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
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 9 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, 2010, 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, 2010, we had drilled and completed 12 (7.14 net) wells. For the year ended December 31, 2010, our combined production from all our producing wells (21 gross, 15.9 net) averaged approximately 162 (92 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 Exxon-Mobil and the lease is held by production of oil and gas on the property. The additional Couba assets we acquired include a gathering system covering approximately 25 miles located on the Bayou Couba Lease, used solely as a production collection system among the wells on the leased property leading to a product distribution point, and various production facilities, geological data, well logs and production information. The information includes 3-D seismic information completed in 1997. The seismic information relates to an area of approximately 23.5 square miles that includes the Bayou Couba Lease, among other acreage. The gathering system we acquired was initially not in operable condition. Subsequently, as part of approximately $1.1 million we expended to restore existing wells to production, we refurbished and upgraded the system so as to be usable. At present, the system, which consists of flow lines, connections and related facilities, is used to transport our production of oil and gas to points where it is trans-shipped and sold.
Our ExxonMobil Joint Development Agreement. In November 2002, we entered into a four-year joint development agreement with ExxonMobil relating to both our Couba properties and additional properties owned by ExxonMobil. The Joint Development Agreement expired by mutual agreement of all parties in March 2009.
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 TransAtlantic Agreements. In March 2003, we assigned a 10% participation interest in the ExxonMobil Corp. AMI and joint development agreement to TransAtlantic Petroleum Corp. ("TransAtlantic") in partial consideration for a $2.0 million financing. This agreement, which has a term of four years or the expiration of our agreement with ExxonMobil Corp., whichever is longer, granted to TransAtlantic the right to acquire a 10% interest in any property we acquire in the 23.5 square mile seismic survey area, including any property interests acquired through our agreement with ExxonMobil Corp.
Effective December 22, 2006, TransAtlantic sold its 10% participation interest in the AMI to Dune Energy. Dune Energy also acquired $3.0 million principal amount of our 8% Convertible Subordinated Debentures formerly held by TransAtlantic. In addition, subsequent to December 31, 2006, Dune Energy acquired from the holders an additional $4,895,000 principal amount of Debentures, bringing Dune Energy’s total holdings of our Debentures outstanding to $7,895,000 principal amount. These Debentures were acquired as part of our August 4, 2009 Purchase Agreement with Dune Energy.
As of March 31, 2011, TransAtlantic remains the beneficial holder of a total of 223,714 shares of our common stock.
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.
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.
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, 2010. Our Manager of Operations is the person primarily responsible for overseeing the preparation of the company’s reserve estimates. His qualifications include the following:
33 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, 2010 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.
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(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, 2010. 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 $77.54 per barrel of oil and $4.11 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, 2010 as there is no future income tax provision.
The future net revenue attributable to our estimated proved undeveloped reserves is calculated to be $68.6 million at December 31, 2010, with the present value thereof to be $44.0 million, based on us expending approximately $9.0 million during 2011 and an additional $449,000 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, 2010, the capital necessary to develop these additional reserves was unavailable to us. Through December 31, 2010, we had expended approximately $15.8 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, 2010, 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.
During 2010 and 2009, Behind Pipe Zones that were classified as Proved Undeveloped Reserves were re-completed at a cost of approximately $223,700 (1 well) and $323,700 (2 wells) and reclassified as Proved Developed Producing at December 31, 2010 and 2009, respectively. 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 (98 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, 2010 and 2009. All of our production was from our properties located in St. Charles Parish, Louisiana.
(1) Includes only production owned by us and produced to our interest, less royalties and production due others. 426 and 367 barrels of oil were produced in December 2010 and 2009 but not sold until January 2011 and 2010, respectively, and are included in inventory at December 31, 2010 and 2009 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:
Acreage
The following table sets forth as of December 31, 2010, 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.
