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, 2010

o	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 of incorporation or organization)		(I.R.S. Employer Identification No.)

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. o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o

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 o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

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. o

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 o	Accelerated filer o

Non-accelerated filer o	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): o Yes x No

The aggregate market value of the voting stock held by non-affiliates of the Company on July 31, 2009 was approximately $1,023,080.

As of April 30, 2010, the Company had 94,150,144 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.

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.

(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 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.

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.

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, 2010 this well was shut in.

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 the Company 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, in addition to leasehold costs of $39,000, Excalibur will receive an 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, 2010 was in the process of being evaluated.

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.

On July 29, 2009, the Company acquired an 85% working interest (62.7598% net revenue interest) in an oil and gas well located in Uintah County, Utah for $40,000 in cash and 1,000,000 shares of its Series A Preferred stock. The Series A Preferred shares will collectively be entitled to a dividend, payable quarterly, based upon 10% of the Company’s net profits derived from the sale of any oil or gas produced from the well. For purposes of the Series A shares, net profits is defined as 10% of the Company’s share of the gross revenues derived from the sale of any oil or gas produced from the well, less the Company’s share of all costs and expenses associated with drilling, completing, reworking or operating the well. The Series A Preferred shares do not have any voting rights except as provided by Delaware law.

The well acquired in the transaction is presently shut-in. The Company estimates that it will spend approximately $355,000 in efforts to return the well to production.

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:

	Year Ended January 31,
	2008				2009				2010
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells (1):
Productive:
Oil		—		—		—		—		—		—
Gas		—		—		—		—		—		—
Nonproductive		1		.422		—		—		—		—
Development Wells (1):
Productive:
Oil		—		—		—		—		—		—
Gas		—		—		—		—		—		—
Nonproductive		—		—		1		.53		—		—
Total Wells (1):
Productive:
Oil		—		—		—		—		—		—
Gas		—		—		—		—		—		—
Nonproductive		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, 2010, 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		2		.66345
Wyoming		1		.358		40		14.3		600		214.8
Texas		-		-		40		16.0		2,520		1,008.0
Totals		3		1.02145		80		30.3		3,120		1,222.8

(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, 2010 the status of Company’s gross acreage.

	Held by Production		Not Held by Production
Oklahoma
Wyoming		640
Texas		40		2,520

(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,
	2008		2009		2010
Production Data:
Production –
Oil (Bbls)		1,499		1,147		1,052
Gas (Mcf)		59,491		28,157		18,502
Average sales price –
Oil (Bbls)	$	56.48	$	81.02	$	53.81
Gas (Mcf)	$	5.88	$	6.35	$	3.23
Average production
costs per MCFE	$	2.90	$	1.38	$	1.68

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 FASB ASC 932 (formerly 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,
	2008				2009				2010
	Oil		Gas		Oil		Gas		Oil		Gas
	(Bbls)		(Mcf)		(Bbls)		(Mcf)		(Bbls)		(Mcf)
Proved reserves		53,909		746,499		5,644		378,759		101,494		2,718,744
Estimated future net cash flows from proved oil and gas reserves	$3,865,249				$730,682				10,258,494

Present value of future net cash flows from proved oil and gas reserves	$2,077,673				$357,270				6,807,436

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 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 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 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.

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, 2010, the Company employed 4 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.

ITEM 3.

LEGAL PROCEEDINGS

In July 2009 the Company entered into two option agreements with Lex Dolton. The first option was exercised in July 2009. The second agreement provided the Company with the option to acquire a 50% working interest in oil and gas leases in Utah in exchange for the issuance of 2,000,000 shares of the Company’s Series C preferred stock. Each Series C preferred share would be entitled to a quarterly dividend based on the amount received from the sale of oil or gas produced from any wells drilled on the leased acreage.

In August 2009, the Company notified Dolton that it had elected to exercise the second option and was prepared to issue the Series C preferred stock pursuant to the agreement. Nevertheless, Dolton refused to assign the working interest to the Company.

On November 16, 2009, as a result of Dolton’s failure to assign the working interest pursuant to the second option agreement, the Company filed suit against Dolton in the District Court of Arapahoe County, Colorado. In its complaint, the Company seeks damages for breach of contract and a mandatory injunction requiring Dolton to assign the working interest.

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, 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

April 30, 2009	$	0.11	$	0.055
July 31, 2009	$	0.07	$	0.015
October 31, 2009	$	0.059	$	0.021
January 31, 2010	$	0.04	$	0.015

As of April 30, 2010 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.

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, 2010 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, 2010 the Company did not have any outstanding options, warrants or other securities convertible into common stock.

See Item 11 of this report for information concerning the Company’s outstanding options and warrants.

