10-K

FORM 10-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

(Mark One)

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended September 30, 2012

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: None

VANGUARD ENERGY CORPORATION

 (Exact name of registrant as specified in its charter)

COLORADO	27-2888719
(State or other jurisdiction of incorporation or organization)	(I.R.S.Employer Identification No.)

1330 Post Oak Blvd. Suite 1600, Houston Texas	77506
(Address of principal executive offices)	(Zip Code)

Registrant's telephone number, including area code: (713) 627-2500

Securities registered pursuant to Section 12(b) of the Act:

Title of each class Name of each exchange on which registered

Securities registered pursuant to Section 12(g) of the Act:

___________________

(Title of class)

___________________

(Title of class)

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 o  No þ

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations 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 filing). Yes þ  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. þ

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	þ
(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  þ   No

The aggregate market value of the voting stock held by non-affiliates of the registrant on March 31, 2012 was approximately $9,300,000.

As of December 15, 2012, the Registrant had 12,741,512 outstanding shares of common stock.

Documents Incorporated by Reference: None

PART I

FORWARD-LOOKING STATEMENTS

This report contains statements which, to the extent that they do not recite historical fact, constitute forward-looking statements. These statements can be identified by the fact that they do not relate strictly to historical or current facts and may include the words ‘‘may,’’ ‘‘will,’’ ‘‘could,’’ ‘‘should,’’ ‘‘would,’’ ‘‘believe,’’ ‘‘expect,’’ ‘‘anticipate,’’ ‘‘estimate,’’ ‘‘intend,’’ ‘‘plan’’ or other words or expressions of  similar meaning. We have based these forward-looking statements on our current expectations about future events. The forward-looking statements include statements that reflect management’s beliefs, plans, objectives, goals, expectations, anticipations and intentions with respect to our financial condition, results of operations, future performance and business, including statements relating to our business strategy and our current and future development plans.

The potential risks and uncertainties that could cause our actual financial condition, results of operations and future performance to differ materially from those expressed or implied in this report include:

●   The sale prices of crude oil;

●   The amount of production from oil wells in which we have an interest;

●   Lease operating expenses;

●   International conflict or acts of terrorism;

●   General economic conditions; and

●   Other factors disclosed in this report.

Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, level of activity, performance or achievements. Many factors discussed in this report, some of which are beyond our control, will be important in determining our future performance. Consequently, actual results may differ materially from those that might be anticipated from the forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of a forward-looking statement in this report as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

2

ITEM 1.  BUSINESS.

We are an early-stage independent energy company engaged in the acquisition and development of oil in or near established oil-producing areas. We plan to build our cash flow and oil reserves through a focused acquisition and development program by:

●   focusing our operations in the hydrocarbon-rich region of east Texas;

●   drilling in areas which have a high proportion of oil relative to natural gas;

●   lessening risk by concentrating on established areas with proven production; and

●   using new screening technology which prevents sand accumulation in the well bores and allows for the recovery of more oil from mature fields.

In December 2011 we completed a $4,800,000 initial public offering. The offering consisted of 4,800,000 Units priced at $1.00 per Unit.

Batson Dome and Hull-Daisetta fields

Pursuant to three agreements, we acquired oil and gas leases covering 230 acres in the Batson Dome Field in Hardin County, Texas. In the first agreement, and in consideration for the assignment of a 40% working interest (32% net revenue interest) in leases covering 220 acres, we paid $40,000 in cash and issued a promissory note in the principal amount of $285,668. In the second agreement, and in consideration for the assignment of a 50% working interest (40% net revenue interest) in leases covering the same 220 acres, we paid $50,000 in cash and issued a promissory note in the principal amount of $357,085. The notes associated with the first and second agreements bore interest at 8% per year and were repaid in December 2010. In the third agreement, and in payment of $259,247 in cash, we acquired a 90% working interest in 10 acres adjacent to the 220 acres described above, as well as a 90% working interest (63% net revenue interest) in two producing oil wells and three shut- in wells located on the 10- acre lease. The leases and wells subject to the first and third agreements were acquired from C.F.O., Inc., a corporation controlled by Delton Drum, one of our officers. C.F.O., Inc. owns the remaining 10% working interest in the leases covering the 230 acres.

