American Natural Energy Corp - FORM 10-K

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - American Natural Energy Corp	exhibit32-2.htm
EX-99.1 - EXHIBIT 99.1 - American Natural Energy Corp	exhibit99-1.htm
EX-23.1 - EXHIBIT 23.1 - American Natural Energy Corp	exhibit23-1.htm
EX-31.1 - EXHIBIT 31.1 - American Natural Energy Corp	exhibit31-1.htm
EX-32.1 - EXHIBIT 32.1 - American Natural Energy Corp	exhibit32-1.htm
EX-31.2 - EXHIBIT 31.2 - American Natural Energy Corp	exhibit31-2.htm
EXCEL - IDEA: XBRL DOCUMENT - American Natural Energy Corp	Financial_Report.xls

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM 10-K

Mark One:

[X] Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
For the fiscal year ended December 31, 2011;

[ ] 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 2010, 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.

[ ]

Check whether the Issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past twelve (12) months (or for such shorter period that the Issuer was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

[X] Yes [ ] No

Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-K 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-K or any amendment to this Form 10-K. [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, Pursuant to Rule 12b-2 of the Exchange Act.

Large accelerated filer [ ]

Accelerated filer [ ]

Non-accelerated filer [ ]

Smaller reporting company [X]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes [ ] No [X]

State Issuer’s revenues for its most recent fiscal year: $1,998,836.

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 June 30, 2011: $2,402,185. (Non-affiliates have been determined on the basis of holdings set forth in Item 12 of this Annual Report on Form 10-K.)

The number of shares outstanding of each of the Issuer’s classes of common equity, as of March 30, 2012, was 18,928,895 shares of Common Stock.

DOCUMENTS INCORPORATED BY REFERENCE

None

Table of Contents

	Part I	Page
Item 1.	Description of Business	4
Item 1A	Risk Factors	16
Item 1B	Unresolved Staff Comments	23
Item 2.	Properties	23
Item 3.	Legal Proceedings	23
Item 4.	Submission of Matters to a Vote of Security Holders	23
	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
Item 6.	Selected Financial Data	25
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 8.	Consolidated Financial Statements and Supplementary Data	35
Item 9A.	Controls and Procedures	35
Item 9B.	Other Information	37
	Part III
Item 10.	Directors, Executive Officers And Corporate Governance	38
Item 11.	Executive Compensation	41
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	42
Item 13.	Certain Relationships and Related Transactions, Director Independence	45
Item 14.	Principal Accountant Fees and Services	45
Item 15.	Exhibits	45

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

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.

Through our ownership we hold interests in approximately 1,320 acres of land in St. Charles Parish, Louisiana. This acreage is the Bayou Couba leases in which we hold a 97.25% working interest in the leasehold and 97.25% working interest in all but 7 producing wells. The ownership results from our acquisition on December 31, 2001, of the assets and outstanding stock of Couba Operating Company (“Couba”) and consolidation of other working interests in the field during 2009. 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, 2011, we returned to production 9 (8.75 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, 2011, we had drilled and completed 12 (7.89 net) wells. For the year ended December 31, 2011, our combined production from all our producing wells (21 gross, 16.6 net) averaged approximately 84 (51 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 1,320 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.

The principal asset of Couba that we acquired was the Bayou Couba Lease. The lessor is ExxonMobil 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 Dune Energy Agreements. In September 2005, we entered into a participation agreement with Dune Energy, Inc. (“Dune Energy”). Pursuant to the agreement, Dune Energy acquired certain exploration and development rights within our Bayou Couba Properties area. On September 1, 2007 Dune Energy was elected successor operator under the Joint Operating Agreement.

On August 4, 2009 we completed the terms of a Purchase Agreement whereby we acquired all of Dune Energy’s interest in the producing properties on the Bayou Couba lease, all of the Dune Energy’s interest in the undeveloped leasehold from the surface to the top of the Cib Op formation and all of the outstanding Debentures held by Dune Energy. Additionally, we assumed operations of the field at that time. Dune Energy retained a 65% interest in the lease below the Cib Op formation.

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 was 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. The lease expired in January 2010.

Seismic Survey Participation Agreement. On March 8, 2006, we agreed to participate in a 3D seismic survey covering 60 square miles covering our Bayou Couba lease and surrounding acreage positions. The survey is part of a larger regional survey being conducted by Seismic Exchange, Inc. We received the survey data in 2008 and participated in a joint Pre-stack time migration processing of the data. We have completed Pre-stack depth migration processing of the data and continue to evaluate the deeper horizons of our Bayou Couba lease.

Oil and Gas Reserves

Reserves Estimation

We engaged a third-party engineering firm to prepare our reserve estimates comprising all of our estimated proved reserves (by volume) at December 31, 2011. Our Manager of Operations is the person primarily responsible for overseeing the preparation of the company’s reserve estimates. His qualifications include the following:

34 years of practical experience in geology, petroleum engineering and reserve evaluation
Bachelor of Science degree in Geology

We maintain internal controls such as the following to ensure the reliability of reserves estimations:

No employee’s compensation is tied to the amount of reserves booked.
We follow comprehensive SEC-compliant internal policies to determine and report proved reserves. Reserves estimates are made by experienced third-party reservoir engineers.
The Manager of Operations reviews all the company’s reported proved reserves at the close of each quarter.
Each quarter, the Manager of Operations and the Chief Executive Officer review all significant reserve changes and all new proved undeveloped reserves additions.

The tables below set forth information as of December 31, 2011 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. This report is included as Exhibit 99.1 to this Annual Report on Form 10-K. The qualifications of the technical person at each of these firms primarily responsible for overseeing his firm’s preparation of the company’s reserve estimates are set forth below.

Bachelor of Science Degree in Petroleum Engineering
Over 35 years of practical experience in petroleum engineering
A registered Professional Engineer in the State of Oklahoma

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	82.47	-	82.47
Proved developed non-producing	-	-	-
Proved undeveloped	1,931.44	315.90	1,984.09
Total proved	2,013.90	315.90	2,066.55

			Proved
		Proved	Developed
		Developed	Non-		Proved		Total
		Producing	producing		Undeveloped		Proved
Estimated future net revenue(a)	$	4,981,070	-	$	115,934,050	$	120,915,120
Present value of future net revenue(b)	$	3,531,670	-	$	70,690,012	$	74,221,682
Standardized measure of discounted future net cash flows	$	3,531,670	-	$	70,690,012	$	74,221,682

___________________________________
(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, 2011. 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 $93.69 per barrel of oil and $3.87 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, 2011 as there is no future income tax provision.

The future net revenue attributable to our estimated proved undeveloped reserves is calculated to be $115.9 million at December 31, 2011, with the present value thereof to be $70.7 million, based on us expending approximately $10.4 million during 2012 and an additional $6.0 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, 2011, the capital necessary to develop these additional reserves was unavailable to us. Through December 31, 2011, we had expended approximately $16.1 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, 2011, 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,
	2010			2011
		Gross	Net		Gross	Net
Development
Productive		0.0	0.0		0.0	0.0
Non- productive		-0-	-0-		-0-	-0-
Exploratory
Productive		-0-	-0-		-0-	-0-
Non- productive		-0-	-0-		-0-	-0-

During 2010, Behind Pipe Zones that were classified as Proved Undeveloped Reserves were re-completed at a cost of approximately $223,700 (1 well) and reclassified as Proved Developed Producing at December 31, 2010. Additional Proved Undeveloped Reserves will be drilled and completed as cash flow or funding from third party sources becomes available.

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.

During 2009 we acquired all of the working interest of Dune Energy as well as other small interest owners in the field. The acquisitions effectively added an additional 6.56 net wells to our ownership interest.

For the year ended December 31, 2010, combined production from all our producing wells on the property averaged approximately 162 (92 net) barrels of oil equivalents per day.

For the year ended December 31, 2011, combined production from all our producing wells on the property averaged approximately 84 (51 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.

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 years ended December 31, 2011 and 2010. All of our production was from our properties located in St. Charles Parish, Louisiana.

		Year Ended December 31,
		2011		2010
Net Production: ⁽¹⁾
Oil (Mbbl)		18.1		31.5
Natural Gas (Mmcf)		2.5		11.6
Oil Equivalent (Mbble )		18.5		33.4

Oil and Natural Gas Sales:⁽²⁾
Oil	$	1,937,607	$	2,464,419
Natural Gas	$	11,342	$	59,311
Total	$	1,948,949	$	2,523,730

Average Sales Price:
Oil ($per Bbl)	$	107.01	$	78.17
Natural Gas ($per Mcf)	$	4.50	$	5.12
Oil Equivalent ($per Bble)	$	105.19	$	75.43

Oil and Natural
Gas Costs:
Lease operating expenses	$	743,531	$	890,306
Production Taxes	$	57,955	$	132,552
Depreciation, depletion and amortization		487,491	$	884,027
Average production cost per unit of production ($ per Bble)	$	43.26	$	30.82

⁽¹⁾Includes only production owned by us and produced to our interest, less royalties and production due others. 403 and 426 barrels of oil were produced in December 2011 and 2010 but not sold until January 2012 and 2011, respectively, and are included in inventory at December 31, 2011 and 2010 at the lower of production cost and DD&A, or market.