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 Company principally operates in the Arkoma Basin in Oklahoma, the Powder River Basin in Wyoming, Uintah County, Utah and in Callahan County, Texas.

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. 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.

RESULTS OF OPERATIONS

Material changes of certain items in the Company's Statement of Operations for the year ended January 31, 2010 are discussed below.

Item	Increase (I) or Decrease (D)	Reason
Oil and gas sales	D	Production and price decrease.

Lease operating expense	D	Less legal expense, no major repairs.

General and administrative Expense	I	Increase in legal fees, accounting fees and contract services.

Depreciation, depletion and amortization	D	Decline of production

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 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.

Other than the foregoing 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.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s material sources and (uses) of cash during the years ended January 31, 2010 and 2009 were:

	2010			2009
Cash used in operations	$	(279,458	)	$	(74,048	)
Acquisition and development of oil and gas properties		(775,995	)		(692,948	)
Cash resulting from purchase of subsidiaries		—			71,297
Investment in partnership		—			(39,000	)
Payments on note receivable		950,000			87,980
Sale of oil and gas properties		—			590,400
(Payments to) advances from related parties		49,469			96,327
Advances (net of repayments) on capital lease		(1,445	)		7,164
Cash supplied from cash on hand at beginning of twelve month period	$	(57,429	)	$	47,172

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.

Contractual Obligations

Except as shown in the following table, as of January 31, 2010, 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, 2010 are as follows:

	Total	2011		2012		2013		Thereafter
Office equipment leases	6,628		2,655		2,108		1,865		—
Drilling obligation	156,000		0		156,000		—		—

Critical Accounting Policies

See Note 3 to the financial statements included as part of this report.

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.

On July 15, 2009 Eide Bailly LLP resigned as the Company’s independent registered public accounting firm.

The report of Eide Bailly regarding the Company’s financial statements for the fiscal year ended January 31, 2009 did not contain any adverse opinion or disclaimer of opinion and was not qualified or modified as to uncertainty, audit scope or accounting principles. However, the report of Eide Bailly for that fiscal year was qualified with respect to uncertainty as to the Company’s ability to continue as a going concern. During the year ended January 31, 2009, and during the period from January 31, 2009 through July 15, 2009, the date of resignation, there were no disagreements with Eide Bailly 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 Eide Bailly would have caused it to make reference to such disagreement in its reports.

On August 12, 2009, the Company, through and with the approval of its Board of Directors, engaged Smith, Carney & Co., p.c. as its independent registered public accounting firm.

Prior to engaging Smith, Carney, the Company did not consult with Smith, Carney regarding the application of accounting principals to a specific completed or contemplated transaction or regarding the type of audit opinions that might be rendered by Smith, Carney on the Company’s financial statements, and Smith, Carney 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.

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 Exchange Act of 1934 as of January 31, 2010. 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, 2010 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.

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, 2010 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	79	President, Principal Financial Officer, Principal Accounting Officer and a Director
G. Scott Shaw	38	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 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, 2010 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, 2010, 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, 2010.

Name and Principal Position	Fiscal Year	Salary (1)		Bonus (2)		Stock Awards (3)		Option Awards (4)		All Other Annual Compen- sation (5)		Total
George Shaw,	2010	$	39,000			$	5,000					$	44,000
President	2009	$	36,000			$	15,375					$	51,375
	2008	$	36,000		—	$	15,000		—		—	$	51,000
Scott Shaw	2010	$	48,000			$	5,000					$	53,000
Vice President	2009	$	48,000			$	3,750					$	51,750
	2008	$	48,000			$	7,500					$	55,500

(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 FASB ASC 718 (formerly FAS 123R).

(4)	The amount recognized for financial statement reporting purposes and calculated in accordance with FASB ASC 718 (formerly 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 during the twelve month period ending January 31, 2011, 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.

Name	Proposed Compensation		Time to Be Devoted 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, 2010. The Company’s Incentive and Non-Qualified Stock Option Plans were not approved by the Company's shareholders.

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options [a]		Weighted-Average Exercise Price of of Outstanding Options		Number of Securities Remaining Available For Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in 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, 2010 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.

Name of Plan	Total Shares Reserved Under Plans		Shares Reserved for Outstanding Options		Shares Issued As Stock Bonus		Remaining Options/ Shares 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		—		2,036,981		1,963,019

The following table summarizes the options and stock bonuses granted pursuant to the Plans as of April 30, 2010:

Incentive Stock Options

Shares Subject To Option

Exercise Price

Date of Grant

Expiration Date of Option

Options Exercised as of April 30, 2010

None.

Non-Qualified Stock Options

Shares Subject To Option				Exercise Price				Date of Grant				Expiration Date of Option				Options Exercised as of April 30, 2010
	250,000			$	0.32				6-30-03				7-15-05				250,000

Stock Bonuses

Name	Shares Issued as Stock Bonus		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

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.