By agreement dated March 15, 2011, we entered into a farmout agreement with an unrelated third party pertaining to a 100-acre lease in the Batson Dome Field. Pursuant to the farmout agreement we have the option of drilling wells on the lease; provided however, that if we do not drill at least six wells in any twelve month period our right to drill any additional wells on the lease will terminate. For each well drilled, we will receive a partial assignment of the lease covering the two acres surrounding the well. We will have a 100% working interest (75% net revenue interest) in any wells we drill on the leased acreage. We estimate the cost of drilling and completing any well on this lease will be approximately $500,000. As of November 30, 2012, we had drilled three wells on this lease.

3

By agreement dated May 25, 2011, we entered into a farmout agreement with Exxon/Mobil Corporation pertaining to another 100-acre lease in the Batson Dome Field. Pursuant to the agreement, we have the obligation to commence drilling a well on the lease by June 14, 2013. Subject to the commencement of drilling the first well by June 14, 2013, and completing the well if we consider it to be productive of oil, we have the option of drilling additional wells on the lease; provided, however, that unless we commence drilling each well within 180 days of the date we complete or abandon the latest well drilled, our right to drill any additional wells on the lease will terminate. For each well drilled, we will receive a partial assignment of the lease covering the acreage surrounding the well. We will have a 100% working interest (75% net revenue interest) in any wells we drill on the leased acreage. We estimate the cost of drilling and completing any well on this lease will be approximately $1,000,000. As of November 30, 2012, we had not commenced any drilling operations on the lease subject to the farmout agreement.

Exxon/Mobil has the right to purchase any oil produced from any wells drilled on the lease. If Exxon/Mobil exercises this right, the price for any oil purchased will be based upon the price posted by Exxon/Mobil, in its discretion, or in the alternative, the market price for oil in the area, after deduction for costs of gathering, storing, dehydrating, treating, processing and transporting the oil. Although the agreement with Exxon/Mobil does not specify how the ‘‘posted’’ price will be determined, in the area of our wells the posted price typically approximates the price published by the New York Mercantile Exchange for West Texas Intermediate Crude Oil. If ExxonMobil, does not post the price, then any purchase will be at the market value price as determined by ExxonMobil, at the well, after deduction of all costs of gathering, storing, dehydrating, treating, processing, and transporting oil. However, we may elect to provide ExxonMobil with any bona fide term purchase offer for oil to be used in future market value determinations and ExxonMobil will consider any offer in determining the market value price.

By agreement dated January 6, 2012, we entered into a three-year farmout agreement with an unrelated third party pertaining to another 70-acre lease in the Batson Dome Field.  We estimate the cost of drilling and completing any well on this lease will be approximately $1,000,000.

The Batson Dome Field is located in Hardin County, Texas approximately 50 miles northeast of Houston, and has multiple production zones. The oil produced from the field is light, sweet, high-quality crude with a specific gravity of 21 to 35 degrees. This field lies in flat wooded areas which allow easy access for the drilling and maintenance of wells. There are no significant man-made improvements other than oil wells and related equipment. There are no nearby residences.

The Batson Dome Field draws oil and negligible amounts of gas from an anhydrite and limestone reservoir in a caprock structure above a salt dome in the Miocene and Oligocene formations. Along with three other highly prolific salt dome fields—Spindletop, Sour Lake, and Humble—the Batson Dome Field helped to establish the basis of the Texas oil industry when these shallow fields produced the first Texas Gulf Coast oil.

A salt dome is a mushroom-shaped structure made of salt, commonly having an overlying caprock. Salt domes form as a consequence of the relative buoyancy of salt when buried beneath other types of sediment. The salt flows upward to form salt domes, sheets, pillars and other structures. Oil is commonly found in and around salt domes due to the abundance and variety of traps created by salt movement and the excellent sealing capabilities of salt.