Development, Exploration and Acquisition Expenditures

The following table sets forth certain information regarding the costs we incurred in our development, exploration and acquisition activities during the periods indicated:

		Year Ended		Year Ended
		December 31,		December 31,
		2011		2010
Development Costs	$	231,483	$	334,887
Exploration Costs		-		-
Acquisition Costs		226,847		-
Sales of Properties		-		-
Capitalized Interest		-		-

Total	$	458,330	$	334,887

Acreage

The following table sets forth as of December 31, 2011, the gross and net acres of both developed and undeveloped oil and natural gas leases which we hold. “Gross” acres are the total number of acres in which we own a working interest. “Net” acres refer to gross acres multiplied by our fractional working interest.

					Total Developed and
	Developed⁽¹⁾		Undeveloped⁽¹⁾		Undeveloped
Area	Gross	Net	Gross	Net	Gross	Net
Louisiana	1,319	1,284	-	-	1,319	1,284
Total	1,319	1,284	-	-	1,319	1,284

(1) Net acreage assumes that we maintain our existing working interest percentage in all future development.

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 2011, our oil sales to Sunoco, Inc (formerly Texon L.P.) of $1,937,606 accounted for 99% of our total oil and gas sales. We believe we are not materially dependent upon Sunoco for our sales as we believe there are numerous other purchasers for our oil and gas production at competitive prices. We believe that the loss of this customer 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 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, 2011, 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 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 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 water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under an EPA general permit. We believe that we are in material compliance with all permits we are required to obtain and obtaining such permits in the future will not have a material adverse impact on our operations in the future. With respect to our future operations, we believe we will be able to obtain, or be included under, such permits, where necessary. Compliance with such permits is not expected to have a material adverse effect on us.

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

Safe Drinking Water Act. Our operations may involve the disposal of produced saltwater and other non-hazardous oilfield wastes by re-injection into the subsurface. Under the Safe Drinking Water Act (“SDWA”), oil and gas operators, such as us, must obtain a permit for the construction and operation of underground Class II injection wells. To protect against contamination of drinking water, periodic mechanical integrity tests are often required to be performed by the well operator. While we expect to be able to obtain all such permits as are required, there can be no assurance that these requirements may not cause us to incur additional expenses.

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

Title To Properties

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

Operating Hazards and Insurance

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. While we believe our policies are customary in the industry, they do not provide complete coverage against all operating risks.

Employees

As of December 31, 2011, we employed seven persons, of whom two were executive officers and three 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.

Office

Our principal office is located at 6100 South Yale, Suite 2010, Tulsa, Oklahoma 74136. Additionally, we maintain office space in The Woodlands, Texas. Our leased premises include approximately 5,062 square feet and are leased for various terms expiring in 2012. The annual aggregate rental is $98,709. The facilities are considered adequate for our present activities.

Item 1A – 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 consolidated 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 recorded a net loss of $905,792 and $2,062,145 in 2011 and 2010, respectively. We had a working capital deficiency at December 31, 2011 of approximately $7.4 million. Our production from our drilling program decreased during 2011 compared to 2010, and our revenue has not been sufficient to fund our operations. At December 31, 2011, our current assets are $165,000 compared with current liabilities of $7.6 million which include accounts payable, revenues payable, notes payable, and other current obligations. We have substantial needs for funds to pay our outstanding payables and debt due during 2012. 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. 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 consolidated financial statements as of and for the year ended December 31, 2011 includes an explanatory paragraph which states that we have sustained a substantial loss in 2011 and have a working capital deficiency and an accumulated deficit at December 31, 2011 that raise substantial doubt about our ability to continue as a going concern.

Our Current Liabilities as of December 31, 2011 Exceed Our Current Assets by $7.4 Million.

As of December 31, 2011, our current assets were approximately $165,000 and our current liabilities were approximately $7.6 million. In order to meet our current obligations, we will need to raise additional capital. 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.

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;
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.

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.

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, 2011, based on the report of Summa Engineering, Inc., we claimed total estimated proved reserves of 2,013.90 Mbble of oil. Through December 31, 2011, we were able to return to production 9 (8.75 net) well bores drilled by prior owners on the Couba properties we acquired, and we had successfully completed 12 (7.89 net) wells. As of that time, our combined production from all our producing wells was approximately 84 (51 net) barrels of oil equivalent per day. Production from our existing wells is subject to fluctuation from time to time based upon the zones of the wells where we are obtaining production. There can be no assurance that we will be successful in our development activities or that as a consequence we will claim any material amounts of additional proven reserves as a result of these and further drilling activities. In any event, there are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control.

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

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

Our Reliance On a Limited Number of Key Management Personnel Imposes Risks On Us That We Will Have Insufficient Management Personnel Available If Their Services Are Unavailable.

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

Drilling For Oil and Natural Gas and Operating Oil and Natural Gas Fields Involves Material Risks Including the Risk That No Commercially Productive Reservoirs Will Be Encountered; We Have Uninsured Risks.

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

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

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 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 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 2012 and beyond, to differ materially from those expressed in any forward-looking statements made by or on our behalf.

Item 1B – Unresolved Staff Comments:

As of December 31, 2011, we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to year-end.

Item 2 - Properties:

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

Item 3 - Legal Proceedings:

We are defendants in a lawsuit brought by Dune Energy, Inc and Dune Operating Company alleging breach of contract and requesting a judgment in an amount of not less than $183,551 plus interest and attorney fees. The case is set for trial in January 2013.

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, 2011 to a vote of security holders through the solicitation of proxies or otherwise.

PART II

Item 5 - Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities:

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

The reported high and low sales prices, reported in United States dollars, for our common shares, as reported by the TSX Venture Exchange, on a calendar quarterly basis for the calendar year ended December 31, 2009 through March 29, 2012 were as follows.

	Prices⁽¹⁾
		High		Low	Share Volume⁽¹⁾
2010
First Quarter	$	0.60	$	0.30	513,282
Second Quarter	$	0.65	$	0.40	546,196
Third Quarter	$	0.45	$	0.30	545,626
Fourth Quarter	$	0.44	$	0.23	783,196
2011
First Quarter	$	0.38	$	0.22	508,026
Second Quarter	$	0.32	$	0.13	139,993
Third Quarter	$	0.24	$	0.10	305,870
Fourth Quarter	$	0.15	$	0.07	722,050

2012
First Quarter through March 21 , 2012	$	0.38	$	0.22	474,117

(1)	Effective October 26, 2010 the shareholders approved a 1 for 10 reverse split of the issued and outstanding shares of our common stock reducing the outstanding shares from 134,306,080 to 13,430,608. Per share prices and share volumes pre-split have been adjusted to reflect this change.

As of March 30, 2012, we had 1,751 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 Consolidated Financial Statements and related annual filings. As of June 9, 2008 all of our filings were current and TSX Venture Exchange reinstated trading in our securities on November 17, 2008.

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.

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, 2011.

Item 6 – Selected Financial Data:

As a smaller reporting company, we are not required to respond to this Item.

Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations:

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 consolidated 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 recorded a net loss of $905,792 and $2,062,145 in 2011 and 2010, respectively. We had a working capital deficiency at December 31, 2011 of approximately $7.4 million and an accumulated deficit at December 31, 2011 which leads to questions concerning our ability to meet our obligations as they come due. We 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. 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”.

Statements of Operations

A Comparison of Operating Results for the Years Ended December 31, 2011 and December 31, 2010

We recorded a net loss of $905,792 during the year ended December 31, 2011 compared to a net loss of $2,062,145 during the year ended December 31, 2010. During the year ended December 31, 2011, our revenues were composed of oil and gas sales totaling $1,949,000 compared with oil and gas sales of $2,524,000 during the same period of 2010. Our oil sales for the twelve months ended December 31, 2011 were lower as a result of decreased production due to mechanical problems in our field during the 4^th quarter of 2011. The decreased production was partially offset by higher oil prices. Our net average daily production for the twelve month period ended December 31, 2011 decreased by 45% over the same period of the prior year, from 162 (92 net) barrels of oil equivalent per day to 84 (51 net) barrels of oil equivalent per day. The decrease was due to a 45% decrease in gross production and was partially offset by an increase in oil prices. Oil prices increased by 39% for the twelve month period ended December 31, 2011 over the same period of the prior year from $75.43 per barrel of oil equivalent to $105.19 per barrel of oil equivalent. Production from our existing wells is subject to fluctuation based upon which zones of wells are in production and normal declines resulting as the reservoirs are depleted.