Name	Shares Issued for 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
George Shaw		500,000		1/2010
Scott Shaw		500,000		1/2010

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS ANDMANAGEMENT

The following table shows the ownership of the Company’s common stock as of April 30, 2010 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, 2010 the Company did not have any outstanding options, warrants or other securities convertible into common stock.

Name and address	Shares Beneficially Owned			Percent of Outstanding Shares
George G. Shaw		21,633,649	(1)		22.98	%
Third Floor, 800 Northeast 63rd Street Oklahoma City, Oklahoma 73105
G. Scott Shaw		8,178,905			8.68	%
800 Northeast 63rd Street Oklahoma City, Oklahoma 73105
Terry R. and Marguerite S. Tyson 16250 County Rd. U Lipscomb, TX 79056-6304		8,792,800			9.34	%
Executive Officers and Directors as a group (two persons)		38,605,354			41.0	%

(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, 2010, 2009 and 2008 the Company paid rent of $48,000, $47,600 and $45,600, respectively. In addition, and prior to January 31, 2009, Mr. Shaw owned Energas Pipeline Company which operates the natural gas gathering system to which the Company's three wells in Atoka County, Oklahoma are connected. During the years ended January 31, 2010, 2009 and 2008 Energas Pipeline Company received $-0-, $13,658 and $13,550, 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, 2010 the Company had borrowed $90,706 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 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

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
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.

Smith Carney & Co., P.C. served as the Company's independent public accountants during the fiscal year ended January 31, 2010. The following table shows the aggregate fees billed to the Company during the year ended January 31, 2010 by Eide Bailly and Smith Carney & Co.

	2010
Audit Fees	$	99,830
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 Smith Carney & Co. was engaged by the Company to render audit services, the engagement was approved by the Company’s Board of Directors.

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	*

31.	Rule 13a-14(a)/15d-14(a) certifications	58

32.	Section 1350 certifications	60

*	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.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Energas Resources, Inc.:

We have audited the accompanying consolidated balance sheets of Energas Resources, Inc. as of January 31, 2010 and the related consolidated statements of operations, stockholders' equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 provide 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, 2010 and the results of its operations and cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company 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 to the financial statements, 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/ Smith, Carney & Co., p.c.

Oklahoma City, Oklahoma

May 17, 2010

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

ENERGAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

	January 31,			January 31,
	2010			2009
ASSETS

Current Assets
Cash	$	18,647		$	76,076
Restricted cash		25,637			25,049
Accounts receivable		87,563			54,539
Deposits		14,315			-
Total Current Assets		146,162			155,664
Property and Equipment
Oil and gas properties, using full cost accounting
Proved properties		9,858,142			2,606,814
Unproved properties		251,352			162,012
Pipelines and gathering systems		-			-
		10,109,494			2,768,826
Less accumulated depreciation, depletion, and amortization,
including impairment of $2,637,686 and $1,505,656		(3,435,598	)		(2,249,545	)
		6,673,896			519,281
Other, net of accumulated depreciation of $41,651 and $34,035		10,351			14,474
		6,684,247			533,755
Goodwill		146,703			146,703
Property held for resale		350,000			-
Drilling receivable		156,000			-
Investment in partnership		-			39,000
Note Receivable, net of allowance of $0 and $1,162,020		-			950,000

Total Assets	$	7,483,112		$	1,825,122

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued expenses	$	550,457		$	219,791
Advanced drilling funds		-			126,263
Due to related parties		90,706			40,431
Current portion of lease		1,746			1,444
Current asset retirement obligation		54,682			23,691
Note payable		-			16,000
Total Current Liabilities		697,591			427,620

Asset Retirement Obligation		109,828			87,726
Long-term lease		3,973			5,720
Drilling commitment		156,000			156,000
Total Liabilities		967,392			677,066

Stockholders' Equity
Preferred stock, $0.0001 par value, 20,000,000 share authorized, 1,000,000
shares designated Series A, 1,000,000 shares issued and outstanding
January 31, 2010		100			-
Common stock, $.001 par value 100,000,000 shares authorized 94,150,144 and
90,700,144 shares issued and outstanding at January 31, 2010 and 2009, Respectively		94,150			90,700
Additional paid in capital		26,572,530			19,308,395
Retained (deficit)		(20,151,060	)		(18,251,039	)
Total Stockholders' Equity		6,515,720			1,148,056
Total Liabilities and Stockholders' Equity	$	7,483,112		$	1,825,122

See accompanying notes to consolidated financial statements.