The Batson Dome Field was first drilled in the early 1900s. The salt in the Batson Dome rises to a depth of approximately 800 feet at the cap of the dome, where the first oil was discovered in very shallow wells. Alternating sands and shales form oil reservoirs in the sand dipping away from the cap on all sides of the dome down to a depth of over 7,000 feet. The field has produced oil and a negligible amount of gas from an anhydrite and limestone reservoir in the cap as well as the Miocene and Frio Sands at depths of 400-4,000 feet and the Yegua Sands below 7,000 feet. Since no secondary or enhanced recovery has been attempted over the years, we believe there are opportunities for recovery of substantial undrained reserves through the drilling of new wells with closer spacing and the re-entry of old well bores in currently producing areas.

4

As mentioned above, we acquired two producing and three shut-in oil wells in the Batson Dome Field.  As of November 30, 2012, the two wells were producing approximately one barrel of oil per day, net to our 63% net revenue interest. The three shut-in wells will need to be reworked, at an estimated cost of $125,000 per well, before they can be returned to production.  As of  November 30, 2012, one of the shut-in wells was being reworked.

As of November 30, 2012, we had drilled and completed twelve wells in the Batson Dome Field. Our share of the costs of drilling and completing these wells was approximately $7,200,000. During the three months ended November 30, 2012, these wells collectively produced approximately 16,000 barrels of oil. Each well has shown multiple potentially productive zones at various depths. In the event production from one zone falls off materially, we have the opportunity to open another zone to compensate for the decline.

By agreement dated May 1, 2012, we entered into a farmout agreement with an unrelated third party pertaining to a 45-acre lease in the Hull-Daisetta Field. Pursuant to the agreement, we have the obligation to commence drilling a well on the lease by January 31, 2013.  Subject to the commencement of drilling the first well by January 31, 2013, and completing the well if warranted, we have the option of drilling additional wells on the lease; provided however, that unless we commence drilling each well within 180 days of the date the latest well is completed or abandoned, the right to drill any additional wells on the lease will terminate. We estimate the cost of drilling and completing any well on this lease will be approximately $750,000. As of November 30, 2012, we had not drilled any wells on this lease.

The Hull-Daisetta Field is located in the Liberty County, Texas, about 10 miles south of our Batson Dome Field.  The Hull-Daisetta Field includes coverage of a salt dome formation with similar geological characteristics as the Batson salt dome.  The field was first drilled in 1918 and has produced over 180 million barrels of oil to date.  Our initial lease position is on the edge of the salt dome which contains old shut-in wells that were drilled and successfully produced a number of years ago. Our geologist believes that substantial volumes of oil remain in the field.  The expected depths to the dome cap rock on this lease are around 5,000 feet.

The completion of oil wells in established areas, such as the Batson Dome and Hull-Daisetta fields, is, to a certain extent, less risky than drilling for oil in unproven areas where uncertainty exists as to whether relevant amounts of oil exist at all. However, the process of completing an oil well is nevertheless associated with considerable risk.

We plan on drilling and, if warranted, completing additional wells in the Batson Dome and Hull Daisetta fields. The wells will be drilled to a depth of approximately 3,000 to 4,000 feet to the Frio formation. Each well will take approximately ten days to drill and complete. Our share of the drilling and completion costs for each well is estimated to be approximately $450,000. We will have a 90% working interest (63%-67.5% net revenue interest) in any wells we drill in the Batson Dome Field.

Vanguard Net Profits, LLC, a Texas limited liability company (the ‘‘Fund’’), has a 20% net profits interest in the four wells drilled with the proceeds from our November and December 2010 sale of convertible notes. We have a 1% interest in the Fund. Thirty-three private investors hold the remaining 99% interest.

The holders of the convertible notes we sold in 2012 have a security interest in any leases acquired, or wells drilled, with the proceeds from the sale of the notes.

5

During the period from our inception to September 30, 2010, we did not drill any oil or gas wells.

The table shows the type and number of wells we drilled during the two years ended September 30, 2012.