We had expenses of $2,905,000 for the year ended December 31, 2011 compared to expenses of $4,641,000 for the year ended December 31, 2010. Our general and administrative expenses decreased by $14,000 for the twelve months ended December 31, 2011 compared to the same period in 2010 at $1,595,000 and $1,609,000 respectively.

Interest and financing costs decreased by $276,000 for the year ended December 31, 2011 compared to the same period in 2010 at $235,000 and $511,000 respectively. Interest costs were higher in 2010 due to the amortization of note discounts.

Lease operating expenses of $744,000, production taxes of $58,000 and depletion, depreciation and amortization of $515,000 during the year ended December 31, 2011 changed from $890,000, $133,000, and $912,000, respectively, during the year ended December 31, 2010. Lease operating expenses and production taxes were lower in 2011 as a result of decreased production. The decrease in depletion, depreciation and amortization was also due to decreased production in 2011.

During the year ended December 31, 2011, we had a foreign exchange gain of $242,000, compared to a $587,000 foreign exchange loss for the year ended December 31, 2010. Our foreign exchange gains and losses arise out of an inter-company indebtedness we owe to our wholly-owned subsidiary, Gothic, which is payable in Canadian dollars. The foreign exchange gain for the twelve months ended December 31, 2011 was caused by the strengthening of the US dollar against the Canadian dollar.

Liquidity and Capital Resources

General

At December 31, 2011 our current assets are $165,000 compared with current liabilities of $7.6 million which includes accounts payable, revenues payable, notes payable, and other current obligations. We have substantial needs for funds to pay our outstanding payables and debt due during 2011.

We have substantial need for capital to develop our oil and gas prospects. 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 notes payable. Any capital expenditures for drilling purposes during 2012 will be partially funded from proceeds from the financing agreement that was finalized in February of 2012 with TCA Global Credit Master Fund, LP. We will raise a total amount of $3 million, before fees and expenses, through the issuance of a series of $1 million debentures. We expect additional funding 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.

Years Ended December 31, 2011 and December 31, 2010

Our net cash provided by operating activities was $238,000 for the year ended December 31, 2011 as compared to net cash provided by operating activities of $714,000 for the year ended December 31, 2010, a decrease of $476,000. The decrease in net cash provided by operating activities for the year ended December 31, 2011 compared to the same period of 2010 was primarily due to a decrease in non-cash items for the year ended 2011. Changes in working capital items had the effect of increasing cash flows from operating activities by $532,000 during the year ended December 31, 2011 due to a decrease in accounts receivable and prepaid expense and an increase in accounts payable. Changes in working capital items had the effect of increasing cash flows from operating activities by $624,000 during the year ended December 31, 2010 due to a decrease in accounts receivable and prepaid expense and an increase in accounts payable.

We used $160,000 of net cash in investing activities during the year ended December 31, 2011 compared to net cash used of $335,000 for the same period of 2010. The cash used in investing activities was for the purchase and development of oil and gas properties for both years.

We used $87,000 of net cash in financing activities for the year ended December 31, 2011 compared to $513,000 of net cash used in financing activities for the same period in 2010. For the year ended December 31, 2011, net cash outflows from financing activities were a result of the issuance of notes of $629,000 of which $500,000 was to related parties, offset by payments against outstanding notes of $626,000 of which $181,000 was to related parties, and payments of deferred financing costs of $90,000. For the year ended December 31, 2010, net cash outflows from financing activities were a result of payments against outstanding notes of $829,000 of which $600,000 was to related parties offset by the issuance of notes to related parties of $331,000 and deferred financing costs of $15,000.

We have no other commitments to expend additional funds for drilling activities for the rest of 2012.

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

How We Have Financed Our Activities

Our activities since 2002 have been financed primarily from sales of debt and equity securities and drilling participations. These transactions during this period of time included the following, among other previously reported financing transactions we entered into during the period:

Certain Financing Transactions Prior to January 1, 2010:

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 $4.50 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 $1.50 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, 7,216,667 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.

On October 19, 2005 we executed a 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 elected 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 retained 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.

On March 19, 2009 the TSX Venture Exchange approved the issuance of 106,000 shares of our common stock as payment for an outstanding invoice owed to Wakabayahsi Funds LLC in the amount of $10,600. The shares were issued on March 26, 2009.

On July 29, 2009 we closed the final tranche of a Private Placement of 6.67 million shares of our common stock at $0.30 per share for total proceeds of $2.0 million. In conjunction with this placement, finders fees were paid to two firms in Vancouver, BC in the amount of $96,839 and finders warrants were issued for the purchase of 538,000 shares of common stock exercisable through July 29, 2010 at $0.50 per share. The net proceeds of the private placement are being used to close the Dune Transaction and for working capital purposes.

On August 4, 2009 we re-purchased and retired $7.8 million, plus accrued and unpaid interest, of its 8% Secured Debentures held by Dune (including release of collateral rights), acquired Dune’s interest in producing wells and certain leasehold rights in the Bayou Couba field, resumed operations of the Bayou Couba field and settled outstanding issues between the companies. In exchange, the Company agreed to assign a portion of certain deep rights held by us and pay Dune a total of $1.3 million dollars with $1 million due at closing and an additional $300,000 due in quarterly payments commencing 90 days after resuming operations of the field.

We re-purchased its remaining outstanding 8% Secured Debenture debt totaling $2.0 million and an additional $821,000 of accrued interest with various holders with the payment of $256,000 and the issuance of 1.17 million shares of its common stock at a deemed price of US$0.30 per share. The issuance of the shares occurred during the third quarter of 2009.

In December 2009, we granted 160,000 common shares to a group of lenders as a share bonus for the bridge loan related to the acquisition of an Overriding Royalty Interest. The relative fair value of these shares of $42,585 was recorded as a discount on the bridge loan. The issuance of the shares occurred in January 2010.

Future Capital Requirements and Resources

At December 31, 2011, our current assets are $165,000 compared with current liabilities of $7.6 million which includes accounts payable, revenues payable and notes payable (a portion of which is past due). We have substantial needs for funds to pay our outstanding payables and debt due during 2012. In addition, we have substantial need for capital to develop our oil and gas prospects.

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 notes payable. Any capital expenditures for drilling purposes during 2012 will be partially funded from proceeds from the financing agreement that was finalized in February of 2012 with TCA Global Credit Master Fund, LP. We will raise a total amount of $3 million, before fees and expenses, through the issuance of a series of $1 million debentures. We expect additional funding 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.

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 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 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. Oil prices have fluctuated significantly over the past twelve months.

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

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 FASB ASC 740, 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, 2011 and 2010, we have a deferred tax asset of approximately $8.1 million and $7.2 million for which we have recognized a $8.1 million and $7.2 million valuation allowance, respectively.

Notes payable and long-term debt

We account for notes payable and long-term debt by recording the face amount of the debt instrument adjusted for any premium or discount realized on the issuance of the instrument. The premium or discount is amortized to expense utilizing the effective interest rate method for debt instruments with scheduled repayment terms. 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 FASB ASC 410-20, Accounting for Asset Retirement Obligations (“ASC 410-20”). 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 ASC 410-20 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.

Off-Balance Sheet Arrangements

We have no significant off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to stockholders.

Accounting Matters

On December 31, 2008, the Securities and Exchange Commission (SEC) issued the final rule, “Modernization of Oil and Gas Reporting” (“Final Rule”). The Final Rule adopts revisions to the SEC’s oil and gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the oil and gas disclosure requirements to align them with current practices and technological advances. Revised requirements in the Final Rule include, but are not limited to:

Oil and gas reserves must be reported using a 12-month average of the closing prices on the first day of each of such months, rather than a single day year-end price:
Companies will be allowed to report, on a voluntary basis, probable and possible reserves, previously prohibited by SEC rules; and
Easing the standard for the inclusion of proved undeveloped reserves (PUDs) and requiring disclosure of information indicating any progress toward the development of PUDs.

We have adopted the Final Rule and have begun complying with the disclosure requirements in this annual report on Form 10-K for the year ended December 31, 2011.

