit Fees		Fees		Tax Fees
2007	$	46,000		—	$	26,000
2006	$	110,000		—	$	35,000

          Our Board of Directors believes that the provision of the services during the years ended December 31, 2007 and December 31, 2006 is compatible with maintaining the independence of Malone & Bailey, PC. 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 Malone & Bailey, PC and PricewaterhouseCoopers LLP included under the caption Audit Fees include 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 by PricewaterhouseCoopers LLP related to Canadian tax matters.

56

American Natural Energy Corporation

Consolidated Financial Statements
December 31, 2007 and 2006

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of American Natural Energy Corporation
Tulsa, Oklahoma

We have audited the accompanying consolidated balance sheets of American Natural Energy Corporation (the Company), and the related consolidated statements of operations and other Comprehensive Income, stockholders’ deficit, and cash flows for years ended December 31, 2007 and 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for purposes of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of American Natural Energy Corporation at December 31, 2007 and 2006, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

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 2007 and 2006, has a working capital deficiency and an accumulated deficit at December 31, 2007 and is in default with respect to certain debenture obligations. 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.

/s/ Malone & Bailey, PC
Houston, Texas
www.malone-bailey.com
May 20, 2008

F-2

AMERICAN NATURAL ENERGY CORPORATION
Consolidated Balance Sheets

	December 31,			December 31,
	2007			2006
	$			$
ASSETS
Current assets:
Cash and cash equivalents		136,856			491
Accounts receivable — joint interest billing, net of allowance for doubtful accounts of $26,195 in 2007		8,822			427,736
Accounts receivable — oil and gas sales		48,794			555,453
Prepaid expenses and other		67,722			98,593
Oil inventory		12,273			9,004
Total current assets		274,467			1,091,277
Proved oil and gas properties using the full cost method, net of accumulated depletion, depreciation, amortization and impairment of $20,087,252 and $19,809,614 respectively		2,819,355			3,016,913
Unproved oil and gas properties		9,095			3,430,582
Equipment and other fixed assets, net of accumulated depreciation of $764,931 and $659,025		523,551			452,005
Deposits		—			20,000
Total assets		3,626,468			8,010,777
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current liabilities:
Accounts payable and accrued liabilities		2,066,376			3,201,002
Revenues payable		3,347,371			4,767,006
Accrued interest		1,533,229			705,153
Insurance note payable		17,700			40,491
Notes payable (Note 7)		75,217			1,107,628
Note payable — related party (Note 10)		195,850			195,850
Asset retirement obligation (Note 6)		—			451,740
Taxes due on dissolution of subsidiary (Note 9)		190,252			302,870
Convertible secured debentures (Note 7)		10,825,000			10,825,000
Other current liabilities		113,785			364,007
Total current liabilities		18,364,780			21,960,747
Asset retirement obligation (Note 6)		1,753,110			1,288,795
Total liabilities		20,117,890			23,249,542
Commitments and contingencies (Notes 9 and 12)
Stockholders’ deficit:
Common stock
Authorized — 250,000,000 shares with par value of $0.001 Issued and outstanding — 52,997,673 shares		52,997			52,997
Additional paid-in capital		20,321,226			20,321,226
Accumulated deficit, since January 1, 2002 (in conjunction with the quasi- reorganization stated capital was reduced by an accumulated deficit of $2,015,495)		(41,151,844	)		(37,922,798	)
Accumulated other comprehensive income		4,286,199			2,309,810
Total stockholders’ deficit		(16,491,422	)		(15,238,765	)
Total liabilities and stockholders’ deficit		3,626,468			8,010,777

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

F-3

AMERICAN NATURAL ENERGY CORPORATION
Consolidated Statements of Operations and Other Comprehensive Income

	December 31, 2007			December 31, 2006
	$			$
Revenues:
Oil and gas sales		1,219,461			1,622,252
Operations income		132,104			160,900
Interest income and other income		1,324			56
		1,352,889			1,783,208
Expenses:
Lease operating expense		470,730			345,854
Production taxes		102,968			103,111
General and administrative		1,227,298			1,596,639
Foreign exchange loss		1,976,389			46,379
Interest and bank charges		991,711			1,260,704
Related party interest		21,885			13,426
Depreciation, depletion, and amortization — oil and gas properties		277,319			457,519
Accretion of asset retirement obligation		164,445			180,585
Depreciation and amortization — other assets		159,655			338,587
Gain on settlement of debt		(836,660	)		(108,087	)
Doubtful accounts expense		26,195			—
Total expenses		4,581,935			4,234,717
Net loss		(3,229,046	)		(2,451,509	)
Other comprehensive income— net of tax:
Foreign exchange translation		1,976,389			46,379
Other comprehensive income		1,976,389			46,379
Comprehensive loss		(1,252,657	)		(2,405,130	)
Net loss per share — basic and diluted		(0.06	)		(0.05	)
Weighted average number of shares outstanding — basic and diluted		52,997,673			51,884,888