	Years September 30,
	2012				2011
	Gross		Net		Gross		Net
Development Wells:
Productive:
Oil		8		7.4		4		3.6
Gas						-		-
Nonproductive						-		-
Exploratory Wells:
Productive
Oil
Gas						-		-
Nonproductive						-		-

As of November 30, 2012 we were not drilling  or completing  any wells, and we were reworking one well.

6

The following table shows, as of November 30, 2012, our producing wells, developed acreage, and undeveloped acreage, excluding service (injection and disposal) wells:

Productive Wells

Developed Acreage

Undeveloped Acreage(1)

State

Gross

Net

Gross

Net

Gross

Net

Texas

12

11

375

352

170

153

(1)   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.

The following table shows, as of November 30, 2012, the status of our gross acreage:

State	Held by Production		Not Held by Production
Texas		330		215

Acres that are Held by Production remain in force so long as oil or gas is produced from one or more wells on the particular lease. Leased acres that 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 leased 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.

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The following table shows the years our leases, which are not Held By Production, will expire, unless a productive oil or gas well is drilled on the lease.

Leased  Acres	Expiration of Lease
145	2013
70	2015

Proved Reserves

Below are estimates of our net proved reserves as of September 30, 2012, net to our interest.  All of our proved reserves are located in Texas.

Estimates of volumes of proved reserves at September 30, 2012 are presented in barrels (Bbls) for oil and, for natural gas, in millions of cubic feet (Mcf) at the official temperature and pressure bases of the areas in which the gas reserves are located.

	Oil (Bbls)		Gas (Mcf)
Proved Developed:
Producing		231,859		-
Non-Producing		81,758		-
Proved Undeveloped		412,247		-

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‘‘Bbl’’ refers to one stock tank barrel, or 42 U.S. gallons liquid volume, in reference to crude oil or other liquid hydrocarbons. ‘‘Mcf’’ refers to one thousand cubic feet. A BOE (i.e., barrel of oil equivalent) combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil. Below are estimates of our present value of estimated future net revenues from our proved 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 Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. 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 based upon benchmark prices that reflect the unweighted arithmetic average of the first-day-of-the-month price for oil and gas during the twelve months period ended September 30, 2012.  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.

Future cash inflows	$	74,669,619
Deductions (including estimated taxes)	$	(29,179,159	)
Future net cash flow	$	45,490,460
Discounted future net cash flow	$	36,981,262

Nova Resources, Inc. prepared the estimates of our proved reserves, future production and income attributable to our leasehold interests as of September 30, 2012.  Nova is an independent petroleum engineering firm that provides petroleum consulting services to the oil and gas industry. The estimates of drilled reserves, future production and income attributable to certain leasehold and royalty interests are based on technical analysis conducted by engineers employed at Nova.

Joseph V. Rochefort was the technical person primarily responsible for overseeing the preparation of the reserve report. Mr. Rochefort earned a Bachelor’s Degree in Physics and Geophysics from Texas Christian University and a Masters Degree in Geology from Texas Tech University. Mr. Rochefort has more than 28 years of practical experience in the estimation and evaluation of petroleum reserves.

Delton Drum, our Vice President of Field Operations, oversaw the preparation of the reserve estimates by Nova. Mr. Drum has over 30 years experience in oil and gas exploration and development, with over 15 years of experience in the Batson Dome Field. We do not have a reserve committee and we do not have any specific internal controls regarding the estimates of our reserves.

Our proved reserves include only those amounts which we reasonably expect 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.

9

Proved reserves were estimated by performance methods, the volumetric method, analogy, or a combination of methods utilizing present economic conditions and limited to those proved reserves economically recoverable. The performance methods include decline curve analysis that utilize extrapolations of historical production and pressure data available through September 30, 2012 in those cases where such data were considered to be definitive.