(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 2010, our oil and gas sales to Texon L.P. of $2,464,419 accounted for 98% of our total oil and gas sales. We believe we are not materially dependent upon Texon 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, 2010, 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. Dune Energy carries insurance coverage covering their activities as operator of the Bayou Couba field. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks.
Employees
As of December 31, 2010, 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 300, Tulsa, Oklahoma 74136. Additionally, we maintain office space in The Woodlands, Texas. Our leased premises include approximately 4,899 square feet and are leased for various terms expiring in 2011. The annual aggregate rental is $95,531. The facilities are considered adequate for our present activities.
Item 1A
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 $2,062,145 in 2010. However, we recorded net income of $23,953,000 for the twelve months ended December 31, 2009 as the result of a $27,994,000 gain on extinguishment of debt related to the re-purchase of our 8% Secured Debentures and a settlement on debt owed to Dune Energy. We had a working capital deficiency at December 31, 2010 of approximately $6.6 million. Although production from our drilling program increased during 2010 compared to 2009, and our revenue has not been sufficient to fund our operations. At December 31, 2010, we do not have any available borrowing capacity under existing credit facilities and our current assets are $369,000 compared with current liabilities of $6.9 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 2011. All the foregoing lead to questions concerning our ability to meet our obligations as they come due. We also have a need for substantial funds to develop our oil and gas properties. We have financed our activities using private debt and equity financings, and we have no line of credit or other financing agreement providing borrowing availability with a commercial lender. As a result of the losses incurred and current negative working capital and other matters described above, there is no assurance that the carrying amounts of our assets will be realized or that liabilities will be liquidated or settled for the amounts recorded. Our ability to continue as a going concern is dependent upon adequate sources of capital and the ability to sustain positive results of operations and cash flows sufficient to pay our current liabilities and to continue to explore for and develop our oil and gas reserves.
The independent registered public accounting firm’s report on our consolidated financial statements as of and for the year ended December 31, 2010 includes an explanatory paragraph which states that we have sustained a substantial loss in 2010 and have a working capital deficiency and an accumulated deficit at December 31, 2010 that raise substantial doubt about our ability to continue as a going concern.
Our Current Liabilities as of December 31, 2010 Exceed Our Current Assets by $6.6 Million
As of December 31, 2010, our current assets were approximately $369,000 and our current liabilities were approximately $6.9 million. In order to meet our current obligations, we will need to raise additional capital. At March 31, 2011, we have no commitments from others to provide this capital and without additional capital to meet these obligations, our continued operations cannot be assured. There can be no assurance that we will be successful in raising additional capital or that the terms on which such additional capital can be raised may not be disadvantageous to the holders of our common stock or result in material dilution. Our inability to reduce our current liabilities relative to our current assets could lead creditors to refuse to extend us further credit which could materially adversely affect our operations.
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, 2010, based on the report of Summa Engineering, Inc., we claimed total estimated proved reserves of 1,488.7 Mbble of oil. Through December 31, 2010, 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 (7.14 net) wells. As of that time, our combined production from all our producing wells was approximately 108 (66 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 2010 and beyond, to differ materially from those expressed in any forward-looking statements made by or on our behalf.
Item 1B
Item 1B - Unresolved Staff Comments:
As of December 31, 2010, we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to year-end.
Item 2
Item 2 - Properties:
A description of our properties appears in Item 1 of this Annual Report on Form 10-K.
Item 3
Item 3 - Legal Proceedings:
No legal proceedings are pending against us.
Item 4
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, 2010 to a vote of security holders through the solicitation of proxies or otherwise.
PART II
Item 5
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, 2008 through March 31, 2011 were as follows.
(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.
(2)
Effective July 25, 2007, TSX Venture Exchange suspended trading in our securities as a result of the Cease Trade Order issued by the British Columbia Securities Commission. Effective November 17, 2008 TSX Venture Exchange reinstated trading in our securities.
As of March 31, 2011, we had 2,679 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, 2010.
Item 6
Item 6 - Selected Financial Data:
As a smaller reporting company, we are not required to respond to this Item.