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

F-4

AMERICAN NATURAL ENERGY CORPORATION
Consolidated Statements of Changes in Stockholders’ Deficit

										Accumu-
										lated
										Other		Total
					Additional		Accumu-			compre-		stock-
	Common stock				paid-in		lated			hensive		holders’
	Shares		Amount		capital		Deficit			income		deficit
			$		$		$			$		$
Balance — December 31, 2005		50,664,342		50,664		19,973,090		(35,471,289	)		2,263,431		(13,184,104	)
Stock issued on conversion of debentures		2,333,331		2,333		347,667		—			—		350,000
Stock option compensation expense		—		—		469		—			—		469
Foreign exchange translation gain		—		—		—		—			46,379		46,379
Net loss (total comprehensive loss of $2,405,130)		—		—		—		(2,451,509	)		—		(2,451,509	)
Balance — December 31, 2006		52,997,673		52,997		20,321,226		(37,922,798	)		2,309,810		(15,238,765	)

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

F-5

AMERICAN NATURAL ENERGY CORPORATION
Consolidated Statements of Changes in Stockholders’ Deficit (cont.)

										Accumu-
										lated
										Other		Total
					Additional		Accumu-			compre-		stock-
	Common stock				paid-in		lated			hensive		holders’
	Shares		Amount		capital		Deficit			income		deficit
			$		$		$			$		$
Balance — December 31, 2006		52,997,673		52,997		20,321,226		(37,922,798	)		2,309,810		(15,238,765	)
Foreign exchange translation gain		—		—		—		—			1,976,389		1,976,389
Net loss (total comprehensive loss of $1,252,657)		—		—		—		(3,229,046	)		—		(3,229,046	)
Balance — December 31, 2007		52,997,673		52,997		20,321,226		(41,151,844	)		4,286,199		(16,491,422	)

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

F-6

AMERICAN NATURAL ENERGY CORPORATION
Consolidated Statements of Cash Flows

	December 31, 2007			December 31, 2006
	$			$
Cash flows from operating activities:
Net loss		(3,229,046	)		(2,451,509	)
Non cash items:
Depreciation, depletion and amortization		436,974			796,106
Accretion of asset retirement obligation		164,445			180,585
Foreign exchange loss		1,976,389			46,379
Gain on settlement of notes payable		(836,660	)		—
Amortization of discount on convertible secured debentures		—			205,169
Doubtful accounts expense		26,195			—
Non-cash compensation expense		—			469
Changes in non-cash working capital items:
Accounts receivable		632,840			26,535
Oil inventory		(2,950	)		597
Prepaid expenses		28,246			112,012
Accounts payable, revenues payable and accrued Liabilities		(1,014,434	)		2,783,243
Net cash provided by (used) in operating activities		(1,818,001	)		1,699,586
Cash flows from investing activities:
Purchase and development of oil and gas properties		(310,462	)		(1,500,813	)
Purchase of equipment and other fixed assets		(252,702	)		(8,998	)
Proceeds from sale of fixed assets		21,500			—
Proceeds from sale of participation rights		2,946,418			162,500
Net cash provided by (used) in investing activities		1,404,754			(1,347,311	)
Cash flows from financing activities:
Issuance of notes payable		—			220,601
Payments of notes payable		(443,660	)		(697,760	)
Change in bank overdrafts outstanding		(6,728	)		(59,893	)
Net cash used in financing activities		(450,388	)		(537,052	)
Effect of exchange rate changes on cash		—			—
Increase (decrease) in cash and cash equivalents		136,365			(184,777	)
Cash and cash equivalents beginning of period		491			185,268
Cash and cash equivalents end of period		136,856			491

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

F-7

AMERICAN NATURAL ENERGY CORPORATION
Consolidated Statements of Cash Flows (continued)

	December 31, 2007			December 31, 2006
	$			$
Supplemental disclosures:
Interest paid (net of amount capitalized)		117,078			342,954
Income taxes paid		—			—
Non cash financing and investing activities:
Principal amount of 8% debentures converted to common stock		—			350,000
Accounts payable refinanced as notes payable		—			339,850
Prepaid expenses financed		21,988			166,143
Change in accounts payable resulting from direct payment of obligation by third party		553,581			—
Change in accounts payable resulting from the purchase and development of oil and gas properties		(1,055,632	)		(350,092	)
ARO Liability-changes in estimates		151,870			—