F-3

ENERGAS RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended
	January 31,
	2010			2009
Revenue
Oil and gas sales	$	116,291		$	272,223
Overhead and marketing revenue		39,487			-
Pipeline revenue		10,015			12,074
Total Revenue		165,793			284,297
Operating Expenses
Lease operating expense		80,281			119,038
Pipeline and gathering expense		2,925			14,432
General and administrative expense		613,044			498,615
Bad debt expense		-			1,160,997
Property impairments		1,309,189			1,225,455
Depreciation, depletion and amortization		59,461			142,321
Total Operating Expenses		2,064,900			3,160,858
Operating (Loss)		(1,899,107	)		(2,876,561	)
Other (Expenses) Income
Other income		61			-
Interest income		588			140,115
Gain on sale of properties		-			267,549
Gain on sale of subsidiary		-			7,116
Interest expense		(1,563	)		(5,861	)
Total Other (Expense)		(914	)		408,919
Net (Loss) before Income Taxes		(1,900,021	)		(2,467,642	)
Provision for income taxes		-			-
Net (Loss)	$	(1,900,021	)	$	(2,467,642	)
Net (Loss) per Share, Basic and Diluted	$	(0.02	)	$	(0.03	)
Weighted average of number of shares outstanding		92,327,788			83,046,405

See accompanying notes to consolidated financial statements.

F-4

ENERGAS RESOURCES, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

FOR THE YEARS ENDED JANUARY 31, 2010 AND

JANUARY 31, 2009

	Common Stock				Preferred Stock				Additional Paid-In Capital		Accumulated Deficit			Total Shareholders' Equity
	Shares		Amount		Shares		Amount		Additional Paid-In Capital		Accumulated Deficit			Total Shareholders' Equity
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	)
Restricted stock issued for compensation		2,000,000		2,000		-		-		39,000		-			41,000
Stock issued for purchase of subsidaries		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
Net loss												(1,900,021	)		(1,900,021	)
Stock issued for conversion of debt		200,000		200		-		-		15,800		-			16,000
Stock issued for services		750,000		750		-		-		51,750		-			52,500
Stock issued for purchase of gathering system		1,000,000		1,000		-		-		59,000		-			60,000
Preferred stock issued for purchase of properties						1,000,000		100		7,124,085		-			7,124,185
Restricted stock issued for compensation		1,500,000		1,500						13,500		-			15,000
Balance, January 31, 2010		94,150,144	$	94,150		1,000,000	$	100	$	26,572,530	$	(20,151,060	)	$	6,515,720

See accompanying notes to consolidated financial statements.

F-5

ENERGAS RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended January 31,
	2010			2009
Cash Flows From Operating Activities
Net (Loss)	$	(1,900,021	)	$	(2,467,642	)
Adjustments to reconcile net loss to net cash used by
operating activities
Depreciation, depletion and amortization		59,461			142,320
Bad debt provision		-			1,160,997
Gain on sale of subsidiary		-			(7,115	)
Gain on sale of properties		-			(267,549	)
Property impairments		1,309,189			1,225,455
Common stock issued for services		67,500			41,000
(Increase) Decrease in
Restricted cash		(588	)		-
Accounts receivable		(33,024	)		130,216
Deposits		(13,509	)		-
Increase (Decrease) in
Accounts payable and accrued expenses		330,666			(231,791	)
Drilling advances		(126,263	)		126,263
Accrued interest		-			4,008
Asset retirement obligation		27,131			69,790
Net Cash Flows Used By Operating Activities		(279,458	)		(74,048	)
Cash Flows From Investing Activities
(Investment in) oil and gas properties		(775,995	)		(692,948	)
Cash received from purchase of subsidiaries		-			64,182
Sale of subsidiary		-			7,115
Investment in partnership		-			(39,000	)
Payments on note receivable		950,000			87,980
Sale of oil and gas properties		-			590,400
Net Cash Provided By Investing Activities		174,005			17,729
Cash Flows from Financing Activities
Advances from (Repayments to) related parties and stockholders		49,469			96,327
Advances on capital lease		-			8,708
Payments on capital lease		(1,445	)		(1,544	)
Net Cash Provided By (Used By) Financing Activities		48,024			103,491
Increase (Decrease) in Cash		(57,429	)		47,172
Cash at Beginning of Period		76,076			28,904
Cash at End of Period	$	18,647		$	76,076
Supplemental Information:
Interest Paid in Cash	$	1,563		$	1,853
Income Taxes Paid	$	-		$	-
Non-Cash Transactions:
Common stock issued for consulting services	$	22,500		$	-
Common stock issued for engineering services	$	30,000		$	-
Common Stock issued for purchase of gathering system	$	60,000		$	-
Restricted stock issued for compensation	$	15,000		$	41,000
Common Stock issued for purchase of subsidiaries	$	-		$	249,655
Preferred stock issued for oil and gas properties	$	7,124,185		$	-

See accompanying notes to consolidated financial statements.