Item 7
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 $2,062,145 in 2010. However, we recorded net income of $23,953,000 for the twelve months ended December 31, 2009 as the result of a $27,994,000 gain on extinguishment of debt related to the re-purchase of our 8% Secured Debentures and a settlement on debt owed to Dune Energy. We had a working capital deficiency at December 31, 2010 of approximately $6.6 million and an accumulated deficit at December 31, 2010 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, and we have no bank or other line of credit or other financing agreement providing borrowing availability with a commercial lender. Our cash flow from operations is sensitive to the prices we receive for our oil and natural gas in addition to the quantities of oil and natural gas we sell. A reduction in planned capital spending or an extended decline in oil and gas prices could result in less than anticipated cash flow from operations and a lessened ability to sell more of our common stock or refinance our debt with current lenders or new lenders, which would likely have a further material adverse effect on us. The uncertainty as to whether or not we can raise additional capital in the future is likely to have an effect on our future revenues and operations if we are unable to raise that additional capital.
As a result of the losses incurred and current negative working capital and other matters described above, there is no assurance that the carrying amounts of our assets will be realized or that liabilities will be liquidated or settled for the amounts recorded. Our ability to continue as a going concern is dependent upon adequate sources of capital and the ability to sustain positive results of operations and cash flows sufficient to continue to explore for and develop our oil and gas reserves. See the discussion under the caption “How We Have Financed Our Activities”.
The independent registered public accounting firm’s report on our consolidated financial statements as of and for the year ended December 31, 2010 includes an explanatory paragraph which states that we have sustained a substantial loss in 2010 and have a working capital deficiency and an accumulated deficit at December 31, 2010 that raise substantial doubt about our ability to continue as a going concern.
Statements of Operations
A Comparison of Operating Results for the Years Ended December 31, 2010 and December 31, 2009
We recorded a net loss of $2,062,145 during the year ended December 31, 2010 compared to net income of $23,953,000 during the year ended December 31, 2009. During the year ended December 31, 2010, our revenues were comprised of oil and gas sales totaling $2,523,730 compared with oil sales of $1,054,000 during the same period of 2009. Our oil sales for the twelve months ended December 31, 2010 were higher as a result of higher oil prices and an increase in volumes. Our net average daily production for the twelve month period ended December 31, 2010 increased by 109% over the same period of the prior year, from 124 (44 net) barrels of oil equivalent per day to 162 (92 net) barrels of oil equivalent per day. The increase was due to a 31% increase in gross production and the remaining increase was due to a higher net revenue interest. Oil prices increased by 14% for the twelve month period ended December 31, 2010 over the same period of the prior year from $66.04 per barrel of oil equivalent to $75.43 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 $4,640,677 for the year ended December 31, 2010 compared to income of $22,869,000 for the year ended December 31, 2009 due to a gain on the extinguishment of debt and exchange of non-monetary assets. Our general and administrative expenses increased by $143,000 for the twelve months ended December 31, 2010 compared to the same period in 2009 at $1,609,000 and $1,465,000 respectively. The increase is due to higher stock based compensation.
Interest and financing costs decreased by $96,000 for the year ended December 31, 2010 compared to the same period in 2009 at $511,000 and $607,000 respectively. Interest costs were lower as a result of a decrease in debt which was partially due to the re-purchase of our debentures during the third quarter of 2009.
Lease operating expenses of $890,000, production taxes of $133,000 and depletion, depreciation and amortization of $911,628 during the year ended December 31, 2010 changed from $760,000, $25,000, and $576,000, respectively, during the year ended December 31, 2009. Lease operating expenses increased as a result of increased production and activity level of the operator of the field and our increased working interest. Production taxes increased primarily as a result of increased production and our increased working interest. The increase in depletion, depreciation and amortization is primarily due to increased production and our increased working interest.