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

F-8

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

1	Basis of presentation and summary of significant accounting policies
	Description of company
	American Natural Energy Corporation (“ANEC”) is an oil and natural gas exploration and production company engaged in the acquisition, exploration and development of oil and natural gas properties for the production of crude oil and natural gas. Our properties are located in Louisiana.
	ANEC, an Oklahoma corporation, was formed by amalgamation on July 9, 1991 under the Company Act (British Columbia) and was continued under the Canada Business Corporations Act on August 1, 1991. On January 22, 2002, Gothic Resources Inc. (“Gothic”) completed a plan of arrangement under Section 192 of the Canada Business Corporations Act with ANEC which was at the time a wholly-owned subsidiary of Gothic, whereby all of the shareholders of Gothic exchanged their common shares in the capital of Gothic for common shares in the capital of ANEC, Gothic became a wholly owned subsidiary of ANEC and the former shareholders of Gothic became shareholders of ANEC The plan of arrangement became effective February 8, 2002. The shares of Gothic are no longer listed on the Toronto Venture Exchange, Inc. and in their place, the shares of ANEC are 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.
	Consolidation
	The financial statements include the accounts of ANEC and its wholly-owned subsidiary Gothic (the “Company”). All significant intercompany accounts and transactions are eliminated in consolidation.
	The consolidated financial statements contained herein have been prepared in accordance with accounting principles generally accepted in the United States of America, which differ in certain respects from accounting principles generally accepted in Canada.
	Cash and cash equivalents
	Cash and cash equivalents consist of short-term, highly liquid investments with maturities of 90 days or less at time of acquisition. Cash and cash equivalents are deposited with two institutions and the balance at one institution does exceed the federally insured limits at December 31, 2007 by $34,000. While balances may periodically exceed the federal depository insurance limit, the Company has not experienced any losses on deposits.
	Oil and natural gas properties
	The Company follows the full cost method of accounting for oil and natural gas properties. The Company defers the costs of exploring for and developing oil and natural gas reserves until such time as proved reserves are attributed to the properties. At that time, the deferred

F-9

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

costs are amortized on a unit-of-production basis. Such costs include land acquisition costs, geological and geophysical costs, costs 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 $15.12 and $17.60 per equivalent bbl in 2007 and 2006, 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 an impairment to the carrying value of oil and gas properties. There was no impairment recorded in 2007 or 2006.

In certain instances, the Company may capitalize interest on the cost of unevaluated oil and natural gas properties excluded from amortization, based on the Company’s weighted average cost of borrowings used to finance the expenditures. For the years ended December 31, 2007 and 2006, the Company did not capitalize any interest to its unevaluated properties.

Unevaluated oil and natural gas properties are reviewed on an annual basis for impairment.

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.

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. The Company is, therefore, unable to estimate when these costs will be included in the amortization computation.

Equipment and other fixed assets

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

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

F-10

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

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.

Foreign exchange and currency translation

The Company’s functional and reporting currency is the U.S. dollar. Transactions denominated in foreign currencies are translated into U.S. dollars at exchange rates in effect on the date of the transactions. Exchange gains or losses on transactions are included in earnings. For Gothic, whose functional currency is the Canadian dollar, 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

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 natural gas 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. Imbalances at December 31, 2007 and 2006 were insignificant. 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”) and Texon L.P. of $1,199,893 and $1,525,194 in 2007 and 2006, respectively, accounted for 98% and 94% of total oil and gas sales. 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.

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.

Asset retirement obligations

Effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”). This statement applies to obligations associated with the retirement of tangible long-lived assets

F-11

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

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.

Income taxes

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

In July 2006, the FASB issued FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109. FIN 48 provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS 109, Accounting for Income Taxes. FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 did not have a material impact on the Company’s financial position, results of operations or cash flows.

Use of estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Significant areas requiring the use of estimates are assessing the recoverability of capitalized oil and natural gas property costs, oil and gas reserve estimates, asset retirement obligations and recoverability of deferred tax assets. Actual results could differ from those estimates.

Earnings (loss) per share

Basic earnings (loss) per share are computed by dividing net income or loss (the numerator) by the weighted average number of shares outstanding during the period (the denominator).

F-12

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

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, unless they are anti-dilutive. Due to losses in 2007 and 2006, options were excluded from the calculation of diluted earnings per share as they were anti-di1utive.

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 Company had other comprehensive income of $1,976,389 and $46,379 for the years ended December 31, 2007 and 2006, respectively, as a result of foreign exchange translation gains. As of December 31, 2007 and 2006, accumulated other comprehensive income was comprised solely of foreign currency translation gains.

Stock-based compensation

On January 1, 2006, the Company adopted FAS 123(R), which requires companies to measure the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. The Company has elected to use the modified prospective application method such that FAS 123(R) applies to new awards, the unvested portion of existing awards and to awards modified, repurchased or canceled after the effective date. The Company also has equity incentive plans that provide for the issuance of stock options.