F-6

ENERGAS RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED JANUARY 31, 2010 AND 2009

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, 2010, the Company had incurred losses for the years ended January 31, 2010 and 2009 of $(1,900,021) and $(2,467,642), 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.

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.

F-7

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 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.

F-8

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 accounting guidance the Company records the fair value of its liability for asset retirement obligations at the time a well is completed and ready for production 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 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 7.

Earnings per share - The Company follows accounting guidance for computing and presenting earnings per share, which requires, among other things, 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, 2010 and 2009, 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 updated accounting guidance regarding stock-based compensation, 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 the updated accounting guidance, 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 accounting guidance. Results for prior periods have not been restated, as provided for under the modified-prospective method.

F-9

The updated accounting guidance 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 the updated accounting guidance 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, 2010 and 2009, and there was no stock-based compensation expense included in net income for these periods subject to the option pricing considerations discussed above.

The Company awarded 1,500,000 and 2,000,000 shares of restricted common stock to employees on January 21, 2010 and September 26, 2008, respectively. Using the discounted market price of $0.01 and $.0205 on the date of the grant, the Company has recognized stock based compensation of $15,000 and $41,000 during the years ended January 31, 2010 and 2009, respectively.

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.

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 ASC Topic 350, "Intangibles - Goodwill and Other".

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, 2010 and 2009. An allowance for bad debt was recorded against the note receivable as of January 31, 2009 as discussed further in Note 7.

Financial Instruments – The carrying value of current assets and liabilities reasonably approximates their fair value due to their short maturity periods.

F-10

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 an interpretation of accounting guidance regarding accounting for uncertainty in income taxes. The interpretation 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. The interpretation also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

Under the interpretation, 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 the interpretation at February 1, 2007 did not have a material effect on the Company’s financial position.

Segment Reporting – Accounting guidance 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 June 2009 the FASB established the Accounting Standards Codification (“Codification” or “ASC”) as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in accordance with GAAP. Rules and interpretive releases of the SEC issued under authority of federal securities laws are also sources of GAAP for SEC registrants. Existing GAAP was not intended to be changed as a result of the Codification, and accordingly the change did not impact the Company’s financial statements. The ASC does change the way the guidance is organized and presented.

F-11

In December 2007, the Financial Accounting Standards Board, (FASB), issued new accounting guidance regarding non-controlling interests in consolidated financial statements. The new guidance establishes new accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. The new guidance is effective for fiscal years beginning on or after December 15, 2008. Management adopted this guidance on February 1, 2009 and the adoption of the guidance did not have a material impact to the Company’s financial position, results of operations, or cash flows.

In March 2008, the FASB issued updated accounting guidance regarding disclosures about derivative instruments and hedging activities. The updated guidance 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 current accounting guidance 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 updated guidance is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. Management adopted this updated guidance on February 1, 2009 and the adoption of the guidance did not have a material impact to the Company’s financial position, results of operations, or cash flows.

In December 2008, the FASB issued updated accounting guidance regarding 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 the updated guidance are to be provided for fiscal years beginning after December 15, 2009. The Company is currently assessing the impact of this update guidance.

In April 2009, the FASB issued updated accounting guidance to amend and clarify the initial recognition and measurement, subsequent measurement and accounting, and related disclosures arising from contingencies in a business combination. Under the new guidance, assets acquired and liabilities assumed in a business combination that arise from contingencies should be recognized at fair value on the acquisition date if fair value can be determined during the measurement period. If fair value cannot be determined, companies should typically account for the acquired contingencies using existing guidance. We will adopt updated guidance along with prior amended guidance in the first quarter of fiscal 2010 and we do not expect the adoption will have a material effect on our financial position or results of operations.

In April 2009, the FASB issued amended accounting guidance regarding fair value disclosures of financial instruments in interim financial statements. The amended guidance will require disclosures about fair value of financial instruments in financial statements for interim reporting periods and in annual financial statements of publicly-traded companies. This amended guidance also will require entities to disclose the method(s) and significant assumptions used to estimate the fair value of financial instruments in financial statements on an interim and annual basis and to highlight any changes from prior periods. Management adopted this amended guidance on May 1, 2009 and the adoption of amended guidance did not have a material impact to the Company’s financial position, results of operations, or cash flows.

F-12

In April 2009, the FASB issued amended accounting guidance regarding recognition and presentation of other-than-temporary impairments. The guidance amends the other-than-temporary impairment guidance for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities. Management adopted this amended guidance on May 1, 2009 and the adoption of amended guidance did not have a material impact to the Company’s financial position, results of operations, or cash flows.

In April 2009, the FASB issued additional accounting guidance for estimating fair value when the market activity for an asset or liability has declined significantly. Management adopted this additional guidance on May 1, 2009 and the adoption additional guidance did not have a material impact to the Company’s financial position, results of operations, or cash flows.

