10-K 1 jan0910k6-09.txt SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (Mark One) (X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended January 31, 2009 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File No. - None ENERGAS RESOURCES, INC. -------------- ------------------------ (Name of Small Business Issuer in its charter) Delaware 73-1620724 ---------------------------------- ------------------------------------ (State or other jurisdiction (I.R.S. Employer Identification No.) of incorporation or organization) 800 Northeast 63rd Street Oklahoma City, Oklahoma 73105 --------------------------------------- -------- (Address of Principal Executive Office) Zip Code Registrant's telephone number, including Area Code: (405) 879-1752 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: Common Stock Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. [ ] Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. [ ] Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. Large accelerated filer [ ] Accelerated filer [ ] Non-accelerated filer [ ] Smaller reporting company [X] (Do not check if a smaller reporting company) Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act): [ ] Yes [X] No The aggregate market value of the voting stock held by non-affiliates of the Company on April 30, 2009 was approximately $3,665,000. As of April 30, 2009, the Company had 91,150,144 issued and outstanding shares of common stock. Documents incorporated by reference: None CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION This report includes "forward-looking statements". All statements other than statements of historical facts included in this report, regarding the Company's financial position, reserve quantities and net present values, business strategy, plans and objectives of management of the Company for future operations and capital expenditures, are forward-looking statements. Although the Company believes that the expectations reflected in the forward-looking statements and the assumptions upon which such forward-looking statements are based are reasonable, it can give no assurance that such expectations and assumptions will prove to have been correct. Reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. GLOSSARY The following terms are used throughout this report: BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, usually used herein in reference to crude oil or other liquid hydrocarbons. BTU. A British thermal unit which is the amount of heat required to raise the temperature of one avoirdupois pound of pure water form 58.5 degrees to 59.5 degrees Fahrenheit under standard conditions. DEVELOPED ACREAGE. The number of acres which are allocated or assignable to producing wells or wells capable of production. DEVELOPMENT WELL. A well drilled as an additional well to the same reservoir as other producing wells on a Lease, or drilled on an offset Lease not more than one location away from a well producing from the same reservoir. EXPLORATORY WELL. A well drilled in search of a new undiscovered pool of oil or gas, or to extend the known limits of a field under development. GROSS ACRES OR WELLS. A well or acre in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. LEASE. Full or partial interests in an oil and gas lease, authorizing the owner thereof to drill for, reduce to possession and produce oil and gas upon payment of rentals, bonuses and/or royalties. Oil and gas leases are generally acquired from private landowners and federal and state governments. The term of an oil and gas lease typically ranges from three to ten years and requires annual lease rental payments of $1.00 to $2.00 per acre. If a producing oil or gas well is drilled on the lease prior to the expiration of the lease, the lease will generally remain in effect until the oil or gas production from the well ends. The Company is required to pay the owner of the leased property a royalty which is usually between 12.5% and 16.6% of the gross amount received from the sale of the oil or gas produced from the well. MCF. One thousand cubic feet. MCFE. Equivalent cubic feet of gas, using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. NET ACRES OR WELLS. A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres expressed as whole numbers and fractions. 3 OPERATING COSTS. The expenses of producing oil or gas from a formation, consisting of the costs incurred to operate and maintain wells and related equipment and facilities, including labor costs, repair and maintenance, supplies, insurance, production, severance and other production excise taxes. PRODUCING PROPERTY. A property (or interest therein) producing oil or gas in commercial quantities or that is shut-in but capable of producing oil or gas in commercial quantities, to which Producing Reserves have been assigned. Interests in a property may include Working Interests, production payments, Royalty Interests and other non-working interests. PRODUCING RESERVES. Proved Developed Reserves expected to be produced from existing completion intervals open for production in existing wells. PROSPECT. An area in which a party owns or intends to acquire one or more oil and gas interests, which is geographically defined on the basis of geological data and which is reasonably anticipated to contain at least one reservoir of oil, gas or other hydrocarbons. PROVED DEVELOPED RESERVES. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery may be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. PROVED RESERVES. Proved oil and gas reserves are 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 existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation testing. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. 4 (iii) Estimates of proved reserves do not include the following: (a) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves", (b) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (c) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (d) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. PROVED UNDEVELOPED RESERVES. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves are not attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. ROYALTY INTEREST. An interest in an oil and gas property entitling the owner to a share of oil and gas production free of Operating Costs. UNDEVELOPED ACREAGE. Lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves. Undeveloped acreage should not be confused with undrilled acreage which is "Held by Production" under the terms of a lease. WORKING INTEREST. The operating interest under a Lease which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all Royalty Interests and other burdens and to all costs of exploration, development and operations and all risks in connection therewith. ITEM 1. DESCRIPTION OF BUSINESS The Company was incorporated under the laws of British Columbia, Canada on November 2, 1989 and on August 20, 2001 the Company became domesticated and incorporated in Delaware. The Company is involved in the exploration and development of oil and gas. The Company's activities are primarily dependent upon available financial resources to fund the costs of drilling and completing wells. The Company evaluates undeveloped oil and gas prospects and participates in drilling activities on those prospects which in the opinion of management are favorable for the production of oil or gas. If, through its review, a geographical area indicates geological and economic potential, the Company attempts to acquire Leases or other interests in the area and assemble a 5 Prospect. The Company normally sells portions of its leasehold interests in a Prospect to unrelated third parties, thus sharing risks and rewards of the exploration and development of the Prospect with the joint owners pursuant to an operating agreement. One or more Exploratory Wells may be drilled on a Prospect, and if the results indicate the presence of sufficient oil and gas reserves, additional Development Wells may be drilled on the Prospect. The Company typically seeks potential joint venture partners for development of its Prospects. In June 2007 and January 2008 the Company sold its oil and gas properties in Kentucky. For financial statement purposes, due to the uncertainty of collection, the January 2008 sale was shown as "Properties Held For Resale" as of January 1, 2008. This accounting treatment was re-evaluated as of October 31, 2008 based on more current information and was characterized as a note receivable. See Item 7 of this report for more information concerning the sale of these properties. In April 2008 the Company sold its interest in the Ainsworth #1-33 well, located in Pittsburgh County, OK, for $615,000 and incurred sales expenses of $24,600. During the year ended January 31, 2009 the Company advanced $660,826 to a third party for drilling and completing a well in Niobrara County, Wyoming. As of April 30, 2009 this well was not producing and temporarily abandoned. In January 2009 the Company acquired Energas Pipeline Company and Energas Corp. from George Shaw, the Company's President, for 6,167,400 shares of the Company's common stock. Energas Pipeline Company operates the natural gas gathering system which is connected to the Company's three wells in Atoka County, Oklahoma. Energas Corp. operates all of the Company's wells and holds the bonds required by state oil and gas regulatory authorities. In March 2009 the Company acquired a 14 mile natural gas gathering system in exchange for 1,000,000 shares of the Company's common stock. The gathering system, located in Callahan County, Texas, will be used to transport any gas, produced from wells which may be drilled on the Company's leases in Texas, to the Enbridge Gas Company pipeline. The Company principally operates in the Arkoma Basin in Oklahoma and the Powder River Basin in Wyoming, and more recently in Texas. The Company's corporate offices are located at 800 Northeast 63rd Street, Third Floor, Oklahoma City, Oklahoma 73105 and its telephone number is (405) 879-1752. The Company's web site is www.energasresources.com. DRILLING ACTIVITIES AND PROVEN RESERVES During the periods indicated, the Company drilled or participated in the drilling of the following wells: 6 Year Ended January 31, -------------------------------------------------------- 2006 2007 2008 2009 ---- ---- ---- ---- Gross Net Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- ----- --- Exploratory Wells (1): Productive: Oil -- -- -- -- -- -- -- -- Gas -- -- -- -- -- -- -- -- Nonproductive 1 .24 -- -- 1 .422 -- -- Development Wells (1): Productive: Oil 1 .137 -- -- -- -- -- -- Gas 3 2.625 -- -- -- -- -- -- Nonproductive 1 .137 -- -- -- -- 1 .53 Total Wells (1): Productive: Oil 1 .137 -- -- -- -- -- -- Gas 3 2.625 -- -- -- -- -- -- Nonproductive 2 .377 -- -- 1 .422 1 .53 (1) Each well completed to more than one producing zone is counted as a single well. The Company has royalty interests in certain wells that are not included in this table. In May 2003 the Company arranged with a private investor to fund the drilling of two natural gas wells in the Arkoma Basin of eastern Oklahoma. The two wells were drilled in June 2003 and one well was successfully completed as a gas well and the other well was a dryhole. The Company will receive approximately 5% of the production from the productive well, after payment of the Company's share of operating expenses, until the investor is repaid the amounts advanced to drill and complete the wells, which were approximately $490,000. After the amount advanced by the investor has been repaid, the Company will receive approximately 25% of the production from the well after payment of the Company's share of operating expenses The following table shows, as of April 30, 2009, by state and basin, the Company's producing wells, Developed Acreage, and Undeveloped Acreage, excluding service (injection and disposal) wells: Productive Wells (1) Developed Acreage Undeveloped Acreage (2) Gross Net Gross Net Gross Net Oklahoma 3 1.004 -- -- -- -- Wyoming 1 .358 40 .143 600 214.8 Texas -- -- -- -- 2,560 1,024 Totals 4 1.362 40 .143 3,160 1,238.8 7 (1) The wells in Oklahoma are gas wells and the wells in Wyoming are oil wells. (2) "Undeveloped Acreage" includes leasehold interests on which wells have not been drilled or completed to the point that would permit the production of commercial quantities of natural gas and oil regardless of whether the leasehold interest is classified as containing proved undeveloped reserves. (3) For its Oklahoma wells, the Company's interest is limited to the well bores only. The following table shows, as of April 30, 2009 the status of Company's gross acreage. Held by Production Not Held by Production Oklahoma -- -- Wyoming 640 -- Texas -- 2,560 (1) For its Oklahoma wells, the Company's interest is limited to the well bores only. Acres Held By Production remain in force so long as oil or gas is produced from the well on the particular lease. Leased acres which are not Held By Production require annual rental payments to maintain the lease until the first to occur of the following: the expiration of the lease or the time oil or gas is produced from one or more wells drilled on the lease acreage. At the time oil or gas is produced from wells drilled on the leased acreage the lease is considered to be Held By Production. The Company owns a 2% Overriding Royalty Interests in the Texas leased acreage. Title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and gas 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, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). Drilling title opinions or other investigative title activities are always performed before commencement of drilling operations; however, as is customary in the industry. The following table shows the Company's net production of oil and gas, average sales prices and average production costs during the periods presented: Year Ended January 31, ----------------------------- Production Data: 2007 2008 2009 ---- ---- ---- Production - Oil (Bbls) 1,417 1,499 1,147 Gas (Mcf) 97,836 59,491 28,157 Average sales price - Oil (Bbls) $47.67 $56.48 $81.02 Gas (Mcf) $ 6.04 $ 5.88 $ 6.35 Average production costs per MCFE $ 2.43 $ 2.90 $ 1.38 8 Production costs may vary substantially among wells depending on the methods of recovery employed and other factors, but generally include severance taxes, administrative overhead, maintenance and repair, labor and utilities. The Company is not obligated to provide a fixed and determined quantity of oil or gas in the future. During the last three fiscal years, the Company has not had, nor does it now have, any long-term supply or similar agreement with any government or governmental authority. Below are estimates of the Company's net Proved Reserves and the present value of estimated future net revenues from such Reserves based upon the standardized measure of discounted future net cash flows relating to proved oil and gas reserves in accordance with the provisions of Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities" (SFAS No. 69). The standardized measure of discounted future net cash flows is determined by using estimated quantities of Proved Reserves and the periods in which they are expected to be developed and produced based on period-end economic conditions. The estimated future production is priced at period-end prices, except where fixed and determinable price escalations are provided by contract. The resulting estimated future cash inflows are then reduced by estimated future costs to develop and produce reserves based on period-end cost levels. No deduction has been made for depletion, depreciation or for indirect costs, such as general corporate overhead. Present values were computed by discounting future net revenues by 10% per year. January 31, ----------------------------------------------------- 2007 2008 2009 --------------- --------------- --------------- Oil Gas Oil Gas Oil Gas (Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) Proved reserves 22,143 1,942,040 53,909 746,499 5,644 378,759 Estimated future net cash flows from proved oil and gas reserves $7,383,384 $3,865,249 $730,682 Present value of future net cash flows from proved oil and gas reserves $4,416,660 $2,077,673 $357,270 The Company's Proved Reserves include only those amounts which the Company reasonably expects to recover in the future from known oil and gas reservoirs under existing economic and operating conditions, at current prices and costs, under existing regulatory practices and with existing technology. Accordingly, any changes in prices, operating and development costs, regulations, technology or other factors could significantly increase or decrease estimates of Proved Reserves. In general, the volume of production from natural gas and oil properties owned by the Company declines as reserves are depleted. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities, or both, the proved reserves 9 of the Company will decline as reserves are produced. Volumes generated from future activities of the Company are therefore highly dependent upon the level of success in acquiring or finding additional reserves and the costs incurred in doing so. GOVERNMENT REGULATION Various state and federal agencies regulate the production and sale of oil and natural gas. All states in which the Company plans to operate impose restrictions on the drilling, production, transportation and sale of oil and natural gas. Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission (the "FERC") regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. The FERC's jurisdiction over interstate natural gas sales has been substantially modified by the Natural Gas Policy Act under which the FERC continued to regulate the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce. The Natural Gas Wellhead Decontrol Act (the "Decontrol Act") deregulated natural gas prices for all "first sales" of natural gas. Because "first sales" include typical wellhead sales by producers, all natural gas produced from natural gas properties is sold at market prices, subject to the terms of any private contracts which may be in effect. The FERC's jurisdiction over natural gas transportation is not affected by the Decontrol Act. The Company's sales of natural gas will be affected by intrastate and interstate gas transportation regulations which are designed to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesale marketers of natural gas to the primary role of gas transporters. All natural gas marketing by the pipelines is required to divest to a marketing affiliate, which operates separately from the transporter and in direct competition with all other merchants. Pipelines must provide open and nondiscriminatory transportation and transportation-related services to all producers, natural gas marketing companies, local distribution companies, industrial end users and other customers seeking service. FERC has pursued other policy initiatives that have affected natural gas marketing. Most notable are (1) the large-scale divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies; (2) further development of rules governing the relationship of the pipelines with their marketing affiliates; (3) the publication of standards relating to the use of electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information on a timely basis and to enable transactions to occur on a purely electronic basis; (4) further review of the role of the secondary market for released pipeline capacity and its relationship to open access service in the primary market; and (5) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates) for transportation or transportation-related services upon the pipeline's demonstration of lack of market control in the relevant service market. The 10 Company does not know what effect the FERC's other activities will have on the access to markets, the fostering of competition and the cost of doing business. As a result of these changes, sellers and buyers of natural gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counter parties. The Company believes these changes generally have improved the access to markets for natural gas while, at the same time, substantially increasing competition in the natural gas marketplace. The Company cannot predict what new or different regulations the FERC and other regulatory agencies may adopt or what effect subsequent regulations may have on production and marketing of natural gas from the Company's properties. In the past, Congress has been very active in the area of natural gas regulation. However, as discussed above, the more recent trend has been in favor of deregulation and the promotion of competition in the natural gas industry. Thus, in addition to "first sales" deregulation, Congress also repealed incremental pricing requirements and natural gas use restraints previously applicable. There are other legislative proposals pending in the Federal and State legislatures which, if enacted, would significantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, these proposals might have on the production and marketing of natural gas by the Company. Similarly, and despite the trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue or what the ultimate effect will be on the production and marketing of natural gas by the Company cannot be predicted. The Company's sales of oil and natural gas liquids will not be regulated and will be at market prices. The price received from the sale of these products will be affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. FERC regulates interstate transportation rates and adjusts these rates annually based on the rate of inflation, subject to certain conditions and limitations. Every five years, the FERC examines the relationship between the annual change in the applicable index and the actual cost changes experienced by the oil pipeline industry. The Company is not able to predict with certainty what effect, if any, these federal regulations or the periodic review of the index by the FERC will have. Federal, state, and local agencies have promulgated extensive rules and regulations applicable to the Company's oil and natural gas exploration, production and related operations. Most states require permits for drilling operations, drilling bonds and the filing of reports concerning operations and impose other requirements relating to the exploration of oil and natural gas. Many states also have statutes or regulations addressing conservation matters including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of some states limit the rate at which oil and natural gas is produced from the Company's properties. The federal and state regulatory burden on the oil and natural gas industry increases the Company's cost of doing business and affects its profitability. Because these 11 rules and regulations are amended or reinterpreted frequently, the Company is unable to predict the future cost or impact of complying with those laws. COMPETITION AND MARKETING The Company will be faced with strong competition from many other companies and individuals engaged in the oil and gas business, many are very large, well established energy companies with substantial capabilities and established earnings records. The Company may be at a competitive disadvantage in acquiring oil and gas prospects since it must compete with these individuals and companies, many of which have greater financial resources and larger technical staffs. It is nearly impossible to estimate the number of competitors; however, it is known that there are a large number of companies and individuals in the oil and gas business. Exploration for and production of oil and gas are affected by the availability of pipe, casing and other tubular goods and certain other oil field equipment including drilling rigs and tools. The Company depends upon independent drilling contractors to furnish rigs, equipment and tools to drill its wells. Higher prices for oil and gas may result in competition among operators for drilling equipment, tubular goods and drilling crews which may affect the Company's ability expeditiously to drill, complete, recomplete and work-over its wells. However, the Company has not experienced and does not anticipate difficulty in obtaining supplies, materials, drilling rigs, equipment or tools. The Company does not refine or otherwise process crude oil and condensate production. Substantially all of the crude oil and condensate production from the Company's well is sold at posted prices under short-term contracts, which is customary in the industry. The market for oil and gas is dependent upon a number of factors beyond the Company's control, which at times cannot be accurately predicted. These factors include the proximity of wells to, and the capacity of, natural gas pipelines, the extent of competitive domestic production and imports of oil and gas, the availability of other sources of energy, fluctuations in seasonal supply and demand, and governmental regulation. In addition, there is always the possibility that new legislation may be enacted which would impose price controls or additional excise taxes upon crude oil or natural gas, or both. Oversupplies of natural gas can be expected to recur from time to time and may result in the gas producing wells being shut-in. Increased imports of natural gas, primarily from Canada, have occurred and are expected to continue. Such imports may adversely affect the market for domestic natural gas. The market price for crude oil is significantly affected by policies adopted by the member nations of Organization of Petroleum Exporting Countries ("OPEC"). Members of OPEC establish prices and production quotas among themselves for petroleum products from time to time with the intent of controlling the current global supply and consequently price levels. The Company is unable to predict the effect, if any, that OPEC or other countries will have on the amount of, or the prices received for, crude oil and natural gas produced and sold from the Company's wells. 12 Gas prices, which were once effectively determined by government regulations, are now largely influenced by competition. Competitors in this market include producers, gas pipelines and their affiliated marketing companies, independent marketers, and providers of alternate energy supplies, such as residual fuel oil. Changes in government regulations relating to the production, transportation and marketing of natural gas have also resulted in significant changes in the historical marketing patterns of the industry. Generally, these changes have resulted in the abandonment by many pipelines of long-term contracts for the purchase of natural gas, the development by gas producers of their own marketing programs to take advantage of new regulations requiring pipelines to transport gas for regulated fees, and an increasing tendency to rely on short-term contracts priced at spot market prices. GENERAL The Company has never been a party to any bankruptcy, receivership, reorganization, readjustment or similar proceedings. Since the Company is engaged in the oil and gas business, it does not allocate funds to product research and development in the conventional sense. The Company does not have any patents, trade-marks, or labor contracts. With the exception of the Company's oil and gas leases, the Company does not have any licenses, franchises, concessions or royalty agreements. Backlog is not material to an understanding of the Company's business. The Company's business is not subject to renegotiation of profits or termination of contracts or subcontracts at the election of federal government. As of April 30, 2009, the Company employed four people. The Company's employees work in management, engineering, and accounting. In addition, 2 contract workers were responsible for the supervision and operation of the Company's field activities and providing well services. ITEM 1A. RISK FACTORS Not applicable. ITEM 1B. UNRESOLVED STAFF COMMENTS Not applicable. ITEM 2. PROPERTIES See Item 1 of this report for information concerning the Company's oil and gas properties. The Company's offices are located at 800 Northeast 63rd Street, Oklahoma City, Oklahoma and consist of 4,800 square feet which is rented on a month-to-month basis for $4,000 per month. The building is owned by George G. Shaw, the Company's Chief Executive Officer and a Director. 13 ITEM 3. LEGAL PROCEEDINGS The Company is not involved in any legal proceedings. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not applicable ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASE OF EQUITY SECURITIES. The Company's common stock is listed on the OTC Bulletin Board under the symbol EGSR. The following table shows the high and low sale prices of the Company's common stock during the periods presented as reported by the NASD. The closing sale prices reflect inter-dealer prices without adjustment for retail markups, markdowns or commissions and may not reflect actual transactions. Closing Sale Price Common Stock Quarter Ended High Low April 30, 2006 $0.44 $0.40 July 31, 2006 $0.14 $0.13 October 31, 2006 $0.08 $0.07 January 31, 2007 $0.04 $0.03 April 30, 2007 $0.05 $0.02 July 31, 2007 $0.05 $0.02 October 31, 2007 $0.04 $0.02 January 31, 2008 $0.04 $0.02 April 30, 2008 $0.04 $0.03 July 31, 2008 $0.04 $0.03 October 31, 2008 $0.15 $0.04 January 31, 2009 $0.11 $0.01 As of April 30, 2009 there were approximately 1,400 holders of the Company's common stock. The market price of the Company's common stock is subject to significant fluctuations in response to, and may be adversely affected by (i) variations in quarterly operating results, (ii) developments in the oil and gas industry generally and more particularly within the geographically and geological areas that the Company owns and operates properties, and (iii) general stock market conditions. 14 The Company's common stock is subject to the "penny stock" rules. The penny stock trading rules impose additional duties and responsibilities upon broker-dealers and salespersons recommending the purchase or sale of a penny stock. Required compliance with these rules will materially limit or restrict the ability to resell the Company's common stock, and the liquidity typically associated with other publicly traded stocks may not exist. During the year ended January 31, 2009 neither the Company, any officer or director of the Company, nor any principal shareholder purchased any shares of the Company's common stock either from the Company, from third parties in a private transaction, or as a result of purchases in the open market. In January 2009 the Company acquired Energas Pipeline Company and Energas Corp. from George Shaw, the Company's President, for 6,167,400 restricted shares of the Company's common stock. Energas Pipeline Company operates the natural gas gathering system which is connected to the Company's three wells in Atoka County, Oklahoma. Energas Corp. operates all of the Company's wells and holds the bonds required by state oil and gas regulatory authorities. The Company relied upon the exemption provided by Section 4(2) of the Securities Act of 1933 in connection with the issuance of these shares. As of April 30, 2009 the Company did not have any outstanding options, warrants or other securities convertible into common stock. As of April 30, 2009 the Company did not have any outstanding options, warrants or other securities convertible into common stock. ITEM 6. SELECTED FINANCIAL DATA Not applicable. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion of financial condition and results of operations should be read in conjunction with the consolidated financial statements and the notes to the consolidated financial statements, which are included elsewhere in this report. The factors that most significantly affect the Company's results of operations are (i) the sale prices of crude oil and natural gas, (ii) the amount of production sales, (iii) the amount of lease operating expenses, and (iv) the level of interest rates on, and amount of, borrowings. Sales of production and level of borrowings are significantly impacted by the Company's ability to maintain or increase its production from existing oil and gas properties through its exploration and development activities. The following table reflects the average prices received by the Company for oil and gas, the average production cost per BOE, and the amount of oil and gas produced for the periods presented: 15 Year Ended January 31, ------------------------------ Production Data: 2007 2008 2009 ---- ---- ---- Production - Oil (Bbls) 1,417 1,499 1,147 Gas (Mcf) 97,836 59,491 28,157 Average sales price - Oil (Bbls) $ 47.67 $ 56.48 $ 81.02 Gas (Mcf) $ 6.04 $ 5.88 $ 6.35 Average production costs per MCFE $ 2.43 $ 2.90 $ 1.38 Prices received by the Company for sales of crude oil and natural gas have fluctuated significantly from period to period. The fluctuations in oil prices during these periods reflect market uncertainty regarding the inability of the Organization of Petroleum Exporting Countries ("OPEC") to control the production of its member countries, as well as concerns related to the global supply and demand for crude oil. Gas prices received by the Company fluctuate with changes in the spot market price for gas. Changes in natural gas and crude oil prices will significantly affect the revenues and cash flow of the wells and the value of the oil and gas properties. Declines in the prices of crude oil and natural gas could have a material adverse effect on the success of the Company's operations and activities, recoupment of the costs of acquiring, developing and producing the wells and profitability. The Company is unable to predict whether the prices of crude oil and natural gas will rise, stabilize or decline in the future. In January 2007 the Company entered into an agreement with an unrelated third party for the sale of all its Pulaski County, Kentucky properties, gathering systems and equipment for $1,735,000. As of January 31, 2007 the Company had received cash payments of $557,000 from the third party of which $200,000 was for the sale of certain royalty rights held by the Company and $357,000 represented a deposit on the sale of the remainder of properties, gathering systems, and equipment. The sale of the royalties was completed on January 25, 2007 and the sale was treated as a reduction in the carrying amount of the oil and gas properties in accordance with the full cost method of accounting for oil and gas properties. The remainder of the sale closed on June 1, 2007 and the $357,000 received was recorded as a deposit as of January 31, 2007. On January 1, 2008 the Company sold its remaining oil and gas properties in Kentucky, as well as its gathering systems, pipelines and equipment, for $2,300,000. For the sale of these assets, the Company received a $100,000 deposit and a non-recourse promissory note for $2,200,000. At the time of the transaction, current production levels indicated that significant funds would need to be invested in the properties to fully develop anticipated reserves and thereby generate revenues sufficient to repay the promissory note. Due to this uncertainty, management determined to characterize the promissory note as `properties held for resale' on the balance sheet. Accordingly, the $100,000 payment was treated as a deposit. During the quarter 16 ended October 31, 2008 management determined, based on more current information, that the transaction should be re-characterized as a note receivable and all payments received since the transaction date characterized as principal and interest payments in accordance with the debt instrument. At the same time, an evaluation of collectibility led management to record an allowance for doubtful collection of $1,162,020. The Company collected another $236,000 in note payments before December, 2008. In December 2008 the maker of the non-recourse note filed a petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code. On February 27, 2009 the Company sold the non-recourse note to an unrelated third party for $950,000. In April 2008 the Company sold its interest in the Ainsworth #1-33 well, located in Pittsburgh County, OK, for $615,000 and incurred sales expenses of $24,600. During the year ended January 31, 2009 the Company advanced $660,826 to a third party for drilling and completing a well in Niobrara County, Wyoming. As of April 30, 2009 this well was temporarily abandoned. In November 2008 the Company entered into an agreement with Excalibur, Inc., an unrelated third party, for the exploration and development of oil and gas leases covering 1,560 acres in Callahan County, Texas. The Agreement provides that the Company will pay the costs to drill and complete five wells on the leased acreage. If any of the five wells are completed as a producing well, Excalibur will receive a 12.5% working interest in the well. When Energas has received net proceeds from the sale of production from a completed well equal to the cost of drilling, completing, equipping, testing and operating the well, as well as leasehold costs of $39,000, Excalibur will receive and additional 12.5% working interest in the well. The Company has drilled one well on the leases (the Maurice Snyder #1-141) which as of April 30, 2009 was in the process of completion. In March 2009 the Company acquired a 2% overriding royalty interests in the leases held by an unrelated third party for $161,000, subject to the retention by the third party of a 2% overriding royalty interest in the Maurice Snyder #1-141 well. The Company does not know of any trends, events or uncertainties that have had or are reasonably expected to have a material impact on the Company's net sales, revenues or expenses. RESULTS OF OPERATIONS YEAR ENDED JANUARY 31, 2009 Material changes of certain items in the Company's Statement of Operations for the year ended January 31, 2009, as compared to the year ended January 31, 2008, are discussed below: Increase (I) Item or Decrease (D) Reason ---- --------------- ------ Oil and gas sales D Sale of Company's Kentucky oil and gas properties, sale of Ainsworth #1-33 well, and decrease in production. General and administrative D Sale of Kentucky oil and gas properties Expense and decrease in staff. Bad debt expense I Sale of non-recourse note, which had an outstanding principal balance at the time of sale of $2,112,020, for $950,000. 17 Property impairment I The Company recorded an impairment expense in connection with the January 2008 sale of its oil and gas properties in Kentucky. An additional impairment charge of $1,225,455 was recorded against the Kentucky properties during the year ended January 31, 2009. Depreciation, depletion D Sale of Company's Kentucky oil and gas and amortization properties and sale of Ainsworth #1-33 well.

YEAR ENDED JANUARY 31, 2008 Material changes of certain items in the Company's Statement of Operations for the year ended January 31, 2008, as compared to the year ended January 31, 2007, are discussed below: Increase (I) Item or Decrease (D) Reason ---- --------------- ------ Oil and Gas Sales D Sale of Company's Kentucky oil and gas properties and decrease of production. Lease Operating Expense D Sale of Company's Kentucky oil and gas properties. Property Impairment I The Company recorded an impairment expense of $701,691 in connection with the January 2008 sale of its oil and gas properties in Kentucky. Depreciation, Depletion D Sale of Company's Kentucky oil and gas and Amortization properties. OIL AND GAS PRICE FLUCTUATIONS Fluctuations in crude oil and natural gas prices have significantly affected the Company's operations and the value of its assets. As a result of the instability and volatility of crude oil and natural gas prices and at times the market conditions within the oil and gas industry, financial institutions are selective in the energy lending area and have reduced the percentage of existing reserves that may qualify for the borrowing base to support energy loans. The Company's principal source of cash flow is the production and sale of its crude oil and natural gas reserves which are depleting assets. Cash flow from oil and gas production sales depends upon the quantity of production and the price obtained for such production. An increase in prices permits the Company to finance its operations to a greater extent with internally generated funds, may allow the Company to obtain equity financing more easily or on better terms, and lessens the difficulty of attracting financing from industry partners 18 and non-industry investors. However, price increases heighten the competition for Leases and Prospects, increase the costs of exploration and development activities, and, because of potential price declines, increase the risks associated with the purchase of Producing Properties during times that prices are at higher levels. A decline in oil and gas prices (i) reduces the cash flow internally generated by the Company which in turn reduces the funds available for servicing debt and exploring for and replacing oil and gas reserves, (ii) increases the difficulty of obtaining equity and debt financing and worsens the terms on which such financing may be obtained, (iii) reduces the number of Leases and Prospects which have reasonable economic terms, (iv) may cause the Company to permit Leases to expire based upon the value of potential oil and gas reserves in relation to the costs of exploration, (v) results in marginally productive oil and gas wells being abandoned as non-commercial, and (vi) increases the difficulty of attracting financing from industry partners and non-industry investors. However, price declines reduce the competition for Leases and Prospects and correspondingly reduce the prices paid for Leases and Prospects. Furthermore, exploration and production costs generally decline, although the decline may not be at the same rate as that of oil and gas prices. The Company's results of operations are somewhat seasonal due to seasonal fluctuations in the sales prices for natural gas. Although in recent years crude oil prices have been generally higher in the third and fourth fiscal quarters, these fluctuations are not believed to be seasonal. Natural gas prices have been generally higher in the fourth fiscal quarter. CAPITAL RESOURCES AND LIQUIDITY The Company's material sources and (uses) of cash during the year ended January 31, 2009 were: Cash used in operations $ (74,048) Acquisition and development of oil and gas properties (692,948) Cash resulting from purchase of subsidiaries 71,297 Investment in partnership (39,000) Collections on note receivable 87,980 Sale of oil and gas properties 590,400 Loans from related parties 96,327 Advances (net of repayments) on capital lease 7,164 The Company's material sources and (uses) of cash during the year ended January 31, 2008 were: Cash used in operations $ (362,848) Acquisition and development of oil and gas properties (575,367) Sale of oil and gas properties 1,178,000 Loans from related parties (40,650) Repayment of notes (699,853) 19 Cash on hand at February 1, 2007 500,718 As a result of the Company's continued losses and lack of cash there is substantial doubt as to the Company's ability to continue operations. The Company plans to generate profits by drilling productive oil or gas wells. However, the Company will need to raise the funds required to drill new wells from third parties willing to pay the Company's share of drilling and completing the wells. The Company may also attempt to raise needed capital through the private sale of its securities or by borrowing from third parties. The Company may not be successful in raising the capital needed to drill oil or gas wells. In addition, any future wells which may be drilled by the Company may not be productive of oil or gas. The inability of the Company to generate profits may force the Company to curtail or cease operations. On July 27, 2006 Energas borrowed $500,000 from Dutchess Private Equities. In consideration for the loan Energas agreed to pay Dutchess $650,000 no later than July 26, 2007. The $150,000 difference between the amount borrowed and the amount Energas was required to repay was treated as loan discount which will be amortized to interest expense over the life of the loan. As further consideration for the loan, Energas issued 800,000 shares of its common stock to Dutchess. The 800,000 shares were valued at $116,000 and treated as an additional loan discount that will be amortized to interest expense over the term of the loan. Prior to April 30, 2007 Energas used the amounts received from sales of common stock under the Equity Line of Credit to repay this loan. In June 2007 the loan to Dutchess Private Equities was paid in full. Contractual Obligations Except as shown in the following table, as of January 31, 2009, the Company did not have any material capital commitments, other than funding its operating losses and repaying outstanding debt. It is anticipated that any capital commitments that may occur will be financed principally through borrowings from institutional and private lenders (although such additional financing has not been arranged) and the sale of shares of the Company's common stock or other equity securities. However, there can be no assurance that additional capital resources and financings will be available to the Company on a timely basis, or if available, on acceptable terms. Future payments due on the Company's contractual obligations as of January 31, 2009 are as follows: Total 2009 2010 2011 2012 Thereafter ----- ---- ---- ---- ---- ---------- Office equipment leases $12,010 $5,382 $2,655 $2,108 $1,865 -- Drilling obligation $156,000 $39,000 $78,000 $39,000 -- -- Critical Accounting Policies ------------------------------- See Note 3 to the financial statements included as part of this report. 20 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET DATA Not applicable. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA See the financial statements attached to this report. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES On August 1, 2008, Murrell, Hall, McIntosh & Co. PLLP resigned as the Company's independent registered public accounting firm. Prior to August 1, 2008 MHM had recently entered into an agreement with Eide Bailly LLP, pursuant to which Eide Bailly acquired the operations of MHM. Certain professional staff and shareholders of MHM joined Eide Bailly either as employees or partners of Eide Bailly and continued to practice as members of Eide Bailly. On September 9, 2008, the Company, through and with the approval of its Board of Directors, engaged Eide Bailly as its independent registered public accounting firm. Prior to engaging Eide Bailly, the Company did not consult with Eide Bailly regarding the application of accounting principles to a specific completed or contemplated transaction or regarding the type of audit opinions that might be rendered by Eide Bailly on the Company's financial statements, and Eide Bailly did not provide any written or oral advice that was an important factor considered by the Company in reaching a decision as to any such accounting, auditing or financial reporting issue. The reports of MHM regarding the Company's financial statements for the fiscal years ended January 31, 2008 and 2007 did not contain any adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principles. However, the reports of MHM for those fiscal years were qualified with respect to uncertainty as to the Company's ability to continue as a going concern. During the years ended January 31, 2008 and 2007, and during the period from January 31, 2008 through August 1, 2008, the date of resignation, there were no disagreements with MHM on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedures, which disagreements, if not resolved to the satisfaction of MHM would have caused it to make reference to such disagreement in its reports. ITEM 9A. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures ------------------------------------------------ In connection with the preparation of this annual report, an evaluation was carried out by George Shaw, the Company's Chief Executive and Principal financial Officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities 21 Exchange Act of 1934 as of January 31, 2009. Disclosure controls and procedures are designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to management to allow timely decisions regarding required disclosures. Based on that evaluation, and the material weaknesses outlined in our Management Report on Internal Control Over Financial Reporting, the Company's management concluded, as of the end of the period covered by this annual report, that the Company's disclosure controls and procedures were not effective in recording, processing, summarizing and reporting information required to be disclosed, within the time periods specified in the SEC's rules and forms, and that such information was not accumulated and communicated to management to allow timely decisions regarding required disclosures. Management's Report on Internal Control Over Financial Reporting The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the Securities and Exchange Commission, internal control over financial reporting is a process designed by, or under the supervision of the Company's principal executive officer and principal financial officer and implemented by the Company's Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements in accordance with U.S. generally accepted accounting principles. The Company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the Company's transactions and dispositions of its assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of the Company's financial statements in accordance with U.S. generally accepted accounting principles, and that its receipts and expenditures are being made only in accordance with authorizations of the Company's management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on its financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, 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. Management has not yet assessed the effectiveness of the Company's internal control over financial reporting as of January 31, 2009 as required by Section 404 of the Sarbanes Oxley Act of 2002. Therefore, management cannot state whether or not the Company's internal controls over financial reporting are effective. 22 A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the Company's annual or interim financial statements will not be prevented or detected on a timely basis. In the course of their engagement for the year ended January 31, 2009 the Company's external audit firm reported that there were control deficiencies that in the aggregate constituted a material weakness in internal controls. The control deficiencies include the failure of management to complete the required testing of internal controls under Section 404, the lack of governance regarding the failure to file corporate tax returns for several years, the inadequacy of property records to support lease agreements and ownership interests and to track by-well full cost additions and the presence of significant audit adjustments. Audit adjustments are the indication of a failure of internal controls to prevent or detect misstatements of accounting information. The failure could be due to inadequate design of the internal controls or to a misapplication or override of controls. This annual report does not include an attestation report of the Company's independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by the Company's independent registered public accounting firm pursuant to temporary rules of the SEC that permit the Company to provide only management's report on internal control in this annual report. ITEM 9B. OTHER INFORMATION Not applicable ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. ------------------------------------------------------ The Company's executive officers and directors are listed below. The Company's directors are generally elected at the annual shareholders' meeting and hold office until the next annual shareholders' meeting or until their successors are elected and qualified. The Company's executive officers are elected by our board of directors and serve at its discretion. Name Age Position ---- --- -------- George G. Shaw 78 President, Principal Financial Officer, Principal Accounting Officer and a Director G. Scott Shaw 37 Vice President, Secretary and a Director The following is a brief description of the business background of the Company's executive officers and directors: GEORGE G. SHAW is the President, Principal Financial Officer, Principal Accounting Officer and a director of the Company. Mr. Shaw has been an officer and director of the Company since July 1991. Mr. Shaw is the President of 23 Energas Corporation and Energas Pipeline Co., Inc., both privately held companies engaged in oil and gas exploration and gas gathering. Mr. Shaw is the father of G. Scott Shaw. G. SCOTT SHAW is the Vice President and a director of the Company and has held these positions since August 1996. Mr. Shaw became the Company's Secretary in April 2003. Mr. Shaw graduated from Oklahoma State University in 1993 with a Bachelor of Science degree in Biology. Mr. Shaw is the son of George G. Shaw. The Company does not have a compensation committee. The Company's Board of Directors serves as the Company's Audit Committee. The Company does not have a financial expert as a member of its Board of Directors. None of the Company's directors are independent as that term is defined Section 803 of the Listing Standards of the NYSE Amex. During the year ended January 31, 2009 the Company did not compensate any person for acting as a director of the Company. The Company has adopted a Code of Ethics which is applicable to the Company's principal executive, financial, and accounting officers and persons performing similar functions. The Code of Ethics is available on the Company's website located at www.energasresources.com ITEM 11. EXECUTIVE COMPENSATION The following table shows the compensation during the three years ended January 31, 2009, paid or accrued, to George G. Shaw, the Company's Chief Executive Officer during those years. None of the Company's executive officers received compensation in excess of $100,000 during the three years ended January 31, 2009. All Other Annual Stock Option Compen- Name and Principal Fiscal Salary Bonus Awards Awards sation Position Year (1) (2) (3) (4) (5) Total ------------------ ------ ------ ----- ------ ------ -------- ------ George Shaw, 2009 $36,000 $15,375 $51,375 President 2008 $36,000 -- $15,000 -- -- $51,000 2007 $36,000 $4,500 $5,200 -- -- $45,700 (1) The dollar value of base salary (cash and non-cash) received. (2) The dollar value of bonus (cash and non-cash) received. (3) During the periods covered by the table, the value of the Company's shares issued as compensation for services calculated in accordance with FAS 123R. (4) The amount recognized for financial statement reporting purposes and calculated in accordance with FAS 123R, for options awarded during the year. (5) All other compensation received that the Company could not properly report in any other column of the table. The following shows the amounts which the Company expects to pay to its officers 24 during the twelve month period ending January 31, 2010, and the time which the Company's executive officers plan to devote to the Company's business. The Company does not have employment agreements with any of its officers. Proposed Time to Be Devoted Name Compensation To Company's Business George G. Shaw $84,000 100% G. Scott Shaw $72,000 100% The Company does not have any employment agreements with its officers or employees. The Company does not maintain any keyman insurance on the life or in the event of disability of any of its officers. STOCK OPTION AND BONUS PLANS Incentive Stock Option Plan. The Company's Incentive Stock Option Plan authorizes the issuance of up to 2,000,000 shares of the Company's common stock to persons that exercise options granted pursuant to the Plan. Only Company employees may be granted options pursuant to the Incentive Stock Option Plan. The option exercise price is determined by the Company's Board of Directors but cannot be less than the market price of the Company's common stock on the date the option is granted. Non-Qualified Stock Option Plan. The Company's Non-Qualified Stock Option Plan authorizes the issuance of up to 1,000,000 shares of the Company's common stock to persons that exercise options granted pursuant to the Plans. The Company's employees, directors, officers, consultants and advisors are eligible to be granted options pursuant to the Plans, provided however that bona fide services must be rendered by such consultants or advisors and such services must not be in connection with the offer or sale of securities in a capital-raising transaction. The option exercise price is determined by the Company's Board of Directors. Stock Bonus Plan. The Company's Stock Bonus Plan allows for the issuance of up to 4,000,000 shares of common stock. Such shares may consist, in whole or in part, of authorized but unissued shares, or treasury shares. Under the Stock Bonus Plan, the Company's employees, directors, officers, consultants and advisors are eligible to receive a grant of the Company's shares, provided however that bona fide services must be rendered by consultants or advisors and such services must not be in connection with the offer or sale of securities in a capital-raising transaction. The following table shows the weighted average exercise price of the outstanding options granted pursuant to the Company's Incentive and Non-Qualified Stock Option Plans as of January 31, 2009. The Company's Incentive and Non-Qualified Stock Option Plans were not approved by the Company's shareholders. 25 Number of Securities Remaining Available Number For Future Issuance of Securities Under Equity to be Issued Weighted-Average Compensation Plans Upon Exercise Exercise Price of (Excluding Securities of Outstanding of Outstanding Reflected in Plan Category Options [a] Options Column (a)) -------------------------------------------------------------------------------- Incentive Stock Option Plan -- -- 2,000,000 Non-Qualified Stock Option Plan -- -- 750,000 The following table provides information as of April 30, 2009 concerning the stock options and stock bonuses granted by the Company pursuant to the Plans. Each option represents the right to purchase one share of the Company's common stock. Total Shares Remaining Shares Reserved for Shares Options/ Reserved Outstanding Issued As Shares Name of Plan Under Plans Options Stock Bonus Under Plans ------------ ----------- ----------- ----------- ----------- Incentive Stock Option Plan 2,000,000 -- -- 2,000,000 Non-Qualified Stock Option Plan 1,000,000 -- -- 750,000 Stock Bonus Plan 4,000,000 -- 1,836,981 2,163,019 The following table summarizes the options and stock bonuses granted pursuant to the Plans as of April 30, 2009: Incentive Stock Options ----------------------- Options Shares Subject Exercise Date of Expiration Exercised as of To Option Price Grant Date of Option April 30, 2009 -------------- -------- ------- -------------- --------------- None. Non-Qualified Stock Options --------------------------- Options Shares Subject Exercise Date of Expiration Exercised as of To Option Price Grant Date of Option April 30, 2009 -------------- -------- ------- -------------- --------------- 250,000 $0.32 6-30-03 7-15-05 250,000 26 Stock Bonuses ------------- Shares Issued as Name Stock Bonus Date Issued ---- ---------------- ----------- George Shaw 100,000 10/30/03 Scott Shaw 100,000 10/30/03 Employees and consultants 1,636,981 various dates --------- 1,836,981 Separate from its Stock Bonus Plan, the Company has issued the following shares of its common stock to George and Scott Shaw for services rendered. Shares Issued for Name Services Rendered Date Issued ---- ----------------- ----------- George Shaw 100,000 10/2005 Scott Shaw 100,000 10/2005 George Shaw 150,000 10/2006 Scott Shaw 150,000 10/2006 George Shaw 750,000 9/2007 Scott Shaw 750,000 9/2007 George Shaw 750,000 10/2008 Scott Shaw 750,000 10/2008 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table shows the ownership of the Company's common stock as of April 30, 2009 by (i) each person who is known to the Company to be the beneficial owner of more than 5% the Company's common stock, (ii) each director and executive officer of the Company, and (iii) all executive officers and directors of the Company as a group. All persons listed have sole voting and investment power with respect to their shares unless otherwise indicated, and there are no family relationships among the executive officers and directors of the Company, except that George G. Shaw is the father of G. Scott Shaw. As of April 30, 2009 the Company did not have any outstanding options, warrants or other securities convertible into common stock. Shares Percent of Beneficially Outstanding Name and address Owned Shares ---------------- ------------ ----------- George G. Shaw 21,133,649 (1) 23.18% Third Floor, 800 Northeast 63rd Street Oklahoma City, Oklahoma 73105 27 G. Scott Shaw 7,678,905 8.4% 800 Northeast 63rd Street Oklahoma City, Oklahoma 73105 Terry R. and Marguerite S. Tyson 8,792,800 9.6% 16250 County Rd. U Lipscomb, TX 79056-6304 Executive Officers and Directors as a group 37,605,354 41.18% (two persons) (1) Includes (i) 2,024,916 shares held by Energas Corporation, (ii) 3,460,320 shares held by Energas Pipeline Co., Inc. and (iii) 1,585,000 shares of common stock held by Mr. Shaw. Energas Corporation and Energas Pipeline Co., Inc. are controlled by Mr. Shaw. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, DIRECTOR INDEPENDENCE --------------------------------------------------------------------- The Company's offices are located at 800 Northeast 63rd Street, Oklahoma City, Oklahoma. The office space is occupied under an unwritten month-to-month lease requiring rental payments of $4,000 per month to George Shaw, the owner of the building. During the years ended January 31, 2009, 2008 and 2007 the Company paid rent of $47,600, $45,600 and $49,400, respectively. In addition, and prior to 1/31/09 Mr. Shaw owned Energas Pipeline Company which operates the natural gas gathering system to which the Company's four wells in Atoka County, Oklahoma are connected. During the years ended January 31, 2009, 2008 and 2007 Energas Pipeline Company received $13,658, $13,550 and $16,820, respectively, for operating the gathering system. In January 2009 the Company acquired Energas Pipeline Company and Energas Corp. from George Shaw, the Company's President, for 6,167,400 shares of the Company's common stock. Energas Pipeline Company operates the natural gas gathering system which is connected to the Company's three wells in Atoka County, Oklahoma. Energas Corp. operates, but holds no interest in, all of the Company's wells and holds the bonds required by state oil and gas regulatory authorities. As of January 31, 2009 the Company had borrowed $40,431 from Mr. Shaw. These loans are non-interest bearing, unsecured, and do not have fixed terms of repayment. The amounts borrowed from Mr. Shaw were used to fund the Company's operations. The Company believes that the rent paid to Mr. Shaw and the terms of the other transactions between the Company and its officers and directors discussed above were fair and reasonable and were upon terms as least as favorable as the Company could have obtained from unrelated third parties. Transactions with the Company's officers, directors, and principal shareholders may continue and may result in conflicts of interest between the 28 Company and these individuals. Although these persons have fiduciary duties to the Company and its shareholders, there can be no assurance that conflicts of interest will always be resolved in favor of Company and its shareholders. Neither the Company's Articles of Incorporation nor Bylaws contain any provisions for resolving potential or actual conflicts of interest. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES Murrell, Hall, McIntosh & Co., PLLP served as the Company's independent public accountants during the fiscal year ended January 31, 2008. The following table shows the aggregate fees billed to the Company during the year ended January 31, 2008 by Murrell, Hall, McIntosh & Co., PLLP. 2009 2008 ---- ---- Audit Fees $46,408.75 $53,386.15 Audit-Related Fees Financial Information Systems Design and Implementation Fees Tax Fees All Other Fees Audit fees represent amounts billed for professional services rendered for the audit of the Company's annual financial statements and the reviews of the financial statements included in the Company's 10-Q reports during the fiscal year. Before Murrell, Hall, McIntosh & Co., PLLP was engaged by the Company to render audit services, the engagement was approved by the Company's Board of Directors. Eide Bailly LLP audited the Company's financial statements for the year ended January 31, 2009. The following table shows the aggregate fees billed to the Company during the year ended January 31, 2009 by Eide Bailly. 2009 ---- Audit Fees $34,099.30 Audit-Related Fees Financial Information Systems Design and Implementation Fees Tax Fees All Other Fees Audit fees represent amounts billed for professional services rendered for the audit of the Company's annual financial statements and the reviews of the financial statements included in the Company's 10-Q reports during the fiscal year. Before Eide Bailly LLP was engaged by the Company to render audit services, the engagement was approved by the Company's Board of Directors. 29 ITEM 15. EXHIBITS, FINANCIAL STATEMENTS SCHEDULES Exhibit No. Description of Exhibit Page Number ------- ---------------------- ----------- 3.1 Certificate of Incorporation * 3.2 Bylaws * 3.3 Certificate of Domestication in Delaware * 10.7 Gas Purchase Agreement, dated March 1, 1991 between Registrant and Energas Pipeline Company. * 10.8 Gas Purchase Agreement, dated March 1, 1991 between Registrant and Energas Pipeline Company. * 10.9 Gas Gathering Agreement, dated July 1, 1992 between Energas Pipeline Company, Inc. and A.T. Gas Gathering Systems, Inc. * 10.10 Gas Purchase Agreement, dated February 13, 1997, between Panenergy Field Services, Inc. and Energas Pipeline Company. * 10.11 Gas Purchase Agreement, dated October 1, 1999, between Registrant and Ozark Gas Gathering, L.L.C. * 21. Registrant's Subsidiaries * 23. Consent of Accountants _____ 31. Rule 13a-14(a)/15d-14(a) certifications _____ 32. Section 1350 certifications _____ * Incorporated by referenced to the same exhibit filed with the Company's initial registration statement on Form 10-SB. ** Incorporated by reference to the same exhibit filed with the Company's report on Form 8-K dated June 27, 2005. 30 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of Energas Resources, Inc. We have audited the accompanying consolidated balance sheet of Energas Resources, Inc. as of January 31, 2009 and the related consolidated statements of income, stockholders' equity and cash flows for the year ended January 31, 2009. Energas Resources, Inc.'s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting an Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose 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 audit provides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energas Resources, Inc. as of January 31, 2009 and the results of its operations and its cash flows for the year ended January 31, 2009 in conformity with accounting principles generally accepted in the United States of America. The accompanying financial statements have been prepared assuming that Energas Resources, Inc. will continue as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of operations. As discussed in Note 2, certain factors indicate substantial doubt that the Company will be able to continue as a going concern. The financial statements do not include any adjustments to reflect the possible future effect on the recoverability and classification of assets or the amounts and classification of liabilities that might result from the outcome of these uncertainties. /s/ Eide Bailly LLP Greenwood Village, Colorado June 9, 2009 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of Energas Resources, Inc. We have audited the accompanying consolidated balance sheet of Energas Resources, Inc. as of January 31, 2008 and the related consolidated statements of income, stockholders' equity and cash flows for the year ended January 31, 2008. Energas Resources, Inc.'s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting an Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose 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 audit provides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energas Resources, Inc. as of January 31, 2008 and the results of its operations and its cash flows for the year ended January 31, 2008 in conformity with accounting principles generally accepted in the United States of America. The accompanying financial statements have been prepared assuming that Energas Resources, Inc. will continue as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of operations. As discussed in Note 2, certain factors indicate substantial doubt that the Company will be able to continue as a going concern. The financial statements do not include any adjustments to reflect the possible future effect on the recoverability and classification of assets or the amounts and classification of liabilities that might result from the outcome of these uncertainties. /s/ Murrell, Hall, McIntosh & Co., PLLP Oklahoma City, Oklahoma April 30, 2008 ENERGAS RESOURCES, INC. CONSOLIDATED BALANCE SHEETS January 31, January 31, 2009 2008 ----------- ----------- ASSETS Current Assets Cash $ 76,076 $ 28,90 Restricted cash 25,049 - Accounts receivable 54,539 52,326 ----------- ----------- Total Current Assets 155,664 81,230 ----------- ----------- Property and Equipment Oil and gas properties, using full cost accounting Proved properties 2,606,814 2,380,633 Unproved properties 162,012 16,845 ----------- ----------- 2,768,826 2,397,478 Less accumulated depreciation, depletion, and amortization, including impairment of $1,505,656 and $280,201 (2,249,545) (904,302) ----------- ----------- 519,281 1,493,176 Other, net of accumulated depreciation of $34,035 and $30,287 14,474 11,691 ----------- ----------- 533,755 1,504,867 ----------- ----------- Goodwill 146,703 - Investment in partnership 39,000 - Note Receivable, net of allowance of $1,162,020 and $0 950,000 2,300,000 ----------- ----------- Total Assets $1,825,122 $3,886,097 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Accounts payable and accrued expenses 219,791 357,473 Advanced drilling funds 126,263 - Due to related parties 40,431 49,962 Current portion of lease 1,444 - Current asset retirement obligation 23,691 - Note payable 16,000 11,992 ----------- ----------- Total Current Liabilities 427,620 419,427 Asset Retirement Obligation 87,726 41,627 Long-term lease 5,720 - Deposit on sale - 100,000 Drilling obligation 156,000 - ----------- ----------- Total Liabilities 677,066 561,054 ----------- ----------- Stockholders' Equity Common stock, $.001 par value 100,000,000 shares authorized 90,700,144 and 82,532,744 shares issued and outstanding at January 31, 2009 and 2008 90,700 82,533 Additional paid in capital 19,308,395 19,025,907 Retained (deficit) (18,251,039) (15,783,397) ----------- ----------- Total Stockholders' Equity 1,148,056 3,325,043 ----------- ----------- Total Liabilities and Stockholders' Equity $1,825,122 $3,886,097 =========== =========== See notes to the consolidated financial statem s. 1 ENERGAS RESOURCES, INC. CONSOLIDATED STATEMENTS OF OPERATIONS ent Years Ended January 31, ----------------------------- 2009 2008 -------------- -------------- Revenue Oil and gas sales $ 272,223 $ 431,959 Pipeline revenue 12,074 12,068 -------------- -------------- Total Revenue 284,297 444,027 Operating Expenses Lease operating expense 119,038 119,002 Pipeline and gathering expense 14,432 82,824 General and administrative expense 498,615 638,201 Bad debt expense 1,160,997 - Property impairments 1,225,455 701,691 Depreciation, depletion and amortization 142,321 178,563 -------------- -------------- Total Operating Expenses 3,160,858 1,720,281 -------------- -------------- Operating (Loss) (2,876,561) (1,276,254) -------------- -------------- Other (Expenses) Income Other income - 187 Interest income 140,115 - Loss on disposal of asset - (31,060) Gain on sale of properties 267,549 - Gain on sale of subsidiary 7,116 - I nterest expense (5,861) (162,208) -------------- -------------- Total Other (Expense) 408,919 (193,081) -------------- -------------- Net (Loss) before Income Taxes (2,467,642) (1,469,335) Provision for income taxes - - -------------- -------------- Net (Loss) $ (2,467,642) $ (1,469,335) ============== ============== Net (Loss) per Share, Basic and Diluted $ (0.03) $ (0.02) ============== ============== Weighted average of number of shares outstanding 83,046,405 79,237,416 ============== ============== See notes to the consolidated financial statements. 2 ENERGAS RESOURCES, INC. CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED JANUARY 31, 2009 AND JANUARY 31, 2008 Additional Total Common Stock Paid-In Accumulated Shareholders' Shares Amount Capital Deficit Equity ------ ------ ---------- ----------- ------------- Balance, January 31, 2007 74,472,914 $ 74,473 $18,872,326 $(14,314,062) $ 4,632,737 Net loss (1,469,335) (1,469,335) Employee stock plan 2,600,000 2,600 49,400 - 52,000 Stock issued for accounts payable 1,258,930 1,259 31,355 - 32,614 Stock issued for loan repayment 4,200,900 4,201 72,826 - 77,027 ------------- ---------- ------------- ------------- ------------- Balance, January 31, 2008 82,532,744 82,533 19,025,907 (15,783,397) 3,325,043 Net loss (2,467,642) (2,467,642) Employee stock plan 2,000,000 2,000 39,000 41,000 Stock issued for purchase of subsidiaries 6,167,400 6,167 243,488 249,655 ------------- ---------- ------------- ------------- ------------- Balance, January 31, 2009 90,700,144 $ 90,700 $19,308,395 $(18,251,039) $ 1,148,056 ============= ========== ============= ============= =============

See notes to the consolidated financial statements. 3 ENERGAS RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS Years Ended January 31, ------------------------- 2009 2008 ------------------------- Cash Flows From Operating Activities Net (Loss) $(2,467,642) $(1,469,335) Adjustments to reconcile net loss to net cash provided by operating activities Depreciation, depletion and amortization 142,320 178,563 Bad debt provision 1,160,997 - Loss on disposal of asset - 31,060 Gain on sale of subsidiary (7,115) - Gain on sale of properties (267,549) - Property impairments 1,225,455 701,691 Amortization of loan discount - 133,000 Stock issued for salaries 41,000 52,000 (Increase) Decrease in Accounts receivable 130,216 16,585 Prepaid expenses - 400 Increase (Decrease) in Accounts payable and accrued expenses (231,791) (109,765) Drilling advances 126,263 - Accrued interest 4,008 - Deposits held - 100,000 Asset retirement obligation 69,790 2,953 ------------- ------------- Net Cash Flows Provided by (Used By) Operating Activities (74,048) (362,848) Cash Flows From Investing Activities (Investment in) oil and gas properties (692,948) (575,367) Cash received from purchase of subsidiaries 64,182 - Sale of subsidiary 7,115 - Investment in partnership (39,000) - Payments on note receivable 87,980 - Sale of oil and gas properties 590,400 1,178,000 ------------- ------------- Net Cash Provided By (Used By) Investing Activities 17,729 602,633 Cash Flows from Financing Activities Advances from (Repayments to) related parties and stockholders 96,327 (40,650) Advances on capital lease 8,708 - Payments on capital lease (1,544) - Payments on notes payable - (699,853) ------------- ------------- Net Cash Provided By Financing Activities 103,491 (740,503) Increase (Decrease) in Cash 47,172 (500,718) Cash at Beginning of Year 28,904 529,622 ------------- ------------- Cash at End of Period $ 76,076 $ 28,904 ============= ============= Supplemental Information: Interest Paid in Cash $ 1,853 $ 29,208 ============= ============= Income Taxes Paid $ - $ - ============= ============= Non-Cash Transactions: Stock issued for salaries $ 41,000 $ 52,000 ============= ============= Stock issued for purchase of subsidiaries $ 249,655 $ - ============= ============= Stock issued for payments on accounts payable $ - $ 32,614 ============= ============= Stock issued for payments on notes payable $ - $ 77,027 ============= ============= See notes to the condensed consolidated financial statements. 4 ENERGAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED JANUARY 31, 2009 AND 2008 1. NATURE OF OPERATIONS Energas Resources, Inc. (the "Company") was originally incorporated in 1989 in British Columbia, Canada as a public company listed on the Canadian Venture Exchange. In 2001, the Company registered as a Delaware corporation becoming a United States domestic corporation. In 2002, its registration statement filed with the Securities and Exchange Commission became effective and its stock is traded in the Over the Counter (OTC) market. The Company is primarily engaged in the operation, development, production, exploration and acquisition of petroleum and natural gas properties in the United States through its wholly-owned subsidiary, A.T. Gas Gathering Systems, Inc. ("AT GAS"). In addition, the Company owns and operates natural gas gathering systems located in Oklahoma, which serve wells operated by the Company for delivery to a mainline transmission system. The majority of the Company's operations are maintained and occur through AT GAS. AT GAS is a company incorporated in the state of Oklahoma. On January 31, 2009 the Company purchased all the outstanding shares of Energas Corporation ("Corp.") from George G. Shaw, the Company's president. Corp. is the operator of all of the Company's wells. Corp. became a wholly owned subsidiary of the Company as of the date of acquisition. On January 31, 2009 the Company purchased all the outstanding shares of Energas Pipeline ("Pipeline") from George G. Shaw, the Company's president. Pipeline operates the natural gas gathering system to which the Company's four wells in Atoka County, Oklahoma are connected. Pipeline became a wholly owned subsidiary of the Company as of the date of acquisition. 2. GOING CONCERN The Company is in the process of acquiring and developing petroleum and natural gas properties with adequate production and reserves to operate profitably. As of January 31, 2009, the Company had incurred losses for the years ended January 31, 2009 and 2008 of $(2,467,642) and $(1,469,335), respectively. The Company's ability to continue as a going concern is dependent upon obtaining financing and achieving profitable levels of operations. The Company is currently seeking additional funds and additional mineral interests through private placements of equity and debt instruments. There can be no assurance that its efforts will be successful. The consolidated financial statements do not give effect to any adjustments that might be necessary if the Company is unable to continue as a going concern. 