Prior to January 1, 2006, the Company accounted for its long-term equity incentive plans under the intrinsic value method described in APB Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretation. The Company, applying the intrinsic value method, did not record stock-based compensation cost for stock options issued to employees and directors because the exercise price of the stock options equaled the market price of the underlying stock at the date of grant.

For the twelve months ended December 31, 2006, the Company recognized compensation costs of $469 related to stock options issued prior to January 1, 2006. There is no unrecognized compensation costs related to stock options not yet vested as all stock options are vested at December 31, 2007.

There was no stock option activity for the years 2007 or 2006. At December 31, 2007, there were 1,050,000 options outstanding and exercisable with a weighted average exercise price of $0.46. The weighted average remaining contractual term for these options at December 31, 2007 was 1.33 years. These options had no intrinsic value at December 31, 2007.

F-13

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

	New pronouncements
	In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is currently assessing the impact, if any, SFAS 157 will have on its financial position, results of operations or cash flows.
	Reclassification of Prior Period Statements
	Certain reclassifications of prior period financial statements balances have been made to conform to current reporting practices.
2	Going Concern
	The Company has no current borrowing capacity with any lender. The Company has sustained substantial losses in 2007 and 2006, totalling approximately $3.2 and $2.5 million, respectively, has a working capital deficiency and an accumulated deficit at December 31, 2007 and 2006, and is in default of the payment terms of its 8% convertible secured debentures as further discussed below, all of 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 and repay borrowings as well as to meet its other current liabilities.
	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 Company’s 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. 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 or participation with industry partners. Certain covenants included in the 8% convertible secured debentures limit the amount of additional indebtedness the Company can incur to $2 million. As of May 19, 2008, the Debentures have not been repaid or refinanced and are in default. It is management’s intention to raise additional debt or equity financing to either repay or refinance these debentures and to fund its operations and capital expenditures. Failure to obtain additional financing can be expected to adversely affect the Company’s ability to pay its obligations, further the development of its properties, including the ExxonMobil Corp. area of mutual interest (the “AMI”), grow revenues, oil and gas reserves and achieve and maintain a significant level of revenues, cash flows, and profitability. There can be no

F-14

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

	assurance that the Company will obtain additional financing at the time required, at rates that are favorable to the Company, or at all. Further, any additional equity financing that is obtained may result in material dilution to the current holders of common stock.
3	Joint Development Agreement
	On November 25, 2002, the Company entered into a Joint Development Agreement with ExxonMobil Corp. whereby the Company gave ExxonMobil Corp. 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 Corp., up to 50% of the total interest. Each party will pay their respective share of exploration and development costs. The original agreement was supposed to terminate in 4 years and covered approximately 8,427 acres. On December 19, 2003, the Company entered into a letter agreement with ExxonMobil Corp. covering a proposed expansion of the lands covered by the agreement and an extension of the termination date of the agreement (the “Expansion Agreement”). The Expansion Agreement added a total of 2,560 acres to the lands covered by the agreement and extended the term by one year to November 2007.
	On March 8, 2006, the Company agreed to participate in a 3D seismic survey. Upon the completion of the survey and seismic interpretation, ExxonMobil Corp. and the Company agreed to formally extend their Joint Development Agreement by two years to November 2009.
4	Exploration and development agreement
	On October 19, 2005 the Company executed the definitive Exploration and Development Agreement (the “Agreement”) with Dune Energy, Inc. (“Dune Energy”), providing for the creation of an area of mutual interest covering an area of approximately 31,367 acres. Pursuant to the terms of the Agreement, Dune Energy agreed to pay to the Company a prospect fee in the amount of $1.0 million, of which $225,000 was paid on September 14, 2005, $225,000 was paid on September 30, 2005, $225,000 was paid on October 19, 2005, $162,500 was paid on November 30, 2005 and $162,500 was paid on January 10, 2006. These amounts reduced the Company’s unproved oil and gas properties. In the event the Company and Dune Energy elect to complete the first two exploratory wells drilled pursuant to the Agreement, upon the receipt by Dune Energy of a log from either of those two wells, Dune Energy agreed to pay to the Company an additional prospect fee of $500,000. The terms of the Agreement were amended September 14, 2006 to waive the additional prospect fee in exchange for Dune Energy paying 100% of the costs of expanded 3D seismic survey over the Bayou Couba area discussed above.
	The area of mutual interest created by the Agreement, in which the Company and Dune Energy have agreed to share all rights, title and interest owned or acquired on an equal basis, includes the Company’s Bayou Couba lease acreage of approximately 1,319 acres, the acreage covered by the Company’s Joint Development Agreement with ExxonMobil Corporation (“ExxonMobil”) of approximately 11,486 acres, as well as any additional acreage offered to the Company or Dune Energy by ExxonMobil as the result of the acquisition of additional 3D seismic data by the parties under the terms of the Agreement. If either party acquires any interests in lands included in the area of mutual interest created by