In May 2009, the FASB issued new accounting guidance regarding subsequent events, which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We have adopted the provisions of the new guidance, which became effective for interim and annual reporting periods ending after June 15, 2009.

In June 2009, the FASB issued amended accounting guidance to address the elimination of the concept of a qualifying special purpose entity. The amended guidance also replaces the quantitative-based risks and rewards calculation for determining which enterprise has a controlling financial interest in a variable interest entity with an approach focused on identifying which enterprise has the power to direct the activities of a variable interest entity and the obligation to absorb losses of the entity or the right to receive benefits from the entity. Additionally, the amended guidance provides more timely and useful information about an enterprise’s involvement with a variable interest entity. The amended guidance will become effective in the first quarter of 2010. The Company is currently evaluating whether this amended guidance will have an impact on the Company consolidated financial statements.

In December 2008, the Securities and Exchange Commission published a Final Rule, “Modernization of Oil and Gas Reporting.” The new rule permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserve volumes. The new requirements also will allow companies to disclose their probable and possible reserves. In addition, the new disclosure requirements require companies to (a) report the independence and qualifications of its reserve preparer, (b) file reports when a third party is relied upon to prepare reserve estimates or conducts a reserve audit, and (c) report oil and gas reserves using an average price based upon the prior 12 month period rather than year end prices. The new requirements were effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. The Company adopted the Final Rule as of January 31, 2010. The adoption of the rule resulted in a lower price used in reserve calculations and a decrease in 2010 reserves. See Note 20 for further discussion of the impact of implementation.

In January 2010, the FASB issued amended accounting guidance to align the oil and gas reserve estimation and disclosure requirements of ASC 932 with the requirements in the Security and Exchange Commission’s Final Rule, “Modernization of Oil and Gas Reporting.” The amendments to the accounting guidance are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. The impact of the adoption of this amended accounting guidance is noted above.

F-13

4. PURCHASE OF GATHERING SYSTEM

On April 14, 2009 the Company issued 1,000,000 shares of common stock valued at $60,000, based on the closing quoted market price of $0.06, for a gas gathering system in Callahan County, Texas. The gas gathering system had not been placed into service as of January 31, 2010 and is now included in properties held for resale.

5. 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 7 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.

6. PURCHASE OF UINTAH COUNTY, UTAH WELL

On July 29, 2009 the Company purchased an 85% working interest, 62.7598% net revenue interest, in the Conoco Federal #22-1 well in Uintah County, Utah for $7,164,185. The company paid $40,000 in cash and 1,000,000 shares of the Company's Series A preferred stock valued at $7,124,185. The fair value of the well was determined by the present value discounted at ten percent (10%) of cash flows from an independent reserve report on the well conducted as of July 1, 2009.

The Company also committed to connect the Conoco Federal #22-1 well to a gathering system within nine months of the purchase of the well. The connection expense is estimated to be $355,475.

The Series A preferred shares are entitled to receive quarterly dividends based upon ten percent of the net profits derived from the Conoco Federal #22-1 well.

7. NOTE RECEIVABLE

At the time of the transaction described in Note 5, 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 accounting guidance 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.

F-14

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. FASB ASC 310 (formerly 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 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, FASB ASC 310 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.

8. 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.

9. 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
Receivables		236,114
Payables		(222,393	)
Goodwill		94,286
	$	197,238

F-15

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. 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

10. RELATED PARTY

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 for the year ended January 31, 2009 for drilling costs, lease operating expenses and overhead. Of the amounts received overhead fees were $54,505 for the year ended January 31, 2009 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 during year ended January 31, 2009. 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 year ended January 31, 2009 Energas Pipeline Company received $13,658 in marketing and transportation fees.

The Company's offices are occupied under a month to month lease 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, 2010 and 2009 the Company paid rent of $48,000 and $47,600, respectively, to the Company's President.

As of January 31, 2010 and 2009 the Company has advances from the Company’s President of $90,706 and $40,431, respectively. These advances have no stated interest and are due on demand.

11. INCOME TAXES

As of January 31, 2010, the Company has approximately $14,581,000 of net operating losses expiring through 2030 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 $5,832,000; 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.