5 3. SIGNIFICANT ACCOUNTING POLICIES Basis of consolidation - The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, AT Gas, Corp., Pipeline and TGC (through February 15, 2008). All significant inter-company items have been eliminated in consolidation. Use of estimates in the preparation of financial statements - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The oil industry is subject, by its nature, to environmental hazards and cleanup costs for which we carry liability insurance. At this time, we know of no substantial costs from environmental accidents or events for which we may be currently liable. In addition, our oil and gas business makes us vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on current oil and gas prices. Price declines reduce the estimated proved reserves and increase annual amortization expense (which is based on proved reserves). Revenue recognition - Oil and natural gas revenue is recognized at the time title is transferred to the customer. Pipeline revenue is earned as a gathering fee at the time the gas is delivered to the customer. Petroleum and natural gas properties - The Company employs the full cost method of accounting for petroleum and natural gas properties whereby all costs relating to exploration and development of reserves are capitalized. Such costs include land acquisition costs, geological and geophysical costs, costs of drilling both productive and non-productive wells, and related overhead. Capitalized costs, excluding costs relating to unproven properties, are depleted using the unit-of-production method based on estimated proven reserves, as prepared by an independent engineer. For the purposes of the depletion calculation, proven reserves are converted to a common unit of measure on the basis of their approximate relative energy content. Investments in unproved properties are not amortized until the proved reserves associated with the projects can be determined or until impairment occurs. If an assessment of such properties indicates that properties are impaired, the amount of impairment is added to the capitalized cost base to be amortized. Under the full cost method, the net book value of natural gas and oil properties, less related deferred income taxes, may not exceed a calculated "ceiling". The ceiling is the estimated after-tax future net revenue from proved natural gas and oil properties, discounted at 10% per annum plus the lower of cost or fair market value of unproved properties. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant indefinitely, except for changes that are fixed and determinable by 6 existing contracts. The net book value is compared to the ceiling on an annual basis. The excess, if any, of the net book value above the ceiling is required to be written off as an expense. Proceeds on disposal of properties are normally applied as a reduction of the capitalized costs without recognition of a gain or loss, unless such amounts would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case gain or loss would be recognized. Abandonment of properties are accounted for as adjustments of capitalized costs with no loss recognized, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. Long-lived assets - The Company reviews its long-lived assets for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable. For purposes of evaluating the recoverability of long-lived assets, the recoverability test is performed using estimated undiscounted net cash flows to be generated by the asset. Equipment - Equipment is recorded at cost and depreciated on the straight-line basis over the following periods: Computer equipment 5-7 years Truck 7 years Office equipment 5-7 years Computer software 5 years Gathering systems 30 years Asset Retirement Obligations - In accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 143 Accounting for Asset Retirement Obligations the Company records the fair value of its liability for asset retirement obligations at the time a well is completed and a corresponding increase in the carrying amount of the related long live assets. Over time, the liability is accreted to its present value at the end of each reporting period, and the capitalized cost is depreciated over the useful life of the related assets. Upon settlement of the liability, the Company will either settle the obligation for its recorded amount or incur a gain or loss upon settlement. The Company's asset retirement obligations relate to the plugging and abandonment of its natural gas and oil properties. Accounts Receivable - Management periodically assesses the collectibility of the Company's accounts receivable and notes receivable. Accounts determined to be uncollectible are charged to operations when that determination is made. The provision for bad debt related to the note receivable has been recorded at $1,162,020 as of January 31, 2009 due to the factors discussed in Note 5. Earnings per share - The Company follows SFAS 128 Earnings per Share, for computing and presenting earnings per share, which requires, among other things, 7 dual presentation of basic and diluted earnings per share on the face of the statement of operations. Basic EPS is computed by dividing income available to common shareholders by the weighted average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if securities, options or warrants were exercised or converted into common shares or resulted in the issuance of common shares that then share in the earnings of the entity. For the years ended January 31, 2009 and 2008, no options or warrants were considered common stock equivalents as their effect would be anti-dilutive. Stock-based compensation - Effective February 1, 2006 the Company adopted the fair value recognition provisions of SFAS 123R, using the modified-prospective transition method. Under this transition method, stock-based compensation expense will be recognized in the consolidated financial statements for granted, modified, or settled stock options. Compensation expense recognized included the estimated expense for stock options granted on and subsequent to February 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS 123R, and the estimated expense for the portion vesting in the period for options granted prior to, but not vested as of February 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS 123. Results for prior periods have not been restated, as provided for under the modified-prospective method. SFAS 123R requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. In the Company's pro forma information required under SFAS 123R for the periods prior to fiscal 2007, the Company accounted for forfeitures as they occurred. The Company is using the Black-Scholes option-pricing model as its method of valuation for share-based awards granted beginning in fiscal 2007. The Company's determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by the Company's stock price as well as assumptions regarding a number of highly complex and subjective variables. These variables include, but are not limited to the Company's expected stock price volatility over the term of the awards, and certain other market variables such as the risk free interest rate. No options were granted, modified or settled during the years ended January 31, 2009 and 2008, and there was no stock-based compensation expense included in net income for these periods subject to the option pricing considerations discussed above. As discussed further in Note 16, the Company awarded 2,000,000 shares of common stock to employees on September 26, 2008. Using the market price of $.0205 on the date of the grant, the Company has recognized stock based compensation of $41,000 during the year ended January 31, 2009. Cash and cash equivalents - For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Investment in Partnership - The Company has elected to follow the equity method with respect to its investment in a partnership. Under the equity method, the Company's share of income or loss will be recorded as an increase or decrease in the investment accounts. Unlike the accounting treatment under proportionate consolidation, neither the Company's share of reserves nor the Company's share of oil and gas assets enter into the depreciation, depletion and amortization calculation under the full cost method. Business Combinations - The Company follows SFAS 141, "Business Combinations", which defines the acquirer, establishes the acquisition date, and requires the acquirer to recognize the assets acquired and the liabilities assumed measured at their fair values as of that date, with any residual recorded as goodwill. Goodwill - Goodwill represents the excess of cost over fair value of assets acquired. Goodwill is not subject to amortization but is tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired, as required by SFAS 142, "Goodwill and Other Intangible Assets". 8 Concentration of credit risk - The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant risk. Trade receivables consist of uncollateralized customer obligations due under normal trade terms. The note receivable results from oil and gas properties and a pipeline sold in a prior period. Management reviews the estimated recoverability of trade and notes receivable and reduces their earning amount by utilizing a valuation allowance that reflects management's best estimate of the amount that may not be recoverable. Management believes all trade receivables to be fully collectible at January 31, 2009 and 2008. An allowance for bad debt has been recorded against the note receivable as of January 31, 2009 as discussed further in Note 5. Financial Instruments - The carrying value of current assets and liabilities reasonably approximates their fair value due to their short maturity periods. Income taxes - Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for future timing differences between the financial statement carrying amounts and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered. In July 2006, the Financial Accounting Standards Board (FASB) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109 (FIN 48). FIN 48 is intended to clarify the accounting for uncertainty in income taxes recognized in a company's financial statements and prescribes the recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. Under FIN 48, evaluation of a tax position is a two-step process. The first step is to determine whether it is more-likely-than-not that a tax position will be sustained upon examination, including the resolution of any related appeals or litigation based on the technical merits of that position. The second step is to measure a tax position that meets the more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. Tax positions that previously failed to meet the more-likely-than-not recognition threshold should be recognized in the first subsequent period in which the threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not criteria should be de-recognized in the first subsequent financial reporting period in which the threshold is no longer met. The adoption of FIN 48 at February 1, 2007 did not have a material effect on the Company's financial position. 9 Segment Reporting - SFAS 131, "Disclosures about Segments of an Enterprise and Related Information", requires a public entity to report financial and descriptive information about its reportable operating segments. Generally, financial information is required to be reported on the basis that it is used internally for evaluating segment performance and deciding how to allocate resources to segments. The majority of the operations involve the operation, development and production of oil and gas properties. An incidental amount of assets (less than 10%) are associated with pipeline activities and the pipeline is operated solely to serve specific properties. Therefore management does not consider the pipeline activities to be separable from the oil and gas activities and the operations are reported herein as a single operating segment. Reclassifications - Certain prior period amounts have been reclassified to conform to current period presentation. New Accounting Pronouncements - In September 2006, the FASB issued Statement 157, "Fair Value Measurements" ("SFAS 157"). SFAS 157 addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. The Company adopted SFAS No. 157 February 1, 2008. In February 2008, the FASB issued Staff Position No. SFAS 157 (FSP No 157-2) Effective Date of FASB Statement No 157, that defers the effect date of SFAS 157 for one year for certain nonfinancial assets and nonfinancial liabilities. SFAS 157 is effective for certain nonfinancial assets and nonfinancial liabilites for financial statements issued for fiscal years beginning after November 15, 2008. Management is currently assessing the effect of the adoption of SFAS 157 to nonfinancial assets and nonfinancial liabilities. In September 2006, the Securities Exchange Commission issued Staff Accounting Bulletin No. 108 ("SAB 108"). SAB 108 addresses how the effects of prior year uncorrected misstatements should be considered when quantifying misstatements in current year financial statements. SAB 108 requires companies to quantify misstatements using a balance sheet and income statement approach and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. When the effect of initial adoption is material, companies will record the effect as a cumulative effect adjustment to beginning of year retained earnings and disclose the nature and amount of each individual error being corrected in the cumulative adjustment. SAB 108 was effective beginning January 1, 2007 and the initial adoption of SAB 108 did not have a material impact on the Company's financial position, results of operations, or cash flows. In February 2007, the FASB issued SFAS 159 "The Fair Value Option for Financial Assets and Financial Liabilities". This statement permits companies to choose to measure many financial assets and liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are 10 reported in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. Management adopted this Statement on February 1, 2008 and the adoption of SFAS 159 did not have a material impact to the Company's financial position, results of operations, or cash flows. In December 2007, the FASB issued SFAS 160, Non-controlling Interests in Consolidated Financial Statements--an amendment of Accounting Research Bulletin No. 51 (SFAS 160). SFAS 160 establishes new accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008. The Company does not believe that SFAS 160 will have a material impact on its consolidated financial statements. In March 2008, the FASB issued SFAS 161, Disclosures about Derivative Instruments and Hedging Activities--an amendment of FASB Statement No. 133. SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. The guidance in SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. This Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. The Company does not believe that SFAS 161 will have a material impact on its consolidated financial statements. In May 2008, the FASB issued SFAS 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS 162 is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with U.S. generally accepted accounting principles (GAAP). SFAS 162 directs the GAAP hierarchy to the entity, not the independent auditors, as the entity is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. SFAS 162 is effective 60 days following the Securities and Exchange Commission's approval of the Public Company Accounting Oversight Board amendments to remove the GAAP hierarchy from the auditing standards. The adoption of this standard did not have a material impact on the Company's financial position, results of operations, or cash flows. In December 2008, the FASB issued FASB Staff Position (FSP) no. FAS 132(R)-1, Employers' Disclosures about Postretirement Benefit Plan Assets. The FSP amends SFAS No. 132 (revised 2003), Employers' Disclosures about Pensions and Other Postretirement Benefits, to provide guidance on an employer's disclosures about plan assets of a defined benefit pension or other postretirement plan. The disclosures about plan assets required by FSP No. FAS 123(R)-1 are to be provided for fiscal years beginning after December 15, 2009. The Company is currently assessing the impact of FSP No. FAS 123(R)-1. 