F-15

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

	the Agreement, the acquiring party is required to notify the non-acquiring party which will have the opportunity to participate in the acquisition by paying its proportionate share of the price for such properties. On June 26, 2007 Dune Energy increased its participation to 75% of the Company’s interest under these agreements, excluding the area under the Bayou Couba lease itself where it retains a participation of 50% of the Company’s interest, with the payment of $3 million. On September 1, 2007 Dune Energy was elected successor operator under the joint development agreement and Dune Energy paid the Company an additional $500,000. These payments reduced the Company’s unproved oil and gas properties.
	The Agreement provides that either party can propose drilling prospects with the non-proposing party given the right to participate in the drilling prospect and pay its proportionate share of all drilling and completion costs. Dune Energy is presently the operator of each drilling prospect and completed well, subject to the rights of ExxonMobil and the Company under the joint development agreement.
	The Agreement will remain in effect so long as the Company’s Joint Development Agreement with ExxonMobil remains in effect. The Agreement excludes certain specified existing wells of the Company, certain litigation rights of the Company, and the Company’s production facility and equipment and personal property. The Company’s interest in the area of mutual interest created by the Agreement is subject to the terms of other agreements to which the Company is a party.
5	Equipment and other fixed assets
	The carrying value of equipment and other fixed assets as of December 31, 2007 and 2006 included the following components:

	2007			2006
	$			$
Computer and office furniture and equipment		163,060			163,060
Leasehold improvements		5,520			5,520
Barges and field equipment		739,748			734,748
Gas gathering and production facility expansion		380,154			207,702
		1,288,482			1,111,030
Less: Accumulated depreciation		(764,931	)		(659,025	)
		523,551			452,005

F-16

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

6	Asset retirement obligations
	The Company’s asset retirement obligations relate to plugging and abandonment of oil and gas properties. The components of the change in the Company’s asset retirement obligations for the years ended December 31, 2007 and 2006 are shown below.

	For the years ended December 31,
	2007			2006
	$			$
Asset retirement obligations, January 1		1,740,535			1,548,647
Additions and revisions		(151,870	)		11,303
Settlements and disposals		—			—
Accretion expense		164,445			180,585
Asset retirement obligations, December 31		1,753,110			1,740,535

7	Notes payable and long-term debt
	Notes payable and long-term debt as of December 31, 2007 and 2006 consisted of the following:

	2007			2006
	$			$
Accounts payable refinanced as notes payable		75,217			1,007,628
Note payable — Officer of Company (Note 10)		195,850			195,850
Note payable — Citizens Bank of Oklahoma		—			100,000
8% Convertible secured debentures		10,825,000			10,825,000
Total notes payable and long-term debt		11,096,067			12,128,478
Less: Current portion		(11,096,067	)		(12,128,478	)
Total notes payable and long-term debt, net of current portion		—			—

8% Convertible secured debentures

On October 21, 2003 and October 31, 2003, the Company completed financing transactions of $11.695 million and $305,000, respectively, by issuing Convertible Secured Debentures (the “Debentures”). The Debentures were 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

F-17

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

per share, subject to antidilution adjustment, and the Debentures are redeemable by the Company at any time after October 1, 2004 if the weighted average price per share on the TSX Venture Exchange for a 20 consecutive trading day period prior to the date notice of redemption is given has exceeded 166 2/3% 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 Debentures are collateralized by substantially all of the Company’s assets. The Debentures have covenants limiting unsecured borrowings to $2 million and restricting the payment of dividends and capital distributions.

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%.

In June 2005, the Debentures were amended with approval by approximately 86% of the Debenture holders. The amendments extended the maturity date of the Debentures by one year to September 30, 2006, reduced through the maturity date of the Debentures the per share price at which the principal of the Debentures could be converted into shares of Common Stock to $0.15 per share, and provided for the partial release of the lien collateralizing the Debentures in the event a third party entered into an agreement with the Company pursuant to which the third party is granted the right to drill one or more wells on Company properties and commenced that drilling activity. On June 23, 2005, stockholders of the Company voted to amend the Certificate of Incorporation to increase the number of shares of Common Stock of the Company from 100 million to 250 million and adjust par value from $0.01 to $0.001 per share. This increase in authorized shares, along with the approval of the TSX Venture Exchange to the transactions, provided final approval of the Debenture amendments. Under the amendments, 72,166,667 shares were issuable upon full conversion of the Debentures at the reduced conversion price; however the conversion rights expired on September 29, 2006 and were not renewed.