F-16

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:

	Year Ended January 31
	2010			2009
Computed at the federal statutory rate of 34%	$	(646,000	)	$	(839,000	)
State tax (benefit) at statutory rates		(114,000	)		(148,000	)
Property impairments and cost pool		425,000			440,000
Change in valuation allowance		335,000			547,000
Income tax expense	$	-		$	-

Significant components of the Company's deferred tax liabilities and assets are as follows:

	As of January 31
	2010			2009
Deferred tax liabilities – timing in full cost pool	$	(309,000	)	$	(210,000	)
Deferred tax assets – net operating losses		5,832,000			5,646,000
Deferred tax assets – asset impairment		1,014,000			490,000
Valuation allowance for deferred tax assets		(6,537,000	)		(5,926,000	)
Net deferred tax assets	$	-		$	-

The changes in the valuation allowance are as follows:

	Year Ended January 31
	2010			2009
Beginning balance, February 1,	$	(5,926,000	)	$	(5,097,000	)
Expiring Canadian net operating losses		—			158,000
Current year net operating losses		(186,000	)		(547,000	)
Asset impairment		(524,000	)		(490,000	)
Changes in timing of full cost pool		99,000			50,000
Ending balance, January 31,	$	(6,537000	)	$	(5,926,000	)

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 Company is in the process of completing and filing these delinquent returns. The filing of these returns could result in changes to the net operating loss (NOL) carry forwards as currently estimated.

Effective February 1, 2007 the Company adopted accounting guidance 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 guidance 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.

F-17

The Company is subject to examination in the U.S. federal and state tax jurisdiction of the 2001 to 2009 tax years. There are not 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 uncertain tax position in the next 12 months.

12. EARNINGS PER SHARE

Accounting guidance 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, 2010 and 2009:

	2010			2009
Basic (loss) per share computation
Numerator:
Net loss	$	(1,900,021	)	$	(2,467,642	)
Denominator:
Weighted average common shares outstanding		92,327,788			83,046,405
Basic (loss) per share	$	(0.02	)	$	(0.03	)
Diluted (loss) per share
Numerator:
Net loss	$	(1,900,021	)	$	(2,467,642	)
Denominator:
Weighted average common shares outstanding		92,327,788			83,046,405
Diluted (loss) per share	$	(0.02	)	$	(0.03	)

13. ASSET RETIREMENT OBLIGATION

The following table provides a roll forward of the asset retirement obligations:

	Year Ended			Year Ended
	January 31, 2010			January 31, 2009
Asset retirement obligation beginning balance	$	111,417		$	41,627
Liabilities incurred		28,164			68,293
Liabilities settled		—			(17,890	)
Revisions		(2,202	)		—
Accretion expense		27,131			19,387
Asset retirement obligation ending balance		164,510			111,417
Less current portion		(54,682	)		(23,691	)
Asset retirement obligation, long-term	$	109,828		$	87,726

F-18

14. 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, 2010			January 31,2009
Remaining lease payments	$	7,391		$	9,855
Imputed interest		(1,672	)		(2,691	)
Copier lease balance		5,719		$	7,164
Less current portion		(1,746	)		(1,444	)
Copier lease, long-term	$	3,973		$	5,720

Future principal payments over the next five years are as follows: 2011 - $1,746; 2012 - $2,108; 2013 - $1,865.

15. 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: 2011 - $909.

16. MAJOR PURCHASERS

The Company’s natural gas and oil production is sold under contracts with various purchasers. Natural gas sales to one purchaser approximated 51% of total natural gas and oil revenues for the year ended January 31, 2010. Oil sales to one purchaser approximated 49% of total natural gas and oil revenues for the year ended January 31, 2010.

17. FINANCIAL INSTRUMENTS

In September 2006, the FASB issued accounting guidance regarding 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. The accounting guidance also expands disclosures about fair value measurements. The accounting guidance 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. The guidance 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 amended guidance regarding fair value measurements which delays by one year, the effective date of the original accounting guidance 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 accounting guidance for the impairment or disposal of long-lived assets.

The Company has adopted the portion of the accounting guidance for fair value measurements that has not been delayed by the amendments 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 the accounting guidance 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 accounting guidance 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:

	Fair Value Measurement at Reporting Date Using
	Fair Value		Quoted Prices In Active Markets for Identical Assets/ Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)

Notes 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.

The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities are carried at cost, which approximates market value.

The company has no assets that the fair value of assets and liabilities are measured on a recurring basis at January 31, 2010.

F-19

18. 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.

19. 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 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, 2010. The Company's Incentive and Non-Qualified Stock Option Plans were not approved by the Company's shareholders.

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options [a]		Weighted-Average Exercise Price of Outstanding options		Number of Securities Remaining Available For Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in column [a]
Incentive Stock Option Plan		—		—		2,000,000
Non-Qualified Stock Option Plan		—		—		750,000

F-20

The following table provides information as of January 31, 2010 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.

Name of Plan	Total Shares Reserved Under Plans		Shares Reserved for Outstanding Options		Shares Issued As Stock Bonus		Remaining Options/Shares 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, 2010:

Incentive Stock Options

Shares Subject to Option

Exercise Price

Date of Grant

Expiration Date of Option

Options Exercised as of January 31, 2009

None

—

Non-Qualified Stock Options

Shares Subject to Option				Exercise Price				Date of Grant				Expiration Date of Option				Options Exercised as of January 31, 2010
	250,000			$	0.32				6-30-03				7-15-05				250,000

Stock Bonus Plan

Name	Shares Issued as Stock Bonus (1)(2)(3)		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.