11 4. SALE OF OIL AND GAS PROPERTIES As of June 1, 2007 the Company had finalized a sales agreement for the sale of all Pulaski County, Kentucky properties, gathering systems and equipment for $1,635,560. The Company received cash payments totaling $1,604,500 and in October 2007 agreed to a sales price adjustment reducing the price by $31,060. The sales price adjustment was recorded in the carrying amount of oil and gas properties in accordance with the requirements of the full cost method of accounting for oil and gas properties. On January 1, 2008 the Company finalized a sales agreement for the sale of all remaining Kentucky properties, gathering systems, pipelines and equipment for $2,300,000. The Company received a $100,000 deposit and a non-recourse note receivable for $2,200,000 due on January 1, 2010, with interest of 7.5%, secured by first mortgage liens on real property; lien and security interest in all wells, fixtures and equipment; and collateral assignment of production and proceeds from the properties. See Note 5 for additional discussion of the note receivable resulting from this transaction. On April 11, 2008 the Company sold the Ainsworth #1-33 well for $615,000 less sales expenses of $24,600. The Company determined that the sale of the Ainsworth significantly altered the relationship between capitalized costs and proved reserves of the remaining full cost pool, therefore the net book value of the property, $322,851 was removed from the full cost pool and a gain was recognized of $267,549 on the sale during the year ended January 31, 2009. 5. NOTE RECEIVABLE At the time of the transaction described in Note 4, current production levels indicated that significant funds would need to be invested in the properties to fully develop anticipated reserves and thereby generate revenues sufficient to repay the promissory note. Due to this uncertainty, management determined to characterize the promissory note as 'properties held for resale' on the balance sheet. Following the guidance of Staff Accounting Bulletin 104, Topic 13, "Revenue Recognition", management also determined to hold all payments received on the promissory note as a liability titled "Deposit on Sale" and did not reduce the note balance nor record interest income from the date of the transaction through the six months ended July 31, 2008. On December 2, 2008 the debtor, Wildcat Energy Corp., with its parent entity Platina Energy Group, filed a voluntary petition for reorganization relief under Chapter 11 of the United States Bankruptcy Code. At the time of filing, all payments due to the Company had been received. However, the act of filing for bankruptcy is a condition of default under the promissory note, which would allow the Company to petition the bankruptcy court to foreclose on the related oil and gas properties and all pipeline and other equipment if they so choose. In considering their options for collection of the outstanding note balance, management determined that the previous classification of properties held for resale should have been as a note receivable with consideration given for an allowance for bad debt. SFAS 114, "Accounting by Creditors for Impairment of a Loan", defines the conditions under which a creditor should consider impairment of a loan and provides a framework in which to measure the impairment. Within 12 this framework, management believes the note receivable is collateral dependent as the repayment of the debt is expected to be provided solely by the underlying collateral. Under these conditions, SFAS 114 requires an allowance for uncollectability if the present value of expected future cash flows from the collateral is less than the recorded investment in the debt. On February 27, 2009 the Company sold the note receivable for $950,000 less expenses of $28,909 and therefore has recorded an allowance for bad debt of $1,162,020 as of January 31, 2009. 6. SALE OF TGC On February 15, 2008 the Company sold all the outstanding stock in its subsidiary, TGC, for $10,000. The Company retained outstanding liabilities of approximately $75,000 some of which are disputed. This sale resulted in the recognition of a $7,115 gain for financial reporting purposes. 7. PURCHASE OF SUBSIDIARIES Energas Corporation: ------------------- On January 30, 2009 the Company issued 4,872,500 shares of restricted common stock valued at $197,238 to George G. Shaw, the Company's President, for 100% of the outstanding shares of Energas Corporation. The shares were valued at 88% of the closing stock price on the day the acquisition. The purchase price was determined by third party valuation of the projected cash flows of Corp. Corp. became a wholly owned subsidiary of the Company as of the date of acquisition. The purchase price was allocated to the assets of Corp. as follows: Cash $ 64,182 Restricted cash 25,049 Receivable 236,114 Payables (222,393) Goodwill 94,286 ---------- $ 197,238 ========= Energas Pipeline: ---------------- On January 30, 2009 the Company issued 1,294,900 shares of restricted common stock valued at $52,417 to George G. Shaw, the Company's President, for 100% of the outstanding shares of Energas Pipeline. The shares were valued at 88% of the closing stock price on the day the acquisition. The purchase price was determined by third party valuation of the projected cash flows of Pipeline. 13 Pipeline became a wholly owned subsidiary of the Company as of the date of acquisition. The purchase price was allocated to the assets of Pipeline as follows: Receivables $ 19,227 Payables (19,227) Goodwill 52,417 ---------- $ 52,417 ========== Proforma Information (unaudited): -------------------------------- The proforma unaudited results of operations for the years ended January 31, 2009 and 2008, assuming that the acquisitions had occurred at the beginning of each period presented, would be as follows: 2009 2008 (unaudited) (unaudited) Revenue $ 352,460 $ 537,461 ============ ============ Net loss $(2,412,564) $(1,393,090) ============ ============ Loss per share $ (.03) $ (.02) ============ ============ All intercompany transactions have been eliminated in the proforma. No non-recurring adjustments were determined to exist. 8. RELATED PARTY TRANSACTIONS Until January 30, 2009, George G. Shaw, the Company's President, owned Energas Corporation which operates the Company's wells in Oklahoma and Wyoming. Corp. billed the Company a total of $710,143 and $268,048 for the years ended January 31, 2009 and 2008, respectively for drilling costs, lease operating expenses and overhead. Of the amounts received overhead fees were $54,505 and $80,236 for the years ended January 31, 2009 and 2008, respectively, for operation of the wells. Until January 30, 2009, George G. Shaw, the Company's President, owned Energas Pipeline Company (Pipeline) that operates the natural gas gathering system to which the Company's four wells in Atoka County, Oklahoma are connected. The Company sells gas from these wells to Pipeline, these sales were approximately $148,000 and $131,000 during years ended January 31, 2009 and 2008, respectively. The price the Company receives for the gas sold is the market price less a marketing and transportation fee of $0.10 per mcf that is deducted from the sales price. During the years ended January 31, 2009 and 2008 Energas Pipeline Company received $13,658 and $13,550, respectively, in marketing and transportation fees. The Company's offices are occupied under a one year lease beginning April 1, 2008, requiring rental payments of $4,000 per month to George G. Shaw, the Company's President and owner of the building. During the years ended January 31, 2009 and 2008 the Company paid rent of $47,600 and $45,600, respectively, to the Company's President. 9. INCOME TAXES As of January 31, 2009, the Company has approximately $13,990,000 of net operating losses expiring through 2029 that may be used to offset future taxable income but are subject to various limitations imposed by rules and regulations of the Internal Revenue Service. The net operating losses are limited each year to offset future taxable income, if any, due to the change of ownership in the Company's outstanding shares of common stock. These net operating loss carry-forwards may result in future income tax benefits of approximately $5,926,000; however, because realization is uncertain at this time, a valuation reserve in the same amount has been established. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. A reconciliation of the provision (benefit) for income taxes with the amounts determined by applying the U.S. federal income tax rate to income before income taxes is as follows: 14 Year Ended January 31 2009 2008 --------------------------- Computed at the federal statutory rate of 34% $ (839,000) $ (489,000) State tax (benefit) at statutory rates (148,000) (57,000) Property impairments and cost pool 440,000 - Change in valuation allowance 547,000 546,000 -------------- ------------ Income tax expense $ - $ - ============== ============ Significant components of the Company's deferred tax liabilities and assets are as follows: As of January 31 2009 2008 --------------------------- Deferred tax liabilities - timing in full cost pool $(210,000) $ (466,000) Deferred tax assets - net operating losses 5,646,000 5,563,000 Deferred tax assets - asset impairment 490,000 - Valuation allowance for deferred tax assets (5,926,000) (5,097,000) --------------------------- Net deferred tax assets $ - $ - =========================== The changes in the valuation allowance are as follows: Year Ended January 31 2009 2008 --------------------------- Beginning balance, February 1, $ (5,097,000) $(4,072,000) Expiring Canadian net operating losses 158,000 - Current year net operating losses (547,000) (1,087,000) Asset impairment (490,000) - Changes in timing of full cost pool 50,000 62,000 --------------------------- Ending balance, January 31, $(5,926,000) $(5,097,000) =========================== The ability of the Company to utilize NOL carryforwards to reduce future federal taxable income and federal income tax of the Company is subject to various limitations under the Internal Revenue Code of 1986, as amended. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. The Company is delinquent in filing tax returns with the Internal Revenue service and state taxing authorities. The filing of these returns could result in changes to the net operating loss (NOL) carry forwards as currently disclosed. Any impact is not expected to be significant. 15 Effective February 1, 2007 the Company adopted FIN 48 which prescribes a more-likely-than-not threshold for financial statement recognition and measurement to a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition of income tax income tax assets and liabilities, classification of current and deferred income tax assets and liabilities, accounting for income taxes in interim periods and income tax disclosures. The Company is subject to examination in the U.S. federal and state tax jurisdiction of the 2000 to 2008 tax years. There are no current examinations of the Company's prior tax returns. The Company has not filed any U.S or state income tax returns since 2001. The penalty and interest charges on the delinquent returns is estimated to be minimal due to net operating losses incurred in each year of operations. No penalty and interest on any tax positions have been computed and the Company does not anticipate there will be a charge in the FIN 48 position in the next 12 months. 10. EARNINGS PER SHARE SFAS 128 requires a reconciliation of the numerator and denominator of the basic and diluted earnings per share (EPS) computations. The following reconciles the components of the EPS computation for the years ended January 31, 2009 and 2008: 2009 2008 ---- ---- Basic (loss) per share computation Numerator: Net loss $ (2,467,642) $ (1,469,335) Denominator: Weighted average common shares outstanding 83,046,405 79,237,416 Basic (loss) per share $ (0.03) $ (0.02) Diluted (loss) per share Numerator: Net loss $ (2,467,642) $ (1,469,335) Denominator: Weighted average common shares outstanding 83,046,405 79,237,416 Diluted (loss) per share $ (0.03) $ (0.02) 16 11. ASSET RETIREMENT OBLIGATION The following table provides a roll forward of the asset retirement obligations: Year Ended Year Ended January 31, 2009 January 31, 2008 ---------------- ---------------- Asset retirement obligation beginning balance $ 41,627 $ 103,687 Liabilities incurred 68,293 -- Liabilities settled (17,890) -- Liabilities transferred to purchaser -- (65,013) Accretion expense 19,387 2,953 ---------------- ---------------- Asset retirement obligation ending balance 111,417 41,627 Less current portion (23,691) -- ---------------- ---------------- Asset retirement obligation, long-term $ 87,726 $ 41,627 ================ ================ 12. CAPITAL LEASE The Company has a lease on a copier through October, 2012. This lease has been classified as a capital lease as the lease term is more than 75% of the estimated economic life of the copier. The balances on the lease are as follows: Year Ended Year Ended January 31, 2009 January 31, 2008 ---------------- ---------------- Remaining lease payments $ 9,855 $ -- Imputed interest (2,691) -- ---------------- ---------------- Copier lease balance 7,164 $ -- Less current portion (1,444) -- ---------------- ---------------- Copier lease, long-term $ 5,720 $ -- ================ ================ Future principal payments over the next five years are as follows: 2010 -$1,445; 2011 - $1,746; 2012 - $2,108; 2013 - $1,865. 13. OPERATING LEASES The Company has one operating lease for office equipment requiring payment through October 2012. All leases are warranted with full maintenance. The minimum annual rental commitment as of January 31, 2009 under non-cancellable leases is as follows: 2010 - $3,937; 2011 - $909. 17 14. MAJOR PURCHASERS The Company's natural gas and oil production is sold under contracts with various purchasers. Natural gas sales to one purchaser approximated 54% of total natural gas and oil revenues for the year ended January 31, 2009. The Company sold gas to Energas Pipeline Company, which was owned by George G. Shaw, the Company's President. These sales generated marketing and transportation fees of approximately $13,600 and $13,500 during years ended January 31, 2009 and 2008, respectively. 