The amendments to the Debentures resulted in the extinguishment of debt and recognition of a loss of $1,147,000. As a result of the extinguishment and recognition of loss, these Debentures were recorded at their fair market value on June 23, 2005 reflecting the present value of future cash flows and the option value of the underlying convertible shares.

The Company failed to meet any of the interest payments due quarterly from June 30, 2006 through May 19, 2008 on its outstanding Debentures. In addition, the Company failed to repay or redeem the Debentures by the due date of September 30, 2006 and as of May 19, 2008 the Debentures are still outstanding. Accordingly, pursuant to the Indenture governing the Debentures, an Event of Default resulting from the Company’s failure to timely pay interest due on June 30, 2006, occurred and is continuing at this time. Under those circumstances, the Trustee may, and upon request in writing from the holders of not less than 25% of the principal amount of the Debentures then outstanding, shall, declare the outstanding principal of and all interest on the Debentures and other moneys outstanding under the Indenture to be immediately due and payable. In addition, the Trustee will have the right to enforce its rights on behalf of the Debenture holders against the collateral for the Debentures. The Debentures are collateralized by substantially all of the Company’s assets. The principal amount of the Debentures outstanding at December 31, 2007 was $10,825,000

F-18

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

	and accrued and unpaid interest at that date amounts to $1,515,000. Subsequent to June 30, 2006 through May 19, 2008, neither the Trustee nor the requisite holders of principal amount of Debentures have declared the Debentures to be immediately due and payable and the Company remains in default under the interest and repayment terms of its Debentures.
	During 2007, Dune Energy acquired from the Debenture holders $4,895,000 principal amount of Debentures, bringing Dune Energy’s total holdings of our Debentures outstanding to $7,895,000 principal amount as of December 31, 2007.
	Notes payable
	On February 2, 2005, the Company entered into a $100,000 unsecured short-term note with a NYP floating interest rate with Citizens Bank of Oklahoma. The note and interest were paid in full on July 6, 2007.
	On August 24, 2005, the Company entered into a note payable with Parker Drilling Company for $507,000, which included the conversion of an accounts payable balance of $486,000 due to Parker Drilling Company. Monthly payments of $25,000 which include interest at the rate of 7% per annum were to be made through June 2007. On July 9, 2007 the Company and Parker Drilling Company entered into a settlement agreement whereby the Company paid $50,000 in full satisfaction of the outstanding note payable to Parker Drilling Company of $395,000 resulting in a gain on extinguishment of $345,000.
	On November 16, 2005, the Company agreed to convert its $420,000 accounts payable balance to Ambar Drilling Fluids to a note payable. Beginning November 16, 2005, interest accrued at 4% per annum with payment of principal balance and interest due on or before May 16, 2006. On July 17, 2007 the Company and Ambar Drilling Fluids entered into a settlement agreement whereby the Company paid $112,000 in full satisfaction of the outstanding note payable to Ambar Drilling Fluids, resulting in a gain on extinguishment of $310,000.
	On December 16, 2005, the Company converted its $99,000 accounts payable balance to Patterson Services to a note payable. Monthly payments of $8,710 which include interest at the rate of 10% per annum were to be made through December 2006. At May 19, 2008, nine payments were past due.
	On October 4, 2006, the Company converted its $139,000 accounts payable balance to Landmark Graphics to a note payable. Payments include interest at the rate of 15% per annum. This note was paid in full on December 20, 2007.
	On October 30, 2007, the Company entered into an agreement to finance its insurance premiums totaling $22,000. This note is subject to monthly payments, which include interest at the rate of 7.5% per annum.
8	Capital stock
	Options

F-19

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

The Company adopted the 2001 Stock Incentive Plan during the year ended December 31, 2001. For options granted under the plan, the option price 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 will be set by the board at the time of issue of the option and cannot be more than 5 years after the grant date. The maximum number of shares that may be issued pursuant to options granted under the plan will be 5,000,000 shares or such additional amount as may be approved from time to time by the shareholders of the Company. The number of shares issuable to any one optionee under the plan cannot exceed 5% of the total number of issued and outstanding shares on a non-diluted basis. The number of shares that can be issued under the plan within a one year period, in aggregate, shall not exceed 20% of the then outstanding options issued under the plan and, to any optionee who is an insider, shall not exceed 5% of the then outstanding options issued under the plan.