In January 2010, the FASB issued FASB Accounting Standards Update (ASU) No. 2010-03 Oil and Gas Estimations and Disclosures (ASU 2010-03). This update aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries Oil and Gas topic of the FASB ASC (Topic 932) with the changes required by the SEC final rule ASC 2010-03, as discussed above. ASU 2010-03 expands the disclosures required for equity method investments, revises the definition of oil and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. The impact on the Company’s operating results, financial position and cash flows has been recorded in the financial statements.

In January 2010, the FASB issued ASU No. 2010-06, Improving Disclosures about Fair Value Measurements (ASU 2010-06). This update provides amendments to Subtopic 820-10 and requires new disclosures for 1) significant transfers in and out of Level 1 and Level 2 and the reasons for such transfers and 2) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements. In addition, this update amends Subtopic 820-10 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements). The provisions in ASU 2010-06 are applicable to interim and annual reporting periods beginning subsequent to December 15, 2009, with the exception of Level 3 disclosures of purchases, sales, issuances and settlements, which will be required in reporting periods beginning after December 15, 2010. The adoption of ASU 2010-06 did not impact the Company's operating results, financial position or cash flows, but did impact the Company's disclosures on fair value measurements.

Item 7A – Quantitative and Qualitative Disclosures About Market Risk:

As a smaller reporting company, we are not required to respond to this Item.

Item 8 – Consolidated Financial Statements and Supplementary Data:

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

Item 9A(T) – Controls and Procedures

(a) Management’s 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 consolidated 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 consolidated 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 consolidated financial statements.

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, 2010, 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 consolidated 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 consolidated 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 consolidated 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 consolidated 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 consolidated 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. 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.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management's report is not at this time subject to attestation by our registered public accounting firm pursuant to temporary rules and amendments thereto of the SEC that permit us to provide only management's report in this annual report.

Despite the internal control deficiencies, we believe that our consolidated financial statements contained in this Form 10-K filed with the SEC fairly present our financial position, results of operations and cash flows for the fiscal year ending December 31, 2011 in all material respects.

Item 9B – Other Information

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

PART III

Item 10 – Directors, Executive Officers and Corporate Governance:

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⁾	63	President and Director
Steven P. Ensz	60	Vice President, Finance, and Chief Financial Officer and Director
Bennett G. Shelton⁽¹⁾	55	Director
William A. Grant ⁽¹⁾	50	Director

Significant Employees:
Richard O. Mulford	59	Manager of Operations
Robert G. Snead	73	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 20 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 24 years. He is a certified public accountant.

Bennett G. Shelton: Mr. Shelton has been involved in oil and gas land and acquisition management since graduating from Oklahoma Panhandle State University in 1979. With a Bachelor Degree in Business Administration his career moved from Phillips Petroleum Company to positions of increasing responsibility with Andover Oil Company, ALN Resources, Inc. and Gothic Energy Corporation where he served as Vice President of Land and Acquisitions. From June 2001 through January 2007 Mr. Shelton was Manager of Land and Acquisitions for American Natural Energy Corporation and since February 2007 has been a Land Advisor with Broad Oak Energy, Inc.

William A. Grant III: Mr. Grant has held various leadership roles in the banking and insurance industries for the past 24 years. Mr. Grant began his career in a position in Bank of Oklahoma’s management training program and advanced to the position of Vice President - energy lending. Subsequent to his tenure at Bank of Oklahoma, he joined F&M Bank until he purchased an interest and took the reins as President of the The Holmes Organisation in 1997.

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 and 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 December 31, 2011, the members of our Audit Committee of our Board of Directors are Messrs. Shelton (Chairman), Grant and Paulk. Mr. Paulk has been a member of the Audit Committee since 2006. Mr. Grant was added during 2009, and Mr. Shelton was added during 2010. 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 consolidated 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.

Item 11 - 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, 2011 who received total compensation exceeding $100,000 for the year ended December 31, 2011 and who served in such capacities at December 31, 2011.

SUMMARY COMPENSATION TABLE
Annual Compensation

						Non-
						Equity	Nonqualified
Name						Incentive	Deferred
and				Stock	Option	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,	2011	$150,000	-0-	-0-	-0-	-0-	-0-	-0-	$150,000
President and CEO⁽²⁾	2010	$150,000	-0-	-0-	$196,987	-0-	-0-	-0-	$346,987
Steven P. Ensz	2011	$150,000	-0-	-0-	-0-	-0-	-0-	-0-	$150,000
Executive Vice President and CFO⁽²⁾	2010	$150,000	-0-	-0-	$196,987	-0-	-0-	-0-	$346,987

⁽¹⁾	Represents the dollar amount recognized for financial statement reporting purposes with respect to the fiscal year in accordance with FASB ASC 718. See Note 1 to Notes to Consolidated Financial Statements for the year ended December 31, 2011.
⁽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.

Outstanding Equity Awards at December 31, 2011

The following table provides information with respect to our named executive officers above regarding outstanding equity awards held at December 31, 2011.

	Option Awards				Stock Awards
					Number	Market	Equity	Equity Incentive
					of	value of	Incentive	Plan Awards:
					shares	shares	Plan	Market or
		Equity			or units	or units	Awards:	payout
	Number of	Incentive			of	of	Number of	value of
	securities	Plan Awards:			Stock	Stock	Unearned	Unearned
	underlying	Number of			held	held	Shares,	Shares, Units
	unexercised	Securities			that	that	Units or	or Other
	Options	Underlying	Option		have	have	Other Rights	Rights That
	(#)	Unexercised	Exercise	Option	not	not	That Have	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	150,000/0	-0-	0.90	9/8/14	-0-	-0-	-0-	-0-
	495,000/165,000	165,000	0.30	11/30/15	-0-	-0-	-0-	-0-
Steven P. Ensz	150,000/0	-0-	0.90	9/8/14	-0-	-0-	-0-	-0-
	495,000/165,000	165,000	0.30	11/30/15	-0-	-0-	-0-	-0-

Director Compensation

None of our directors received any compensation, including equity awards, during the year ended December 31, 2011.

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 5,000 shares on the date such person joins the Board. In addition, on the date of each annual stockholder meeting, provided such person has served as a non-employee Director for at least six months, each non-employee Board member who is to continue to serve as a non-employee Board member will automatically be granted an option to purchase 500 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 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters:

The following table sets forth certain information regarding beneficial ownership of our common stock as of March 30, 2012 (a) by each person who is known by us to own beneficially more than five percent (5%) of our common shares, (b) by each of our Directors and officers, and (c) by all Directors and officers as a group. As of March 30, 2012, we had 18,928,895 common shares outstanding.


		Percentage of
	Number of Shares	Outstanding
Name and Address ⁽¹⁾⁽²⁾	Owned	Shares⁽³⁾

Michael K. Paulk	2,359,888⁽⁴⁾	12.1%
Steven P. Ensz	2,709,832⁽⁵⁾	13.8%
Bennett G. Shelton	190,674⁽⁶⁾	1.0%
812 Crane Drive
Coppell, TX 75019
William A. Grant	123,333⁽⁷⁾	0.7%
1350 S. Boulder, Suite 1000
Tulsa, OK 74119
All Directors and officers as a group (4 persons)	5,383,727	26.5%

⁽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 2010, Tulsa, Oklahoma 74136.
⁽³⁾	The percentage of outstanding shares calculation is based upon 18,928,895 shares outstanding as of March 30, 2012, except as otherwise noted.
⁽⁴⁾	Includes 150,000 shares issuable at an exercise price of $0.90 on exercise of an option and 495,000 shares issuable at an exercise price of $0.30 on exercise of an option. Includes 1,500,000 shares issued on March 5, 2012.
⁽⁵⁾	Includes 150,000 shares issuable at an exercise price of $0.90 on exercise of an option and 495,000 shares issuable at an exercise price of $0.30 on exercise of an option. Includes 1,500,000 shares issued on March 5, 2012.
⁽⁶⁾	Includes 37,500 shares issuable at an exercise price of $0.30 on exercise of an option.
⁽⁷⁾	Includes 10,000 shares issuable at an exercise price of $0.90 on exercise of an option and 30,000 shares issuable at an exercise price of $0.30 on exercise of an option .

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 Consolidated Financial Statements for further information on the material terms of this plan.

The following table provides information as of December 31, 2011 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

	(a)	(b)	(c)
Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders	2,515,000	$0.41	-0-
Equity compensation plans not approved by security holders	-0-	-0-	-0-
Total	2,515,000	$0.41	-0-

Item 13 - Certain Relationships and Related Transactions:

During 2011 we entered into a $500,000 unsecured short-term note with interest at the rate of 10% per annum with Mike Paulk, an officer of the Company. All accrued interest is payable monthly and the maturity date of the loan is February 15, 2012. Proceeds from the note were used to pay the outstanding obligation to Bank of Oklahoma and the balance for working capital. We paid Mike Paulk $39,000 for interest on the loan.