Forecasts for future production rates are based on historical performance from wells currently on production in the region with an economic cut-off for production based upon the projected net revenue being equal to the projected operating expenses. No further reserves or valuation were given to any wells beyond their economic cut-off. Where no production decline trends have been established due to the limited historical production records from wells on the properties, surrounding wells historical production records were used and extrapolated to wells of the property. Where applicable, the actual calculated present decline rate of any well was used to determine future production volumes to be economically recovered. The calculated present rate of decline was then used to determine the present economic life of the production from the reservoir.

For wells currently on production, forecasts of future production rates were based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to economic depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Proved developed non-producing and undeveloped reserves were estimated primarily by the performance and historical extrapolation methods. Test data and other related information were used to estimate the anticipated initial production rates from those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at a date we determined to be reasonable.

In general, the volume of production from our oil and gas properties declines as reserves are depleted. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced. Accordingly, volumes generated from our future activities are highly dependent upon the level of success in acquiring or finding additional reserves and the costs incurred in doing so.

Future Operations

We plan to evaluate other undeveloped oil prospects and participate in drilling activities on those prospects which, in our opinion, are favorable for the production of oil. Initially, we plan to concentrate our activities in East Texas. Our strategy is to acquire prospects in or adjacent to existing fields with further development potential and minimal risk in the same area. The extent of our activities will primarily be dependent upon available capital.

If we believe a geographical area indicates geological and economic potential, we will attempt to acquire leases or other interests in the area. We may then attempt to sell portions of our leasehold interests in a prospect to third parties, thus sharing the risks and rewards of the exploration and development of the prospect with the other owners. One or more wells may be drilled on a prospect, and if the results indicate the presence of sufficient oil reserves, additional wells may be drilled on the prospect.

10

We may also:

●   acquire a working interest in one or more prospects from others and participate with the other working interest owners in drilling and if warranted, completing oil wells on a prospect;

●   purchase producing oil  properties; or

●   enter into farmin agreements with third parties. A farmin agreement will obligate us to pay the cost of drilling, and if warranted completing a well, in return for a majority of the working and net revenue interest in the well.

Title to properties which we may acquire will be subject to one or more of the following: royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil industry; liens for current taxes not yet due; and other encumbrances. In the case of undeveloped properties, investigation of record title will be made at the time of acquisition. Title reviews will be obtained before commencement of drilling operations.

Although we normally obtain title reports for oil leases we acquire, we have not in the past obtained, and we may not in the future obtain, title opinions pertaining to leases. A title report shows the history of a particular oil and gas lease, as shown by the records of the county clerk and recorder, state oil or gas commission, or the Bureau of Land Management, depending on the nature of the lease. In contrast, in a title opinion, an attorney expresses an opinion as to the persons or persons owning interests in a particular oil and gas lease.

Government Regulation

Although our sale of oil will not be regulated, federal, state and local agencies have promulgated extensive rules and regulations applicable to our oil exploration, production and related operations. Most states, including Texas, require permits for drilling operations, drilling bonds and the filing of reports concerning operations and impose other requirements relating to the exploration of oil. Texas and other states also have statutes or regulations addressing conservation matters including provisions for the unitization or pooling of oil properties, the establishment of maximum rates of production from oil wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of Texas and other states limit the rate at which oil is produced from wells. The federal and state regulatory burden on the oil industry increases our cost of doing business and affects our profitability. Because these rules and regulations are amended or reinterpreted frequently, we are unable to predict the future cost or impact of complying with those laws.

As with the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state and local laws and regulations designed to protect and preserve our natural resources and the environment. The recent trend in environmental legislation and regulation is generally toward stricter standards, and this trend is likely to continue. These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, seismic acquisition, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; impose substantial liabilities for pollution resulting from our operations; and require the reclamation of certain lands.

11

The permits required for many of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunctions or both. In the opinion of our management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry in general. The Comprehensive Environmental Response, Compensation and Liability Act  (‘‘CERCLA’’) and comparable state statutes impose strict and joint and several liabilities on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of ‘‘hazardous substances’’ found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Resource Conservation and Recovery Act (‘‘RCRA’’) and comparable state statutes govern the disposal of ‘‘solid waste’’ and ‘‘hazardous waste’’ and authorize imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of ‘‘hazardous substance,’’ state laws affecting our operations impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as ‘‘non-hazardous,’’ such exploration and production wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements.