Stock option activity for the years ended December 31, 2007 and 2006 is as follows:

				Weighted
				Average
	Number of			Exercise price
	Options			$
Outstanding — December 31, 2005		1,600,000			0.50
Expired		(300,000	)		0.62
Outstanding — December 31, 2006		1,300,000			0.49
Expired		(250,000	)		0.61
Outstanding — December 31, 2007		1,050,000			0.46

	Exercise prices of options outstanding at December 31, 2007 ranged from $0.45 to $0.68. At December 31, 2007 and 2006, 1,050,000 and 1,293,750 options have vested and are exercisable at a weighted average price of $0.46 and $0.49, respectively. The weighted average remaining contractual life of options granted at December 31, 2007 and 2006 is 16 and 27 months, respectively.
	The 2001 Stock Incentive Plan, as amended (approved by the shareholders in June 2005), 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 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.
9	Commitments and contingencies
	The Company rents office space under a long-term operating lease that expires July 2009. At December 31, 2007, the future minimum lease payments required under the operating

F-20

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

lease amounted to $136,000 of which $86,000 is to be paid in 2008, and $50,000 is to be paid in 2009.

Rent expense on all operating leases amounted to approximately $96,000 and $101,000 in 2007 and 2006, respectively.

With respect to the acquisition of the Company’s Bayou Couba lease acreage, 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 plus interest accruing at 8% per annum commencing January 1, 2002, and 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, excluding, however, the Bayou Couba Lease. Upon payment of their allowed claims, inclusive of interest, such royalty and net profits interests is eliminated. 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 the Company 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 with Dune Energy, including payments made by the Company 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 the Company directly from Couba at the time of confirmation and as a result of the plan of reorganization of Couba, and a 25% interest in the Company’s interest in the 23.5 square mile area of mutual interest held by the Company on the effective date of the plan

On January 31, 2005, the Company made application with applicable Canadian authorities to dissolve and terminate Gothic Resources Inc. (“Gothic”). In conjunction with the application for dissolution, the prior tax returns and tax status of Gothic have been reviewed by the Canada Customs and Revenue Agency (“CRA”). The CRA has assessed Gothic $190,000 (Cdn$187,000) in additional taxes and interest based on the review of such returns. At December 31, 2006, the Company had accrued $302,000 for this potential exposure and the corresponding difference of $112,000 reduced selling, general and administrative expense for the periods ended December 31, 2007.

The Company, as an owner or lessee of oil and gas properties, is subject to various federal, states and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations, may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks.

F-21

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

	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.
10	Related party transactions
	On May 4, 2006, the Company entered into a note payable with Mike Paulk, an officer of the Company, in the amount of $198,000. On August 9, 2006 Mike Paulk loaned an additional $10,000 to the Company. In November 2006, $12,000 was repaid. Interest accrues at the rate of 10% per annum. Note payable was due May 31, 2007, after that date is due on demand.
	The Company paid Mike Paulk $21,885 in interest in 2007 on the loans provided to the Company.
11	Income taxes
	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, 2007 and 2006 are presented below:

	2007			2006
	$			$
Deferred tax assets
Asset retirement costs		665,481			660,707
Foreign exchange loss		1,168,510			418,273
Acquisition, exploration and development costs and related depreciation, depletion and amortization		7,210,046			7,107,758
Contribution carryovers		3,162			3,162
Change in accounting principle		123,894			123,894
Net operating loss carryforwards		6,123,450			6,885,024
Deferred tax asset		15,294,543			15,198,819
Less: Valuation allowance		(15,294,543	)		(15,198,819	)
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, 2007 and 2006 are summarized as follows:

F-22

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

	2007			2006
	$			$
Federal tax benefit at statutory rate		1,097,876			953,170
State taxes, net of federal taxes		114,567			125,261
Other		(4,941	)		122,306
Less: valuation allowance		(1,207,502	)		(1,200,737	)
Total provision for income taxes		—			—

	As of December 31, 2007, the Company has a net operating loss carry-forward of approximately $17,711,408 which is available to reduce future taxable income, if any, through 2028. 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. If certain substantial changes in the Company’s ownership should occur, there would be an annual limitation on the amount of the carry-forward which can be utilized.
12	Subsequent Events
	On January 29, 2008, the Company entered into a settlement with Canary Wellhead Equipment whereby the Company settled outstanding invoices and costs of $49,000 with a one time payment of $10,000. The entire amount was unpaid at December 31, 2007.
13	Disclosures About Oil and Gas Producing Activities (Unaudited)
	Net Capitalized Costs
	The following summarizes net capitalized costs as of December 31, 2007 and 2006.

	2007			2006
	$			$
Oil and gas properties
Proved		22,906,607			22,826,527
Unproved		9,095			3,430,582
Total		22,915,702			26,257,109
Less accumulated depreciation, depletion and amortization and impairment		(20,087,252	)		(19,809,614	)
Net capitalized costs		2,828,450			6,447,495

F-23

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

Unproved Property Costs

The following summarizes the capitalized unproved property costs excluded from amortization as of December 31, 2007. All costs represent investment in unproved property in Louisiana and will be evaluated over several years as the properties are explored. Property acquisition costs of $78,513 and $314,825 at December 31, 2007 and 2006 respectively, have been reduced by $3.5 million received from the sale of participation rights to Dune Energy and $162,500 for a prospect fee received from Dune Energy as of December 31, 2007 and 2006 respectively. (See Note 4).