On March 31, 2011, with an effective date of January 1, 2011, we purchased the working interests from TPC Energy for $300,000 through the issuance of a note payable in the same amount. Principal payments of $12,500 and interest at the rate of 10% per annum are due monthly. During the effective date through the closing date of March 31, 2011, revenues of $95,662 were recorded as a net purchase price adjustment that lowered the note payable balance to $204,338 and during 2011 cash payments totaling $40,155 were also applied to the note which left a remaining balance due of $164,183. We paid TPC Energy $21,000 for interest on the loan.

Item 14. Principal Accountant Fees and Services

The following sets forth fees we incurred for services provided by MaloneBailey, LLP for the years ended December 31, 2011 and 2010, our independent registered public accountants at those year ends.

			Audit Related
		Audit Fees	Fees	Tax Fees
2011	$	94,000	-	-
2010	$	74,000	-	-

Our Board of Directors believes that the provision of the services during the years ended December 31, 2011 and December 31, 2010 is compatible with maintaining the independence of MaloneBailey, LLP. Our Audit Committee approves before the engagement the rendering of all audit and non-audit services provided to our company by our independent auditor. Engagements to render services are not entered into pursuant to any pre-approval policies and procedures adopted by the Audit Committee. The services provided by MaloneBailey, LLP included under the caption Audit Fees include services rendered for the audit of our annual consolidated 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.

Item 15 – 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	Assignment, Conveyance and Bill of Sale from Dune Energy Inc to American Natural Energy Corporation dated August 4, 2009 ⁽¹¹⁾

Exhibit	Description
10.3	Assignment, Conveyance and Bill of Sale from American Natural Energy Corporation to Dune Energy Inc dated August 4, 2009 ⁽¹¹⁾
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
23.1	Consent of Summa Engineering ⁽¹¹⁾
31.1	Certification of President and Chief Executive Officer Pursuant to Rule 13a- 14(a)⁽¹¹⁾
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)⁽¹¹⁾
32.1	Certification of President and Chief Executive Officer Pursuant to Section 1350 (furnished, not filed)⁽¹¹⁾
32.2	Certification of Chief Financial Officer Pursuant to Section 1350 (furnished, not filed)⁽¹¹⁾
99.1	Summa Engineering Inc. Report of American Natural Energy Corporation Reserve at December 31, 2011 ⁽¹¹⁾


⁽¹⁾	Filed as an Exhibit to the Registrant’s registration statement on Form 10-SB filed on August 12, 2002 and amended on July 29, 2003. (File No. 0-18956).
⁽²⁾	Filed as an Exhibit to the Registrant’s Quarterly Report on Form 10-QSB for the quarter ended September 30, 2003. (File No. 0-18956).
⁽³⁾	Filed with Amendment No. 1 to Registration Statement on Form SB-2 filed February 6, 2004 (File No. 333-111244).
⁽⁴⁾	Filed with the Registrant’s Annual Report on Form 10-KSB for the year ended December 31, 2003.
⁽⁵⁾	Filed 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.
⁽¹¹⁾	Filed with this Annual Report on Form 10-K for the year ended December 31, 2011.

American Natural Energy Corporation

Consolidated Financial Statements
December 31, 2011 and 2010

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 and its subsidiaries (the “Company”) as of December 31, 2011 and 2010 and the related consolidated statements of operations and other comprehensive income, stockholders’ equity (deficit), and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with 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 audits 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 and its subsidiaries at December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America..

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 incurred a net loss in 2011 and has a working capital deficiency and an accumulated deficit at December 31, 2011. 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/ MaloneBailey, LLP
Houston, Texas
www.malonebailey.com
March 30, 2012

F-2

AMERICAN NATURAL ENERGY CORPORATION
Consolidated Balance Sheets

	December 31,		December 31,
	2011		2010
	$		$
ASSETS
Current assets:
Cash and cash equivalents	-		8,658
Accounts receivable – joint interest billing	22,104		77,816
Accounts receivable – oil and gas sales	31,963		153,745
Prepaid expenses and other	84,141		108,064
Oil inventory	26,484		20,779
Total current assets	164,692		369,062
Proved oil and natural gas properties, full cost method of accounting, net of accumulated depletion, depreciation, amortization and impairment of $21,542,440 and $21,241,298 respectively (Note 1)	15,932,509		15,994,561
Unproved oil and natural gas properties	571,796		352,554
Equipment and other fixed assets, net of accumulated depreciation of $1,131,053 and $1,103,461 (Note 3)	47,178		74,770
Other deferred costs	105,000		15,000
Total assets	16,821,175		16,805,947

LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable and accrued liabilities	2,276,534		2,089,119
Revenue payable	3,460,249		3,288,180
Accounts payable – related parties	49,936		-
Accrued interest	58,510		18,072
Insurance note payable	48,163		68,028
Notes payable – related parties	685,911		161,062
Notes payable (Note 5)	952,527		1,248,247
Taxes due on dissolution of subsidiary (Note 10)	45,252		65,252
Total current liabilities	7,577,082		6,937,960
Asset retirement obligation (Note 4)	2,208,867		2,023,780

Total liabilities	9,785,949		8,961,740
Commitments and contingencies (Note 10)
Stockholders’ equity (deficit):
Common stock (Note 7)
Authorized – 250,000,000 shares with par value of $0.001
13,431,954 and 13,430,608 shares issued and outstanding respectively	13,432		13,431
Additional paid-in capital	23,451,773		23,112,711
Accumulated deficit, since January 1, 2002 (in conjunction with the quasi-reorganization stated capital was reduced by an accumulated deficit of $2,015,495)	(20,228,381	)	(19,322,589	)
Accumulated other comprehensive income	3,798,402		4,040,654
Total stockholders’ equity (deficit)	7,035,226		7,844,207
Total liabilities and stockholders’ equity (deficit)	16,821,175		16,805,947

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

	Year Ended		Year Ended
	December 31, 2011		December 31, 2010
	$		$
Revenues:
Oil and gas sales	1,948,949		2,523,730
Operations income	49,887		54,802

Total revenues	1,998,836		2,578,532

Expenses:
Lease operating expense	743,531		890,306
Production taxes	57,955		132,552
General and administrative	1,595,253		1,608,606
Foreign exchange (gain) loss	(242,252	)	586,893
Interest and bank charges	158,513		483,645
Related party interest	76,545		27,047
Depreciation, depletion, and amortization - oil and gas properties	302,404		603,655
Accretion of asset retirement obligation	185,087		280,372
Depreciation and amortization – other assets	27,592		27,601

Total (income) expenses	2,904,628		4,640,677

Net loss	(905,792	)	(2,062,145	)

Other comprehensive (income) loss:
Foreign exchange translation (gain) loss	(242,252	)	586,893

Other comprehensive (income) loss	(242,252	)	586,893

Comprehensive loss	(1,148,044	)	(1,475,252	)

Net loss per share – basic and diluted	(0.07	)	(0.15	)

Weighted average number of shares outstanding – basic and diluted	13,431,954		13,430,252

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

F-4

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

							Accumulated		Total
			Additional				other		stockholders’
	Common stock		paid-in		Accumulated		comprehensive		equity
	Shares	Amount	capital		deficit		income		(Deficit)
		$	$		$		$		$
Balance - December 31, 2009	13,398,108	13,398	22,783,144		(17,260,444	)	3,453,761		8,989,859

Shares issued acquisition WIO rights	32,500	33	22,092		-		-		22,125
Stock option compensation expense	-	-	307,475		-		-		307,475
Foreign exchange translation loss	-	-	-		-		586,893		586,893
Net loss	-	-	-		(2,062,145	)	-		(2,062,145	)

Balance - December 31, 2010	13,430,608	13,431	23,112,711		(19,322,589	)	4,040,654		7,844,207

Fractional shares issues due to reverse stock split	1,346	1	(1	)	-		-		-
Stock option compensation expense	-	-	339,063		-		-		339,063
Foreign exchange translation gain	-	-	-		-		(242,252	)	(242,252	)
Net loss	-	-	-		(905,792	)	-		(905,792	)

Balance - December 31, 2011	13,431,954	13,432	23,451,773		(20,228,381	)	3,798,402		7,035,226