During the year ended December 31, 2010, we had a foreign exchange loss of $587,000, compared to a $1,687,000 foreign exchange loss for the year ended December 31, 2009. 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 loss for the twelve months ended December 31, 2010 was caused by the weakening of the US dollar against the Canadian dollar.
We incurred a charge of $14,000 for the year ended December 31, 2009 to write-down our inventory to lower of cost or market. There was no such charge for the year ended December 31, 2010.
We recorded a gain of $27,994,000 for the year ended December 31, 2009 as the result of a gain on extinguishment of debt related to the re-purchase of our 8% Secured Debentures, and a settlement on debt owed to Dune Energy. We also settled $16,000 of vendor notes payable for a net gain of $10,000. There was no such gain for the year ended December 31, 2010.
Liquidity and Capital Resources
General
At December 31, 2010, we do not have any available borrowing capacity under existing credit facilities and our current assets are $369,000 compared with current liabilities of $6.9 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 2010.
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. We expect any future capital expenditures for drilling and development to be funded from the sale of drilling participations and equity capital. It is management's plan to raise additional capital through the sale of interests in our drilling activities or other strategic transactions; however, we currently have no firm commitment from any potential investors and such additional capital may not be available to us in the future.
Years Ended December 31, 2010 and December 31, 2009
Our net cash provided by operating activities was $714,000 for the year ended December 31, 2010 as compared to net cash used in operating activities of $861,000 for the year ended December 31, 2009, an increase of $1.6 million. The increase in net cash provided by operating activities for the year ended December 31, 2010 compared to the same period of 2009 was primarily due to a loss from non-cash items for the year ended 2009. 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. Changes in working capital items had the effect of increasing cash flows from operating activities by $797,000 during the year ended December 31, 2009 due to an increase in accounts payable, partially offset by an increase in accounts receivable.
We used $335,000 of net cash in investing activities during the year ended December 31, 2010 compared to net cash used of $969,000 for the same period of 2009. The cash used in investing activities was for the purchase and development of oil and gas properties for both years.
We used $513,000 of net cash in financing activities for the year ended December 31, 2010 compared to $1.9 million of net cash provided by financing activities for the same period in 2009. For the year ended December 31, 2010, net cash outflows from financing activities were a result of payments against outstanding notes of $229,304 offset by the issuance of notes to related parties of $333,000 and incurred financing costs of $15,000. 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. In addition to proceeds from the Private Placement, we had issuance of notes payable of $1.6 million offset by payments against outstanding notes of $1.6 million during the year ended December 31, 2009.
We have no other commitments to expend additional funds for drilling activities for the rest of 2011.
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, 2010, we do not have any available borrowing capacity under existing credit facilities and our current assets are $369,000 compared with current liabilities of $6.9 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 2011. In addition, we have substantial need for capital to develop our oil and gas prospects. At December 31, 2010, we have no commitments for additional capital to fund drilling activities in 2011.
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 2011, we expect will be funded from the sale of drilling participations and equity capital. It is our intention to raise additional capital through the sale of interests in our drilling activities or other strategic transactions; however, we currently have no firm commitment from any potential investors and such additional capital may not be available to us in the future.
Our business strategy requires us to obtain additional financing and our failure to do so can be expected to adversely affect our ability to further 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, 2010 and 2009, we have a deferred tax asset of approximately $7.2 million and $6.4 million for which we have recognized a $7.2 million and $6.4 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.
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, 2010.
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
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
Item 8 - Consolidated Financial Statements and Supplementary Data:
The response to this Item is included in a separate section of this report. See page.
Item 9A(T)
Item 9A(T) - Controls and Procedures
(a) Managements Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act, as amended, as a process designed by, or under the supervision of, a company’s principal executive and principal financial officers and effected by a company’s board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of 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, 2010 in all material respects.
Item 9B
Item 9B - Other Information
No information is required to be disclosed in response to this Item 8B.
PART III
Item 10
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:
________________________
(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 23 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 23 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/ 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, 2010, 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
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, 2010 who received total compensation exceeding $100,000 for the year ended December 31, 2010 and who served in such capacities at December 31, 2010.