	2007			2006		Prior Years		Total
	$			$		$		$
Property acquisition costs		(3,421,487	)		152,325		1,849,047		(1,420,115	)
Capitalized interest		—			—		1,429,210		1,429,210
		(3,421,487	)		152,325		3,278,257		9,095

Costs Incurred in Oil and Gas Acquisition, Exploration and Development

	2007		2006
	$		$
Development costs		231,949		988,221
Exploration costs		—		—
Acquisition costs
Proved		—		—
Unproved		—		—
		231,949		988,221

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 2007 and 2006. The following table includes revenues and expenses associated directly with the Company’s oil and gas producing activities. It does not include any general and administrative costs or any interest costs.

F-24

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

	2007			2006
	$			$
Oil and gas sales		1,219,461			1,622,252
Operations income		132,104			160,900
Lease operating expenses		(470,730	)		(345,854	)
Production taxes		(102,968	)		(103,111	)
Depreciation, depletion and amortization		(441,764	)		(638,104	)
Results of operations from oil and gas activities, excluding corporate overhead and interest costs		336,103			696,083

Oil and Gas Reserve Quantities (unaudited)

The reserve information presented below is based on reports prepared by independent petroleum engineers Summa Engineering, 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. All of the Company’s oil and natural gas producing activities are located in the United States of America.

     December 31, 2007

	Oil			Gas			Total
	(Mbbl)			(Mmcf)			(Mbble)
Proved reserves, beginning of period		328.84			1,386.93			560.00
Extensions, discoveries and other additions		—			—			—
Revisions of previous estimates		(15.66	)		(614.53	)		(118.08	)
Production		(16.54	)		(3.46	)		(17.12	)
Sale of reserves in place		—			—			—
Purchase of reserves in place		—			—			—
Proved reserves, end of period		296.64			768.94			424.80
Proved developed reserves:
Beginning of period		66.13			91.27			81.35
End of period		58.02			3.71			58.64

F-25

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

December 31, 2006

	Oil			Gas			Total
	(Mbbl)			(Mmcf)			(Mbble)
Proved reserves, beginning of period		316.93			1,856.15			626.28
Extensions, discoveries and other additions		9.17			.73			9.30
Revisions of previous estimates		26.25			(455.03	)		(49.59	)
Production		(23.51	)		(14.92	)		(25.99	)
Sale of reserves in place		—			—			—
Purchase of reserves in place		—			—			—
Proved reserves, end of period		328.84			1,386.93			560.00
Proved developed reserves:
Beginning of period		135.61			71.87			147.58
End of period		66.13			91.27			81.35

Standardized Measure of Discounted Future Net Cash Flows (unaudited)

Statement of Financial Accounting Standards No. 69, Disclosures About Oil and Gas Producing Activities, (“SFAS 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, 2007 and December 31, 2006 were $94.45 and $60.00 per barrel for oil and $6.83 and $5.23 per mcf 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.

F-26

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2007 and 2006

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:

	December 31,
	2007			2006
	$			$
Future cash inflows		33,269,026			27,528,968
Future development costs		(3,772,696	)		(6,470,310	)
Future production costs		(12,146,111	)		(7,635,562	)
Net future cash flows		17,350,219			12,885,032
Less effect of a 10% discount factor		(6,201,615	)		(5,399,242	)
Standardized measure of discounted future net cash flows		11,148,604			7,485,790

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

	December 31,
	2007			2006
	$			$
Standardized measure, beginning of period		7,485,790			16,949,441
Sales of oil and gas produced, net of production costs		(645,762	)		(1,173,287	)
Development costs incurred		246,853			—
Changes in future development costs		2,648,235			1,262,207
Revisions of previous quantity estimates		(3,411,393	)		(1,023,508	)
Net change due to extensions and discoveries		—			191,937
Net change in prices and production costs		3,066,348			(9,484,113	)
Changes in production rate		391,101			—
Accretion of discount		1,276,279			763,113
Other		91,153			—
Standardized measure, end of period		11,148,604			7,485,790

F-27

SIGNATURES

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

	American Natural Energy Corporation
By:	/s/ Michael K. Paulk
	Michael K. Paulk, President

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

Signature	Title	Date
/s/ Michael K. Paulk	President (Principal	May 22, 2008
Michael K. Paulk	Executive Officer) and Director
/s/ Steven P. Ensz	Director and Principal Financial	May 22, 2008
Steven P. Ensz	and Accounting Officer
/s/ Brian Bayley Brian Bayley	Director	May 22, 2008
/s/ John K. Campbell John K. Campbell	Director	May 22, 2008