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

F-5

AMERICAN NATURAL ENERGY CORPORATION
Consolidated Statements of Cash Flows

	December 31, 2011		December 31, 2010
	$		$
Cash flows from operating activities:
Net loss	(905,792	)	(2,062,145	)
Non cash items:
Depreciation, depletion and amortization	329,996		631,256
Accretion of asset retirement obligation	185,087		280,372
Foreign exchange (gain) loss	(242,252	)	586,893
Noncash compensation expense	339,063		307,475
Amortization of debt discount	-		346,343
Changes in working capital items:
Accounts receivable	177,494		157,545
Oil inventory	(5,705	)	(7,452	)
Prepaid expenses	23,923		155,373
Accounts payable, revenues payable and accrued liabilities	335,981		318,639

Net cash provided by operating activities	237,795		714,299

Cash flows from investing activities:
Purchase and development of oil and gas properties	(159,806	)	(334,887	)

Net cash used in investing activities	(159,806	)	(334,887	)

Cash flows from financing activities:
Payment of notes payable – related party	(181,062	)	(599,558	)
Payment of notes payable	(444,993	)	(229,304	)
Proceeds from issuance of notes payable	129,408		-
Proceeds from issuance of notes payable- related party	500,000		330,620
Financing costs	(90,000	)	(15,000	)

Net cash used in financing activities	(86,647	)	(513,242	)

Decrease in cash and cash equivalents	(8,658	)	(133,830	)

Cash and cash equivalents beginning of period	8,658		142,488

Cash and cash equivalents end of period	-		8,658

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

F-6

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


	December 31, 2011	December 31, 2010
	$	$
Supplemental disclosures:

Interest paid	146,175	103,055
Taxes Paid	20,000	60,000
Non cash financing and investing activities:
Oil and gas property additions included in accounts payable	71,677	-
Prepaid expenses financed	-	112,364
Asset retirement obligation revision	-	(930,595	)
Exchange of oil and gas leasehold interests	-	92,983
Offset of JIB Receivable and Note Payable	-	27,065
Purchase of working interest through issuance of a note payable (Note 6)	226,847	-
Stock issued as partial payment for purchase of third party working interest	-	22,125
Discount on notes payable	-	108,141

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

F-7

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010

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. ANEC’s 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 consolidated financial statements include the accounts of ANEC and its wholly-owned subsidiary Gothic (collectively, 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 the time of acquisition. Cash and cash equivalents are deposited with two institutions and the balance at either institution does not exceed the federally insured limits at December 31, 2011 and 2010. While balances may periodically exceed the federal depository insurance limit, the Company has not experienced any losses on deposits.

Allowance for Doubtful Accounts

The Company establishes provisions for losses on accounts receivable if it determines that it will not collect all or part of the outstanding balance. The Company regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. There is no significant allowance for doubtful accounts as of December 31, 2011 or 2010.

F-8

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010

Oil and natural gas properties

The Company follows the full cost method of accounting for oil and natural gas properties. The Company defers the costs of exploring for and developing oil and natural gas reserves until such time as proved reserves are attributed to the properties. At that time, the deferred costs are amortized on a unit-of-production basis. Such costs include land acquisition costs, geological and geophysical costs, 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 net book value of all capitalized oil and natural gas properties within a cost center, less related deferred income taxes, is subject to a full cost ceiling limitation which is calculated quarterly. Under the ceiling limitation, costs may not exceed an aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent using current prices, plus the lower of cost or market value of unproved properties included in the amortization base, plus the cost of unevaluated properties, less any associated tax effects. Any excess of the net book value, less related deferred tax benefits, over the ceiling is written off as expense. Impairment expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period. Based on the results of the ceiling limitation test, no impairment was recorded in the years ended December 31, 2011 and 2010.

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, 2011 and 2010, 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:

F-9

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010


Computer equipment	3 years
Office furniture and equipment	5-7 years
Leasehold improvements	1 year
Barges and field equipment	5-10 years
Gas gathering and production facility	10 years

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

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, 2011 and 2010 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 Sunoco, Inc (formerly Texon L.P.) of $1,937,606 and $2,464,419 in 2011 and 2010, respectively, accounted for 99% and 98% 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.

F-10

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010

Asset retirement obligations

Effective January 1, 2003, the Company adopted Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 410-20, Accounting for Asset Retirement Obligations. 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. ASC 410-20 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 FASB ASC 740, 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 consolidated financial statements. The deferred tax assets or liabilities are calculated using the enacted tax rates in effect for the year in which the differences are expected to reverse. Deferred tax assets are recognized to the extent that they are considered more likely than not to be realized. Income taxes and liabilities are recognized for the expected future tax consequences of events that have been included in the financial statements or income tax returns.

Use of estimates

The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of 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). 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.

Comprehensive income (loss)

The preparation of consolidated 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 consolidated 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 $242,252 and other comprehensive loss of $586,893 for 2011 and 2010 respectively as a result of foreign exchange translation gains and losses. As of December 31, 2011 and 2010, accumulated other comprehensive income (loss) was composed solely of foreign currency translation gains and losses.

F-11

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010

Stock-based compensation

During 2011, the Company recognized compensation costs of $339,063 related to stock options issued November 30, 2010 and September 8, 2009. Compensation costs of $307,475 were recognized by the Company during 2010.

There were 2,050,000 stock options issued November 30, 2010. At December 31, 2011, there were 2,002,500 options outstanding and exercisable with a weighted average exercise price of $0.44. The weighted average remaining contractual term for these options at December 31, 2011 was 3.67 years. These options had no intrinsic value at December 31, 2011.

New pronouncements

In May 2011, the FASB issued Accounting Standards Update No. 2011—04: “Fair Value Measurement (Topic 820) – Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs”. This accounting update clarifies application of fair value measurement and disclosure requirements and is effective for annual periods beginning after December 15, 2011. The Company is currently evaluating the provisions of this accounting update and assessing the impact, if any, it may have on our financial position and results of operations.

In December 2011, the FASB issued Accounting Standards Update No. 2011—11 “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities”. This accounting update requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The accounting update is effective for annual periods beginning on or after January 1, 2013. The Company is currently evaluating the provisions of this accounting update and assessing the impact, if any, it may have on our financial position and results of operations.

Reclassification of Prior Period Statements

Certain reclassifications of prior period consolidated financial statements balances have been made to conform to current reporting practices.

2	Going Concern

The Company currently has a severe shortage of working capital and funds to pay its liabilities. The Company has no current borrowing capacity with any lender. The Company recorded a net loss of $905,792 in 2011. The Company has a working capital deficiency and an accumulated deficit at December 31, 2011 which leads to substantial doubt 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.

F-12

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010

The accompanying consolidated 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 continue to explore for and develop its oil and gas reserves and pay its obligations.

Management’s strategy has been to obtain additional financing or industry partners. It is management’s intention to raise additional debt or equity financing to fund its operations and capital expenditures or to enter into another transaction in order to maximize shareholder value. 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, grow revenues, oil and gas reserves and achieve and maintain a significant level of revenues, cash flows, and profitability. There can be no assurance that the Company will obtain this 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	Equipment and other fixed assets

The carrying value of equipment and other fixed assets as of December 31, 2011 and 2010 included the following components:

	2011		2010
	$		$
Computer, office furniture and equipment	163,060		163,060
Leasehold improvements	5,520		5,520
Barges and field equipment	802,014		802,014
Gas gathering and production facility expansion	207,637		207,637
	1,178,231		1,178,231

Less: Accumulated depreciation	(1,131,053	)	(1,103,461	)
	47,178		74,770

F-13

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010

4	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 during 2011 and 2010 are shown below.

	For the years ended December 31,
	2011	2010
	$	$
Asset retirement obligations, January 1	2,023,780	2,674,003
Additions and revisions	-	(930,595	)
Settlements and disposals	-	-
Accretion expense	185,087	280,372
Asset retirement obligations, December 31	2,208,867	2,023,780

The revision in 2010 of $930,595 is due to a change in the plug and abandon timing.

5	Notes payable and long-term debt

Notes payable and long-term debt as of December 31, 2011 and 2010 consisted of the following:

	2011		2010
	$		$
Accounts payable refinanced as notes payable	-		19,930
Note payable - Citizens Bank of Oklahoma	422,465		448,255
Note payable - Bank of Oklahoma	-		250,000
Note payable - Dune Energy (Note 7)	157,017		157,017
Note payable - Leede Financial	373,045		373,045
Total third-party notes payable and long-term debt	952,527		1,248,247

Note payable - TPC Energy	164,183		139,334
Note payable - Mike Paulk	500,000		-
Note payable - Other	21,728		21,728

Total related party notes payable and long-term debt	685,911		161,062

Total notes payable and long-term debt	1,638,438		1,409,309
Less: Current portion	(1,638,438	)	(1,409,309	)

Total notes payable and long-term debt, net of current portion	-		-

F-14

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010

On December 16, 2005, the Company converted its $99,000 accounts payable balance to Patterson Services to a note payable and on March 31, 2010 a payment agreement was signed. The note was paid off in February 2011.