SUMMARY COMPENSATION TABLE
Annual Compensation
(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, 2010.
(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, 2010
The following table provides information with respect to our named executive officers above regarding outstanding equity awards held at December 31, 2010.
Director Compensation
The following table provides information with respect to compensation of our Directors during the year ended December 31, 2010. The compensation paid to our named executive officers who are also Directors is reflected in the Summary Compensation Table above.
(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, 2010.
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
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 31, 2011 (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 31, 2011, we had 13,430,608 common shares outstanding.
___________________________
(1)
This tabular information is intended to conform with Rule 13d-3 promulgated under the Securities Exchange Act of 1934 relating to the determination of beneficial ownership of securities. The tabular information gives effect to the exercise of warrants or options exercisable within 60 days of the date of this table owned in each case by the person or group whose percentage ownership is set forth opposite the respective percentage and is based on the assumption that no other person or group exercise their option.
(2)
Unless otherwise indicated, the address for each of the above is c/o American Natural Energy Corporation, 6100 South Yale, Suite 300, Tulsa, Oklahoma 74136.
(3)
The percentage of outstanding shares calculation is based upon 13,430,608 shares outstanding as of March 31, 2011, except as otherwise noted.
(4)
Includes 150,000 shares issuable at an exercise price of $0.90 on exercise of an option and 660,000 shares issuable at an exercise price of $0.30 on exercise of an option.
(5)
Includes 150,000 shares issuable at an exercise price of $0.90 on exercise of an option and 660,000 shares issuable at an exercise price of $0.30 on exercise of an option.
(6)
Includes 50,000 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 40,000 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, 2010 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
Item 13
Item 13 - Certain Relationships and Related Transactions:
On May 4, 2006, the Company entered into a note payable with Mike Paulk, an officer of the Company, in the amount of $198,000. During 2006 an additional $10,000 was loaned to the Company while $12,000 was repaid. During 2008 an additional $67,000 was loaned to the Company while $70,000 was repaid. During 2009, an additional $68,000 was loaned to the Company and the note was repaid in full in September 2009 with a payment of $261,000.
The Company paid Mike Paulk $16,000 in interest in 2009 on the loans provided to the Company.
Item 14.
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, 2010 and 2009, our independent registered public accountants at those year ends.
Our Board of Directors believes that the provision of the services during the years ended December 31, 2010 and December 31, 2009 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
Item 15 - Exhibits:
__________________________
(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, 2010.
American Natural Energy Corporation
Consolidated Financial Statements
December 31, 2010 and 2009
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of American Natural Energy Corporation Tulsa, Oklahoma
We have audited the accompanying consolidated balance sheets of American Natural Energy Corporation (the “Company”) as of December 31, 2010 and 2009 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 at December 31, 2010 and 2009, 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 2010 and has a working capital deficiency and an accumulated deficit at December 31, 2010. 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 31, 2011
AMERICAN NATURAL ENERGY CORPORATION
Consolidated Balance Sheets
The accompanying notes are an integral part of these consolidated financial statements.
AMERICAN NATURAL ENERGY CORPORATION
Consolidated Statements of Operations and Other Comprehensive Income
The accompanying notes are an integral part of these consolidated financial statements.
AMERICAN NATURAL ENERGY CORPORATION
Consolidated Statements of Changes in Stockholders’ Equity (Deficit)
The accompanying notes are an integral part of these consolidated financial statements.
AMERICAN NATURAL ENERGY CORPORATION
Consolidated Statements of Changes in Stockholders’ Equity (Deficit) (cont.)
The accompanying notes are an integral part of these consolidated financial statements.
AMERICAN NATURAL ENERGY CORPORATION
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of these consolidated financial statements.
AMERICAN NATURAL ENERGY CORPORATION
Consolidated Statements of Cash Flows (continued)
The accompanying notes are an integral part of these consolidated financial statements.