15. FINANCIAL INSTRUMENTS In September 2006, the FASB issued SFAS No. 157 "Fair Value Measurements" in order to establish a single definition of fair value and a framework for measuring fair value in generally accepted accounting principles (GAAP) that is intended to result in increased consistency and comparability in fair value measurements. SFAS No. 157 also expands disclosures about fair value measurements. SFAS No. 157 applies whenever other authoritative literature requires (or permits) certain assets or liabilities to be measured at fair value, but does not expand the use of fair value. SFAS No. 157 was originally effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years with early adoption permitted. In early 2008, the FASB issued Staff Position (FSP) FAS-157-2, "Effective Date of FASB Statement No. 157," which delays by one year, the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The delay pertains to items including, but not limited to, non-financial assets and non-financial liabilities initially measured at fair value in a business combination, non-financial assets recorded at fair value at the time of donation, and long-lived assets measured at fair value for impairment assessment under SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets". The Company has adopted the portion of SFAS No. 157 that has not been delayed by FSP FAS-157-2 as of the beginning of its 2009 fiscal year, and plans to adopt the balance of its provisions as of the beginning of its 2010 fiscal year. Items carried at fair value on a recurring basis (to which SFAS No. 157 applies in fiscal 2009) consist of available for sale securities based on quoted prices in active or brokered markets for identical as well as similar assets and liabilities. Items carried at fair value on a non-recurring basis (to which SFAS No. 157 will apply in fiscal 2010) generally consist of assets held for sale. The Company also uses fair value concepts to test various long-lived assets for impairment. The Company is continuing to evaluate the impact the standard will have on the determination of fair value related to non-financial assets and non-financial liabilities in post-2009 years. Fair value of assets and liabilities measured on a recurring basis at January 31, 2009 are as follows: 18 Fair Value Measurement at Reporting Date Using ------------------------------------------------------ Quoted Prices In Active Markets for Significant Identical Other Significant Assets/ Observable Unobservable Liabilities Inputs Inputs Fair Value (Level 1) (Level 2) (Level 3) ---------- ------------ ----------- ------------ Note receivable $950,000 $950,000 ========== ========== Level 2 inputs include the signed and completed contract for sale of note receivable to third party and subsequent collection by the Company. 16. CONTINGENCIES In the normal course of its operations, the Company may, from time to time, be named in legal actions seeking monetary damages. While the outcome of these matters cannot be estimated with certainty, management does not expect, based upon consultation with legal counsel, that they will have a material effect on the Company's business or financial condition or results of operations. The Company has considered the likelihood of loss contingency in its evaluation of the collectability of the note receivable as discussed in Note 5. 17. STOCK-BASED COMPENSATION Incentive Stock Option Plan. The Company's Incentive Stock Option Plan authorizes the issuance of up to 2,000,000 shares of the Company's common stock to persons that exercise options granted pursuant to the Plan. Only Company employees may be granted options pursuant to the Incentive Stock Option Plan. The option exercise price is determined by the Company's Board of Directors but cannot be less than the market price of the Company's common stock on the date the option is granted. Non-Qualified Stock Option Plan. The Company's Non-Qualified Stock Option Plan authorizes the issuance of up to 1,000,000 shares of the Company's common stock to persons that exercise options granted pursuant to the Plans. The Company's employees, directors, officers, consultants and advisors are eligible to be granted options pursuant to the Plans, provided however that bona fide services must be rendered by such consultants or advisors and such services must not be in connection with the offer or sale of securities in a capital-raising transaction. The option exercise price is determined by the Company's Board of Directors. Stock Bonus Plan. The Company's Stock Bonus Plan allows for the issuance of up to 4,000,000 shares of common stock. Such shares may consist, in whole or in part, of authorized but unissued shares, or treasury shares. Under the Stock Bonus Plan, the Company's employees, directors, officers, consultants and advisors are eligible to receive a grant of the Company's shares, provided however that bona fide services must be rendered by consultants or advisors and 19 such services must not be in connection with the offer or sale of securities in a capital-raising transaction. The following table shows the weighted average exercise price of the outstanding options granted pursuant to the Company's Incentive and Non-Qualified Stock Option Plans as of January 31, 2009. The Company's Incentive and Non-Qualified Stock Option Plans were not approved by the Company's shareholders. Number of Securities Remaining Available For Future Issuance Number of Securities Under Equity to be Issued Upon Compensation Plans Exercise of Weighted-Average (Excluding Securities Outstanding Exercise Price of Reflected in Plan Category Options [a] Outstanding options column [a] --------------------------------------------------------------------------------- Incentive Stock Option Plan -- -- 2,000,000 Non-Qualified Stock Option Plan -- -- 750,000

The following table provides information as of January 31, 2009 concerning the stock options and stock bonuses granted by the Company pursuant to the Plans. Each option represents the right to purchase one share of the Company's common stock. Shares Total Shares Reserved for Remaining Reserved Under Outstanding Shares Issued Options/Shares Name of Plan Plans Options As Stock Bonus Under Plans -------------------------------------------------------------------------------- Incentive Stock Option Plan 2,000,000 -- N/A 2,000,000 Non-Qualified Stock Option Plan 1,000,000 -- N/A 750,000 Stock Bonus Plan 4,000,000 -- 2,036,981 1,963,019 The following table summarizes the options and stock bonuses granted pursuant to the Plans as of January 31, 2009: Incentive Stock Options ----------------------- Options Exercised as of Shares Subject to Expiration January 31, Option Exercise Price Date of Grant Date of Option 2009 -------------------------------------------------------------------------------- None -- -- -- -- 20 Non-Qualified Stock Options --------------------------- Options Exercised as of Shares Subject to Expiration January 31, Option Exercise Price Date of Grant Date of Option 2009 -------------------------------------------------------------------------------- 250,000 $0.32 6-30-03 7-15-05 250,000 Stock Bonus Plan ---------------- Shares Issued as Stock Name Bonus (1)(2) Date Issued -------------------------------------------------------------------------------- George Shaw 100,000 10/30/03 Scott Shaw 100,000 10/30/03 Employees and consultants 1,836,981 Various dates --------------------------- 2,036,981 =========================== (1) In October 2006 the Company issued 150,000 shares of its restricted common stock to George Shaw and 150,000 shares to Scott Shaw for services rendered. However the shares issued in October 2006 were not issued pursuant to the Company's Stock Bonus Plan. Shares were valued at market price on the date of grant. (2) In October 2008 the Company issued 750,000 shares of its restricted common stock to George Shaw and 750,000 shares to Scott Shaw for services rendered. However the shares issued in October 2008 were not issued pursuant to the Company's Stock Bonus Plan. Shares were valued at market price on the date of grant. 18. RECLASSIFICATIONS As discussed in Note 5, management believed the collection of the note receivable in cash funds to be questionable and so determined to reflect the receivable on the balance sheet in the form of the underlying collateral. This classification as properties held for resale on the prior balance sheet of January 31, 2008 has been reclassified as a note receivable in the accompanying consolidated balance sheet. There were no reclassifications made to either the consolidated statements of operations or statements of cash flows presented herein. 19. SFAS 69 SUPPLEMENTAL DISCLOSURES (UNAUDITED) Net Capitalized Costs The Company's aggregate capitalized costs related to natural gas and oil producing activities are summarized as follows: 21 Natural gas and oil properties and January 31, 2009 January 31, 2008 ---------------------------------- Related lease equipment: Proved $ 2,606,814 $ 2,380,633 Unproved 162,012 16,845 ---------------------------------- 2,768,826 2,397,478 Accumulated depreciation, depletion and impairment (2,249,545) (904,302) ---------------------------------- Net capitalized costs $ 519,281 $ 1,493,176 ================================== Unproved properties not subject to amortization consisted mainly of leasehold acquired through acquisitions. The Company will continue to evaluate its unproved properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined. Costs Incurred Costs incurred in natural gas and oil property acquisition, exploration and development activities that have been capitalized are summarized as follows: Years Ended January 31, 2009 2008 ---- ---- Acquisition of properties Proved $ - $ - Unproved - - Exploration costs - - Development costs 692,948 575,367 Equity investment in Snyder Well Partnership 39,000 - ---------- ---------- $ 731,948 $ 575,367 ========== ========== Results of Operations for Natural Gas and Oil Producing Activities The Company's results of operations from natural gas and oil producing activities are presented below for the fiscal years ended January 31, 2009 and 2008. The following table includes revenues and expenses associated directly with the Company's natural gas and oil producing activities. It does not include any interest costs and general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of the Company's natural gas and oil operations. Years Ended January 31, 2009 2008 ---- ---- Production revenues $ 272,223 $ 431,959 Production and transportation costs (133,470) (201,826) Impairment of property (1,225,455) (701,691) Gain on sale of properties 267,549 Depletion expense (119,786) (126,315) ----------- ----------- (938,939) (597,873) Imputed income tax provision (1) - - ----------- ----------- 22 Results of operation for natural gas/oil producing activity $ (938,939) $ (597,873) =========== =========== (1) The imputed income tax provision is hypothetical (at the statutory rate) and determined without regard to the Company's deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision will be payable. Natural Gas and Oil Reserve Quantities The following schedule contains estimates of proved natural gas and oil reserves attributable to the Company. Proved reserves are estimated quantities of natural gas and oil that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Reserves are stated in thousand cubic feet (mcf) of natural gas and barrels (bbl) of oil. Geological and engineering estimates of proved natural gas and oil reserves at one point in time are highly interpretive, inherently imprecise and subject to ongoing revisions that may be substantial in amount. Although every reasonable effort is made to ensure that the reserve estimates are accurate, due to their nature reserve estimates are generally less precise than other estimates presented in connection with financial statement disclosures. Gas - mcf Oil - bbls --------------- ---------------- Proved reserves: Balance, January 31, 2007 1,942,040 22,143 Sale of reserves in place (1,136,665) (3,256) Revisions of previous estimates 615 36,521 Production (59,491) (1,499) --------------- ---------------- Balance, January 31, 2008 746,499 53,909 --------------- ---------------- Sale of reserves in place (298,035) Revisions of previous estimates (41,548) (47,118) Production (28,157) (1,147) --------------- ---------------- Balance, January 31, 2009 378,759 5,644 =============== ================ Proved developed reserves: Balance, January 31, 2009 378,759 5,644 Balance, January 31, 2008 746,499 53,909 Standardized Measure of Discounted Future Net Cash Flows: The following schedule presents the standardized measure of estimated discounted future net cash flows from the Company's proved reserves for the fiscal years ended January 31, 2009 and 2008. Estimated future cash flows are based on independent reserve data. Because the standardized measure of future net cash flows was prepared using the prevailing economic conditions existing at January 31, 2009 and 2008, it should be emphasized that such conditions continually 23 change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of the Company's recoverable reserves or in estimating future results of operations. Years Ended January 31, 2009 2008 ---- ---- Future production revenues (1) $ 1,358,079 $ 8,271,034 Future production costs (627,398) (2,566,873) Future development costs -- (624,258) Future income tax -- (1,214,654) ------------ ------------ Future net cash flows 730,681 3,865,249 Effect of discounting future annual cash flows at 10% (373,412) (1,787,576) ------------ ------------ Standardized measure of discounted net cash flows $ 357,269 $ 2,077,673 ============ ============ (1) The weighted average natural gas and oil wellhead prices used in computing the Company's reserves were $3.18 per mcf and $27.22 per bbl at January 31, 2009 as compared to $6.06 per mcf and $69.15 per bbl at January 31, 2008. The following schedule contains a comparison of the standardized measure of discounted future net cash flows to the net carrying value of proved natural gas and oil properties at January 31, 2009 and 2008: Years Ended January 31, 2009 2008 ---- ---- Standardized measure of discounted future net cash flows $ 357,269 $ 2,077,673 Proved natural gas & oil property net of Accumulated depreciation, depletion and amortization, including impairment of $1,248,954 and $280,201 at January 31, 2009 and 2008, respectively 357,269 1,479,331 ------------ ------------ Standardized measure of discounted future net cash flows in excess of net carrying value of proved natural gas & oil properties $ -- $ 598,342 ============ ============ The following reconciles the change in the standardized measure of discounted future net cash flow for the years ended January 31, 2009 and 2008. Years Ended January 31, 2009 2008 ---- ---- Beginning balance $ 2,077,673 $ 4,416,660 Sales of oil and gas produced, net of net of production costs (150,827) (230,133) 24 Net changes in prices and production costs (718,537) (1,751,017) Sales of reserves in place (597,908) (1,014,763) Revisions of estimated quantities, less related development costs (1,520,861) 349,596 Accretion of discount 53,075 77,338 Net change in income taxes 1,214,654 229,992 ------------ ------------ Ending balance $ 357,269 $ 2,077,673 ============ ============ 20. DRILLING OBLIGATION On November 24, 2008, Corp. acquired a working interest pursuant to a joint development agreement. The agreement requires the drilling of a total of five wells at a price of $39,000 per well. Four payments remain outstanding as of January 31, 2009 for a total accrued obligation of $156,000 as of January 31, 2009. 21. SUBSEQUENT EVENTS February 10, 2009 Signed a letter of intent to purchase a natural gas gathering pipeline system in Callahan and Shackleford Counties, Texas. February 11, 2009 Issued 200,000 shares of common stock to unrelated party in settlement of $16,000 outstanding obligation. February 23, 2009 Issued 220,000 shares of common stock to five consultants in payment for services rendered to the Company. February 27, 2009 Sold note receivable and collected $921,091. March 9, 2009 Acquired a 2% ORRI in the Callahan County, Texas prospect for $161,000. April 2, 2009 Acquired additional acreage to expand the Callahan County, Texas project. SIGNATURES In accordance with Section 13 or 15(a) of the Exchange Act, the Registrant has caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized on the 15th day of June 2009. ENERGAS RESOURCES, INC. By: /s/ George G. Shaw --------------------------------------- George G. Shaw, President, Principal Accounting Officer and Principal Financial Officer In accordance with the Exchange Act, this Report has been signed by the following persons on behalf of the Registrant in the capacities and on the dates indicated. Title Date /s/ George G. Shaw ------------------------ George G. Shaw Director June 15, 2009 /s/ G. Scott Shaw ------------------------ G. Scott Shaw Director June 15, 2009 ENERGAS RESOURCES, INC. FORM 10-K EXHIBITS

ENERGAS RESOURCES INC 10-K