On September 10, 2009, the Company entered into a $500,000 unsecured short-term note with interest at the rate of 6% per annum with Citizens Bank of Oklahoma. The loan was modified with a new interest rate of 12% and a maturity date of July 31, 2012. All accrued interest is payable monthly. Proceeds of $475,500 from the note were paid to the Company and the remaining proceeds of $24,500 were used to pay off a prior note with Citizens Bank of Oklahoma. Net payments of $25,790 were made during the year ended December 31, 2011. The Company evaluated the application of ASC 470-50 and ASC 470-60 and concluded that the revised terms constituted a debt modification, rather than a debt extinguishment or a troubled debt restructuring.

On September 2, 2009, the Company entered into a $250,000 unsecured short-term note with a variable interest rate with Bank of Oklahoma. The note was paid in full on February 17, 2011.

In 2009 and 2010, the Company and TPC Energy entered into financing agreements whereas TPC Energy advanced funds required for the recompletion of behind pipe zones in several existing wells. The terms of the financing required the Company to repay the funds advanced out of specified cash flow from the subject wells. Principal and interest at 10% per annum and is payable monthly. Upon payout of the cost of recompleting the wells, the Company assigned a pro-rata 25% working interest in the wells to TPC Energy. Based on the relative fair value of the wells, a discount on the note was recorded with the discount being amortized over the life of the loan using the effective interest rate method. These discounts were fully amortized as of December 31, 2010. During the six months ended June 30, 2011, cash payments totaling $133,535 were also applied to the note which paid the note in full. In June 2010, the Company borrowed $100,000 from TPC Energy with an interest rate of 10% per annum. The principal and interest was repaid during the first quarter of 2011. On March 31, 2011, with an effective date of January 1, 2011, the Company purchased the working interests from TPC Energy for $300,000 through the issuance of a note payable in the same amount. Principal payments of $12,500 and interest at the rate of 10% per annum are due monthly. During the effective date through the closing date of March 31, 2011, revenues of $95,662 were recorded as a purchase price adjustment that lowered the note payable balance to $204,338 and during the year ended December 31, 2011, cash payments totaling $40,155 were also applied to the note which left a remaining balance due of $164,183. The TPC note is included in Notes Payable – Related Parties on the balance sheet as of December 31, 2011 and December 31, 2010.

On December 23, 2009, the Company entered into a $373,045 unsecured short-term note with Leede Financial with an interest rate of 12% per annum. The maturity date of the note has been extended to June 30, 2012. Due to the unsecured nature of the note, Leede Financial received a bonus of 160,000 shares of the Company’s common shares at a deemed price of $0.30 per share. A discount on the note of $42,585 was recorded based on the relative fair value of the common shares issued and was fully amortized at December 31, 2010. The Company evaluated the application of ASC 470-50 and ASC 470-60 and concluded that the revised terms constituted a debt modification, rather than a debt extinguishment or a troubled debt restructuring.

F-15

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010

On February 17, 2011, the Company entered into a $500,000 note payable with Mike Paulk, a director of the Company, with an annual interest rate of 10%. Monthly payments may be made; however, all unpaid principal and interest is due and payable on February 15, 2012.

6	Convertible debentures

	On August 4, 2009, the Company re-purchased and retired $7.895 million, plus $2.1 million accrued and unpaid interest, of its 8% Secured Debentures held by Dune (including release of collateral rights), acquired Dune’s interest in producing wells and certain leasehold rights in the Bayou Couba field, resumed operations of the Bayou Couba field, and settled outstanding issues between the companies, which net to $2.1 million payable to Dune. In exchange, the Company assigned a portion of certain deep rights held by the Company and paid Dune $1.0 million at the closing and issued a note payable of $300,000 payable in six consecutive quarterly payments of $50,000 each, with the first installment due and payable 90 days after resuming operations of the field. The second installment has not been paid yet at the time of this Form 10-K filing. The interests acquired from Dune were fair valued at $13.8 million based on the present value of the future cash flows of the proved reserves discounted at 10 percent. The certain deep rights assigned to Dune is unproved property with zero book value. The gain on the settlement of the debenture and exchange of properties with Dune was $24.86 million. As of March 31, 2010 additional deep rights were assigned to Dune valued at $93,000 and were recorded as a reduction to the note payable. As of December 31, 2011 the balance of the note payable to Dune was approximately $157,000.

7	Common stock

	During the first quarter of 2010, 32,500 common shares were issued for a total value of $22,125 for the acquisition of various working interests.

	The Company obtained the required stockholder and other approvals to file the necessary corporate and other documents to effect a one-for-ten reverse split of its outstanding shares of common stock. The reverse split and resulting amendment to the Company’s Articles of Incorporation became effective at the close of business on October 26, 2010.

	During the first quarter of 2011, outstanding shares of our common stock increased by 1,346 due to the issuance of shares to shareholders who held fractions of a share as a result of our reverse stock split on October 26, 2010.

8	Options

	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 3,000,000 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.

F-16

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010

Stock option activity for the years ended December 31, 2011 and 2010 is as follows:

		Weighted
	Number of	Average
	Options	Exercise price
		$
Outstanding - December 31, 2009	465,000	0.90
Issued	2,050,000	0.30
Outstanding – December 31, 2010	2,515,000	0.41
Issued	-	-
Outstanding – December 31, 2011	2,515,000	0.41

At December 31, 2011 and 2010, 2,002,500 and 919,375 options have vested and are exercisable at a weighted average exercise price of $0.44 and $0.57, respectively. The weighted average remaining contractual life of options granted at December 31, 2011 and 2010 is 45 months and 57 months, respectively. There is no intrinsic value for the exercisable stock options at December 31, 2011.

On January 1, 2006, the Company adopted ASC 718 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 fair value of the 2,515,000 stock options granted during 2010 and 2009 totaled $944,617. The stock options granted to employees and directors in 2010 vest at 25% immediately and 12.5% per quarter thereafter and expire five years after the date of grant.

For the year ended December 31, 2011, the Company recognized compensation costs of $339,063 related to stock options granted. For the year ended December 31, 2010, the Company recognized compensation costs of $307,475 related to stock options granted. At December 31, 2011, there was $148,786 of total unrecognized compensation costs related to non-vested stock options which will be recognized over a weighted average period of approximately 6 months.

The fair value of stock options granted was estimated on the date of the grant using a Black-Scholes valuation model that uses the following weighted average assumptions:

Options Granted in 2010
Expected term, in years	2.83
Risk-Free interest rate	0.72%
Expected volatility	217.25%
Expected Dividend Rate	None

F-17

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010

The Company utilizes authorized but unissued shares when a stock option is exercised.

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. This Plan has terminated, however, all outstanding options and unvested stock issuances continue to have force and effect in accordance with the provisions of the documents evidencing such grants or issuances.

9	Warrants

Warrant activity for the years ended December 31, 2011 and 2010 is as follows:

			Weighted
	Number of		Average
	warrants		Exercise price
			$
Outstanding - December 31, 2009	538,000		0.50
Expired	(538,000	)	0.50

Outstanding – December 31, 2010	-		-

Outstanding – December 31, 2011	-		-

The Company granted a total of 538,000 warrants on July 28 and July 29, 2009 with an exercise price of $0.50 as a finders’ fee for the common share private placement. The warrants vested immediately and expired on the one year anniversary of the grant date.

10	Commitments and contingencies

The Company rents office space under a long-term operating lease that expires December 2012. At December 31, 2011, the future minimum lease payments required under the operating lease amounted to $99,000 and is to be paid in 2012.

Rent expense on all operating leases amounted to approximately $99,000 and $89,000 in 2011 and 2010, 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 (the “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 holds 93.4% of the Class 7 claims.

F-18

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010

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, 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. The Company is a defendant in a lawsuit brought by Dune Energy, Inc and Dune Operating Company alleging breach of contract and requesting a judgment in an amount of not less than $183,551 plus interest and attorney fees. The case is set for trial in January 2013.

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. Approximately $45,000 remains unpaid at December 31, 2011.

The Company, as an owner or lessee of oil and gas properties, is subject to various federal, state 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.

11	Related Party Transactions

During 2011 the Company entered into a $500,000 unsecured short-term note with interest at the rate of 10% per annum with Mike Paulk, an officer of the Company. All accrued interest is payable monthly and the maturity date of the loan is February 15, 2012. Proceeds from the note were used to pay the outstanding obligation to Bank of Oklahoma and the balance for working capital. The Company paid Mike Paulk $39,000 for interest on the loan.