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
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 time of acquisition. Cash and cash equivalents are deposited with three institutions and the balance at either institution does not exceed the federally insured limits at December 31, 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, 2010 or 2009.
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
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 capitalized costs are assessed quarterly to determine whether it is likely such costs will be recovered in the future. To the extent there are costs which are unlikely to be recovered in the future, they are written off as impairment to the carrying value of oil and gas properties. There was no impairment recorded in 2010 or 2009.
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, 2010 and 2009, 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:
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
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, 2010 and 2009 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 Texon L.P. of $2,464,419 and $1,054,390 in 2010 and 2009, respectively, accounted for 98% and 100% of total oil and gas sales. The Company’s accounts receivable are primarily due from exploration and production companies which own an interest in the properties the Company operates and from purchasers of oil and natural gas. The industry concentration has the potential to impact the Company’s exposure to credit risk because such companies may be similarly affected by changes in economic and industry conditions.
Operations income represents charges billed to non-operator working interest owners who own a working interest in the wells in which the Company serves as operator. The income is recognized in the month in which oil and gas is produced.
Asset retirement obligations
Effective January 1, 2003, the Company adopted 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
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is reversed.
Income taxes
The Company accounts for income taxes under Statement of 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 financia1 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 $586,893 and $1,687,029 for 2010 and 2009 respectively as a result of foreign exchange translation gains and losses. As of December 31, 2010 and 2009, accumulated other comprehensive income (loss) was comprised solely of foreign currency translation gains.
Stock-based compensation
During 2010, the Company recognized compensation costs of $307,475 related to stock options issued November 30, 2010.
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
There were 2,050,000 stock options issued November 30, 2010. At December 31, 2010, there were 919,375 options outstanding and exercisable with a weighted average exercise price of $0.57. The weighted average remaining contractual term for these options at December 31, 2010 was 4.50 years. These options had no intrinsic value at December 31, 2010.
New pronouncements
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. See Note 14, “Fair Value Measurements."
In April 2010, the FASB issued ASU No. 2010-12, Accounting for Certain Tax Effects of the 2010 Health Care Reform Acts (ASU 2010-12). This update clarifies questions surrounding the accounting implications of the different signing dates of the Health Care and Education Reconciliation Act (signed March 30, 2010) and the Patient Protection and Affordable Care Act (signed March 23, 2010). ASU 2010-12 states that the FASB and the Office of the Chief Accountant at the SEC would not be opposed to view the two Acts together for accounting purposes. The adoption of ASU 2010-12 did not impact the Company's operating results, financial position, cash flows or disclosures.
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
Reclassification of Prior Period Statements
Certain reclassifications of prior period consolidated financial statements balances have been made to conform to current reporting practices.
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 $2,062,145 in 2010. The Company has a working capital deficiency and an accumulated deficit at December 31, 2010 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.
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.
Oil and Gas Properties
As part of the transactions with Dune Energy on August 4, 2009, the Company acquired Dune’s interest in producing wells and certain leasehold rights in the Bayou Couba field and assumed operations of the Bayou Couba field. As part of the consideration in exchange, the Company assigned to Dune a portion of certain deep leasehold rights it held. The fair value of the assets acquired was $13,806,799. (Note 16)
In December 2009 the Company completed 8 agreements for the purchase of 5.875% of the working interest in the Company’s Bayou Couba field. Each agreement provided for the purchase of all interests held by the selling party and was for a collective purchase price of approximately $175,000 which included cash of $161,000, netting outstanding joint interest billings of $34,000 against revenues owed of $20,000, and the issuance of 325,000 shares of the common shares of the Company.
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
On December 31, 2009 the Company completed the purchase of 93.4% of the Couba Operating Company Liquidation Agent overriding royalty interest for approximately $315,000. The acquisition of this burden amounted to a 2.547% overriding royalty interest on all of the Company’s current and future producing properties.
Equipment and other fixed assets
The carrying value of equipment and other fixed assets as of December 31, 2010 and 2009 included the following components:
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 2010 and 2009 are shown below.