(3)

In January 2010 the Company issued 500,000 shares of its restricted common stock to George Shaw and 500,000 shares to Scott Shaw for services rendered. However the shares issued in January 2010 were not issued pursuant to the Company's Stock Bonus Plan. Shares were valued at market price on the date of grant.

F-21

20. SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)

Net Capitalized Costs

The Company’s aggregate capitalized costs related to natural gas and oil producing activities are summarized as follows:

	January 31, 2010			January 31, 2009
Natural gas and oil properties and
Related lease equipment:
Proved	$	9,858,142		$	2,606,814
Unproved		251,352			162,012
		10,109,494			2,768,826
Accumulated depreciation, depletion and impairment		(3,435,598	)		(2,249,545	)
Net capitalized costs	$	6,673,896		$	519,281

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,
	2010		2009
Development costs	$	775,995	$	692,948
Investment in Snyder Well Partnership		-		39,000
	$	775,995	$	731,948

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, 2010 and 2009. 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,
	2010			2009
Production revenues	$	116,291		$	272,223
Production and transportation costs		(81,004	)		(133,470	)
Impairment of property		(1,132,030	)		(1,225,455	)
Gain on sale of properties		--			267,549
Depletion expense		(50,904	)		(119,786	)
		(1,147,647	)		(938,939	)
Imputed income tax provision (1)		-			-
Results of operation for natural gas/oil producing activity	$	(1,147,647	)	$	(938,939	)

(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.

F-22

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, 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

Purchase of reserves in place		2,448,135			85,194
Revisions of previous estimates		(89,648	)		11,708
Production		(18,502	)		(1,052	)
Balance, January 31, 2010		2,718,744			101,494
Proved developed reserves:
Balance, January 31, 2010		2,718,744			101,494
Balance, January 31, 2009		378,759			5,644

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, 2010 and 2009. 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 during the year ended January 31, 2010 and at January 31, 2009, it should be emphasized that such conditions continually 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.

F-23

	Years Ended January 31,
	2010			2009
Future production revenues (1)	$	13,698,976		$	1,358,079
Future production costs		(3,440,478	)		(627,398	)
Future development costs		—			—
Future income tax		—			—
Future net cash flows		10,258,498			730,681
Effect of discounting future annual cash flows at 10%		(3,451,062	)		(373,412	)
Standardized measure of discounted net cash flows	$	6,807,436		$	357,269

(1)	The weighted average natural gas and oil wellhead prices used in computing the Company’s reserves were $3.04 per mcf and $53.54 per bbl for the year ended January 31, 2010 as compared to $3.18 per mcf and $27.22 per bbl at January 31, 2009.

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, 2010 and 2009:

	Years Ended January 31,
	2010		2009
Standardized measure of discounted future net cash flows	$	6,807,436	$	357,269
Proved natural gas & oil property net of Accumulated depreciation, depletion and amortization, including impairment of $2,637,686 and $1,505,655 at January 31, 2010 and 2009, respectively		6,807,436		357,269
Standardized measure of discounted future net cash flows in excess of net carrying value of proved natural gas & oil properties	$	—	$	—

The following reconciles the change in the standardized measure of discounted future net cash flow for the years ended January 31, 2010 and 2009.

	Years Ended January 31,
	2010			2009
Beginning balance	$	357,269		$	2,077,673
Sales of oil and gas produced, net of net of production costs		(43,100	)		(150,827	)
Net changes in prices and production costs		171,964			(718,537	)
Sales of reserves in place		—			(597,908	)
Purchase of reserves in place		6,304,846			—
Revisions of estimates, less related production Costs		(12,426	)		(1,520,861	)
Accretion of discount		35,727			53,075
Net change in income taxes		—			1,214,654
Other		(6,844	)		—
Ending balance	$	6,807,436		$	357,269

F-24

21. DRILLING COMMITMENT

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 commitment of $156,000 as of January 31, 2010 and 2009.

22. SUBSEQUENT EVENTS

Management has evaluated subsequent events through May 17, 2010, the date which our financial statements have been issued, and has concluded that no material events, other than those disclosed elsewhere herein, have occurred subsequent to January 31, 2010 that need to included in these financial statements. See accompanying notes to consolidated financial statements.

F-25

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 17th day of May 2010.

	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	Director	May 17, 2010
George G. Shaw

/s/ G. Scott Shaw	Director	May 17, 2010
G. Scott Shaw

ENERGAS RESOURCES, INC.

FORM 10-K

EXHIBITS

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