F-19

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010

On March 31, 2011, with an effective date of January 1, 2011, the Company purchased the working interests from TPC Energy for $300,000 through the issuance of a note payable in the same amount. Principal payments of $12,500 and interest at the rate of 10% per annum are due monthly. During the effective date through the closing date of March 31, 2011, revenues of $95,662 were recorded as a net purchase price adjustment that lowered the note payable balance to $204,338 and during 2011 cash payments totaling $40,155 were also applied to the note which left a remaining balance due of $164,183. The Company paid TPC Energy $21,000 for interest on the loan.

12	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, 2011 and 2010 are presented below:

	2011		2010
	$		$
Deferred tax assets
Asset retirement costs	838,486		768,227
Foreign exchange loss	981,065		1,075,301
Acquisition, exploration and development costs and related depreciation, depletion and amortization	2,056,414		2,006,167
Contribution carryovers	6,142		4,814
Change in accounting principle	123,894		123,894
Net operating loss carryforwards	4,129,128		3,259,772
Deferred tax asset	8,135,129		7,238,175

Less: Valuation allowance	(8,135,129	)	(7,238,175	)

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, 2011 and 2010 are summarized as follows:

	2011		2010
	$		$

Federal tax benefit at statutory rate	307,969		701,130
State taxes, net of federal taxes	160,680		86,739
Other	1,071,605		(440,457	)
Less: valuation allowance	(1,540,254	)	(347,412	)

Total provision for income taxes	-		-

F-20

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010

As of December 31, 2011, the Company has a net operating loss carry-forward benefit of approximately $12.5 million which is available to reduce future taxable income, if any, through 2030. 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.

13	Subsequent Events

Pursuant to FASB ASC 855, the Company evaluated all events or transactions that occurred from January 1, 2012 through March 30, 2012, the date of issuance of the audited consolidated financial statements. During this period we did not have any material recognizable subsequent events, except as disclosed below:

The Company entered into a financing agreement with TCA Global Credit Master Fund, LP during the first quarter of 2012. Proceeds of the financing are to be used for the drilling and completion of wells included in the Company’s inventory of Proved Undeveloped reserves (“PUD”).

The Company has a commitment for a total amount of $3 million, before fees and expenses through the issuance of a series of $1 million debentures, of which $1 million was issued in January 2012. The debenture is secured by a first priority, perfected security interest and mortgage in oil and gas leases and properties. At no time shall the investor funds exceed 65% of the drilling and completion cost of the PUD’s with the balance provided by the Company’s generated funds. The outstanding debenture is due twelve (12) months from funding and is payable monthly with a mandatory redemption fee equal to 10% and interest of 5%.

The Company paid an Equity Incentive Fee of $150,000 worth of Restricted Shares of ANEC stock. The shares carry a nine (9) month ratchet whereby either party is obligated to refund (by the Investor) or issue (by the Company) shares to equal the initial value.

In connection with the closing of the $1 million first tranche in February 2012, the Company issued finder’s fees consisting of the following: a cash fee of $50,000, 732,235 shares of common stock of the Company, 500,000 warrants to purchase the common stock of the Company at an exercise price of $0.10 per share with a contractual term of five years and 96,000 warrants to purchase the common stock of the Company at an exercise price of $0.25 per share with a contractual term of five years.

On March 5, 2012, the Company issued 1.5 million Restricted Shares each to Mike Paulk and Steven Ensz as compensation for personal guarantees provided in connection with various outstanding financings.

14	Disclosures About Oil and Gas Producing Activities (Unaudited)

Net Capitalized Costs

The following summarizes net capitalized costs as of December 31, 2011 and 2010.

F-21

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010

	2011		2010
Oil and gas properties	$		$
Proved	37,474,949		37,235,859
Unproved	571,796		352,554
Total	38,046,745		37,588,413

Less accumulated depreciation, depletion and amortization and impairment	(21,542,440	)	(21,241,298	)

Net capitalized costs	16,504,305		16,347,115

Unproved Property Costs

The following summarizes the capitalized unproved property costs excluded from amortization as of December 31, 2011 and 2010. All costs represent investment in unproved property in Louisiana and will be evaluated over several years as the properties are explored.

	2011	2010	Prior Years		Total
	$	$	$		$
Property acquisition costs	219,242	207,952	(1,284,608	)	(857,414	)
Capitalized interest	-	-	1,429,210		1,429,210

	219,242	207,952	144,602		571,796

Costs Incurred in Oil and Gas Acquisition, Exploration and Development

	2011	2010
	$	$
Development costs	231,483	334,887
Exploration costs	-	-
Acquisition costs
Proved	226,847	-
Unproved	-	-
	458,330	334,887

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 2011 and 2010. 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-22

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010

	2011		2010
	$		$
Oil and gas sales	1,948,949		2,523,730
Operations income	49,887		54,802
Lease operating expenses	(743,531	)	(890,307	)
Production taxes	(57,955	)	(132,552	)
Depreciation, depletion and amortization	(515,083	)	(911,628	)

Results of operations from oil and gas activities, excluding corporate overhead and interest costs	682,267		644,045

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, 2011
	Oil		Gas		Total
	(Mbbl)		(Mmcf)		(Mbble)
Proved reserves, beginning of period	1,488.66		-		1,488.66
Extensions, discoveries and other additions	424.80		-		424.80
Revisions of previous estimates	118.55		318.42		171.62
Production	(18.11	)	(2.52	)	(18.53	)
Sale of reserves in place	-		-		-
Purchase of reserves in place	-		-		-

Proved reserves, end of period	2,013.90		315.90		2,066.55

Proved developed reserves:
Beginning of period	75.32		-		75.32

End of period	82.465		-		82.465

F-23

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010


	Oil		Gas		Total
December 31, 2010	(Mbbl)		(Mmcf)		(Mbble)
Proved reserves, beginning of period	1,375.52		-		1,375.52
Extensions, discoveries and other additions	-		-		-
Revisions of previous estimates	144.67		11.59		146.60
Production	(31.53	)	(11.59	)	(33.46	)
Sale of reserves in place	-		-		-
Purchase of reserves in place	-		-		-

Proved reserves, end of period	1,488.66		-		1,488.66

Proved developed reserves:
Beginning of period	103.07		-		103.07

End of period	75.32		-		75.32

The Company recognized positive revisions in the years ended December 31, 2011 and December 31, 2010. The positive revisions of 171.62 Mbble in 2011 and 146.60 Mbble in 2010 were due to positive price revisions.

Standardized Measure of Discounted Future Net Cash Flows (unaudited)

FASB ASC 932, Disclosures About Oil and Gas Producing Activities, (“ASC 932”) 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 from oil and gas reserves use the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period. 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, 2011 and December 31, 2010 were $93.69 and $77.54 per barrel for oil, respectively. There were no gas reserves at December 31, 2011 or December 31, 2010. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. Estimated future income taxes are computed using current statutory income tax rates including consideration for current tax basis of properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

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

The following sets forth our future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in ASC 932:

F-24

American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2011 and 2010

	December 31,
	2011		2010
	$		$
Future cash inflows	189,906,265		115,430,820
Future development costs	(16,322,246	)	(9,479,971	)
Future production costs	(52,668,899	)	(33,923,506	)

Net future cash flows	120,915,120		72,027,343
Less effect of a 10% discount factor	(46,693,438	)	(25,317,607	)

Standardized measure of discounted future net cash flows	74,221,682		46,709,736

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

	December 31,
	2011		2010
	$		$
Standardized measure, beginning of period	46,709,736		24,830,127
Sales of oil and gas produced, net of production costs	(1,147,464	)	(1,500,872	)
Development costs incurred	230,570		334,886
Changes in future development costs	(4,884,783	)	(1,173,713	)
Revisions of previous quantity estimates	5,318,327		4,966,233
Net change due to extensions and discoveries	10,817,741		-
Net change in prices and production costs	19,711,979		15,706,648
Changes in production rate	(6,374,696	)	(674,412	)
Purchases of properties	-		-
Accretion of discount	5,387,972		4,974,809
Other	(1,547,700	)	(753,970	)

Standardized measure, end of period	74,221,682		46,709,736

F-25

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 and Principal	March 30, 2012
Michael K. Paulk	Executive Officer and Director


/s/ Steven P. Ensz	Principal Financial	March 30, 2012
Steven P. Ensz	and Accounting Officer and Director

/s/ William Grant	Director	March 30, 2012
William Grant

/s/ Ben Shelton	Director	March 30, 2012
Ben Shelton

Attached files

American Natural Energy Corp Reports

Also read