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
The revision in 2010 of $930,595 is due to a change in the plug and abandon timing. The addition in 2009 of $497,066 includes a $36,718 reduction due to change in the plug and abandon timing and $533,784 addition due to change in the working interest after settlement on debt owed to Dune Energy, see Note 8, and purchase of working interests from other interest owners in the Bayou Couba field.
Notes payable and long-term debt
Notes payable and long-term debt as of December 31, 2010 and 2009 consisted of the following:
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. As of December 31, 2010 $19,930 is outstanding and $6,643 is past due.
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. All accrued interest is payable monthly and the maturity date of the loan is April 30, 2011. 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. Payments of $51,745 were made during the year ended 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.
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
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. See additional details in Note 15.
On January 20, 2010, the Company and TPC Energy entered into a note payable whereas TPC Energy agrees to advance up to $210,000 in addition to the $450,000 note issued during fiscal year 2009. Interest on the note accrues at 10% per annum and is payable monthly. Principal payments are to be paid monthly commencing March 31, 2010 at a rate of 75% of the net cash flow received from production of the recompleted DSCI 111 well. The Company agreed it will not encumber or sell its interest in this well as long as the principal balance is unpaid. Upon payout of the principal and interest, the Company shall assign 25% interest in this well to TPC Energy. In January 2010, the Company borrowed $208,892 from TPC Energy. Based on the relative fair value of the well, a discount on the note of $108,141 was recorded. The discount will be amortized over the life of the loan using the effective interest rate method. In June 2010, the Company borrowed $100,000 from TPC Energy with an interest rate of 10% per annum. Principal and interest was due on December 31, 2010. During the year ended December 31, 2010, the Company paid a total of $599,558 to TPC Energy. The TPC note is included in Notes Payable - Related Parties on the balance sheet as of December 31, 2010 and December 31, 2009.
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 March 31, 2011. 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 US$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. 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.
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 the 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.
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
The Company re-purchased its remaining outstanding 8% Secured Debenture debt totalling $2.93 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 fair market price of US$0.30 per share. The issuance of the shares occurred during the third quarter of 2009. The gain on the settlement of the debenture was $3.14 million.
Common stock
In March 2009, the Company granted 106,000 common shares as payment for an outstanding invoice in the amount of $10,600. The fair value of the shares was $0.30 cents per share for a total of $10,600. No gain or loss was recognized in this transaction.
In June and July 2009, the Company granted 1,165,674 common shares of the Company’s common stock which were issued at a fair value of $0.30 per share for partial retirement of the Company’s 8% Secured Debentures.
In December 2009, the Company granted 160,000 common shares to a group of lenders as a share bonus for the bridge loan related to the acquisition of the ORI. The relative fair value of these shares of $42,585 was recorded as a discount on the bridge loan.
During 2009, the Company issued 6,666,667 common shares through a Private Placement at a price of $0.30 per share for total proceeds of $2.0 million. Private placement costs of $96,839 were recorded as a reduction to additional paid-in capital.
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 and the Company’s outstanding shares of common stock was reduced to approximately 13,430,608 from 134,306,080 shares.
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.
Stock option activity for the years ended December 31, 2010 and 2009 is as follows:
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
At December 31, 2010 and 2009, 919,375 and 174,375 options have vested and are exercisable at a weighted average exercise price of $0.57 and $0.90, respectively. The weighted average remaining contractual life of options granted at December 31, 2010 and 2009 is 57 months. There is no intrinsic value for the exercisable stock options at December 31, 2010.
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, 2010, the Company recognized compensation costs of $307,475 related to stock options granted. At December 31, 2010, there was $490,330 of total unrecognized compensation costs related to non-vested stock options which will be recognized over a weighted average period of approximately 10 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:
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
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.
Warrants
Warrant activity for the years ended December 31, 2010 and 2009 is as follows:
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.
Commitments and contingencies
The Company rents office space under a long-term operating lease that expires December 2011. At December 31, 2010, the future minimum lease payments required under the operating lease amounted to $96,000 and is to be paid in 2011.
Rent expense on all operating leases amounted to approximately $89,000 and $93,000 in 2010 and 2009, 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.
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
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.
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 $65,000 remains unpaid at December 31, 2010.
The Company, as an owner or lessee of oil and gas properties, is subject to various federal, states and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations, may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks.
Related Party Transactions
The Company borrowed an additional $68,000 during 2009 from Mike Paulk, an officer of the Company. The note payable was later repaid in full with a payment of $261,000. The Company paid Mike Paulk $16,000 for interest on the loans provided to the Company.
As part of the Private Placement of common shares during 2009, Steven P. Ensz, an officer and director of the Company and Brian Bayley, a director of the Company each purchased 250,000 shares at the issue price of US $0.30 per share for a total of US $150,000.
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, 2010 and 2009 are presented below:
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
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, 2010 and 2009 are summarized as follows:
As of December 31, 2010, the Company has a net operating loss carry-forward benefit of approximately $10.2 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.
Fair Value Measurements
As defined in ASC 820-Fair Value Measurements and Disclosures, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). This statement requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. The statement requires fair value measurements be classified and disclosed in one of the following categories:
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
Level 1 - Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Quoted prices in markets that are not active or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3 - Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). This category includes the proved property acquired from Dune as part of the settlement of the 8% Secured Debentures held by Dune (see Note 7) that we valued using the present value of the future cash flows of the proved reserves discounted at 10 percent. Substantially all of these inputs are observable in the marketplace throughout the full term of the proved properties, can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
As required by ASC 820, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table summarizes the valuation of our investments and financial instruments by ASC 820 pricing levels as of December 31, 2009. There was no fair value measurement for 2010 related to this transaction, since this was a one-time transaction that occurred in 2009.
Subsequent Events
Pursuant to FASB ASC 855, the Company evaluated all events or transactions that occurred from January 1, 2011 through March 31, 2011, 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:
On February 17, 2011, the Company entered into a $500,000 unsecured short-term note with interest at the rate of 10% per annum with Michael Paulk and Steven Ensz, officers and directors of the Company. All accrued interest is payable monthly and the maturity date of the loan is February 15, 2012. Proceeds of from the note were used to pay the outstanding obligation to Bank of Oklahoma and the balance for working capital.
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
Disclosures About Oil and Gas Producing Activities (Unaudited)
Net Capitalized Costs
The following summarizes net capitalized costs as of December 31, 2010 and 2009.
Unproved Property Costs
The following summarizes the capitalized unproved property costs excluded from amortization as of December 31, 2010 and 2009. All costs represent investment in unproved property in Louisiana and will be evaluated over several years as the properties are explored.
Costs Incurred in Oil and Gas Acquisition, Exploration and Development
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
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 2010 and 2009. 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.
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, 2010
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
December 31, 2009
The Company has recognized positive revisions in the years ended December 31, 2010 and December 31, 2009. The positive revisions of 146.60 Mbble in 2010 and 450.37 Mbble in 2009 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, 2010 and December 31, 2009 were $77.54 and $58.83 per barrel for oil, respectively. There were no gas reserves at December 31, 2010 or December 31, 2009. 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.
American Natural Energy Corporation
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
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:
The principal sources of change in the standardized measure of discounted future net cash flows are as follows:
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
American Natural Energy Corporation
By: /s/ Michael K. Paulk
Michael K. Paulk, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated.
Signature Title Date
/s/ Michael K. Paulk President (Principal March 31, 2011
Michael K. Paulk Executive Officer) and Director
/s/ Steven P. Ensz Director and Principal Financial March 31, 2011
Steven P. Ensz and Accounting Officer
/s/ William Grant Director March 31, 2011
William Grant
/s/ Ben Shelton Director March 31, 2011
Ben Shelton