Competition and Marketing

We will be faced with strong competition from many other companies and individuals engaged in the oil business, some of which are very large, well-established energy companies with substantial capabilities and established earnings records. We may be at a competitive disadvantage in acquiring oil prospects since we must compete with these individuals and companies, many of which have greater financial resources and larger technical staffs. In addition, although we use new screening technology which prevents sand accumulation in the well bores and allows for the recovery of more oil from mature fields, larger companies have the ability to manage their risk by diversification.

Exploration for and the production of oil are affected by the availability of pipe, casing and other tubular goods and certain other oil field equipment including drilling rigs and tools. We will depend upon independent drilling contractors to furnish rigs, equipment and tools to drill our wells. Higher prices for oil may result in competition among operators for drilling equipment, tubular goods and drilling crews which may affect our ability expeditiously to drill, complete, recomplete and work-over wells.

The market for oil is dependent upon a number of factors beyond our control, which at times cannot be accurately predicted. These factors include the extent of competitive domestic production and imports of oil, 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. As of November 30, 2012, all of our oil production was being sold to an independent oil company. The agreement with the independent oil company is on a month-to-month basis, and the price at which we sell our oil is established each month. The oil is transferred by truck from the field to a nearby refinery. We do not expect to have any difficulty in selling the oil produced from our wells in the foreseeable future.

12

On June 23, 2011, 28 member countries of the International Energy Agency agreed to release 60 million barrels of oil, including 30 million barrels from the United States’ Strategic Petroleum Reserve, in the subsequent months in response to the ongoing disruption of oil supplies from Libya. 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. We are 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.

Employees and Offices

As of November 30, 2012, we had one full-time employee and two part-time employees.

Our principal offices are located at 1330 Post Oak Blvd., Suite 1600, Houston, Texas 77056. Our offices, consisting of approximately 1,200 square feet, are leased until February 28, 2013 at a rate of $2,900 per month.

We also maintain a satellite office in Los Angeles, California.  This office consists of 500 square feet and is rented for $5,700 per month pursuant to a lease which expires on June 30, 2013.

Our office leases include fully furnished offices, utilities, administrative support and covered parking.

Subsidiaries

We conduct business in Texas through VE Corporation, a Colorado corporation and our wholly owned subsidiary. In addition, we own a 1% interest in Vanguard Net Profits, LLC, a Texas limited liability company. Thirty-three private investors own the remaining 99% interest.

ITEM 1A.  RISK FACTORS.

Investors should be aware that and investment in our securities involves certain risks, including those described below, which could adversely affect the value of our common stock. We do not make, nor have we authorized any other person to make, any representation about the future market value of our common stock.  In addition to the other information contained in this report, the following factors should be considered carefully in evaluating an investment in our securities.

Our failure to obtain capital may restrict our operations. We may need additional capital to fund our operating losses and to expand our business. We do not know what the terms of any future capital raising may be but any future sale of our equity securities would dilute the ownership of existing stockholders and could be at prices substantially below the market price of our common stock. Our failure to obtain the capital which we require may result in the slower implementation of our business plan.  There can be no assurance that we will be able to obtain the capital which we will need.

13

Drilling.  Oil exploration is not an exact science, and involves a high degree of risk.  The primary risk lies in the drilling of dry holes or drilling and completing wells which, though productive, do not produce oil in sufficient amounts to return the amounts expended and produce a profit.  Hazards, such as unusual or unexpected formation pressures, downhole fires, blowouts, loss of circulation of drilling fluids and other conditions are involved in drilling and completing wells and, if such hazards are encountered, completion of any well may be substantially delayed or prevented.  In addition, adverse weather conditions can hinder or delay operations, as can shortages of equipment and materials or unavailability of drilling, completion, and/or work-over rigs.  Even though a well is completed and is found to be productive, water and/or other substances may be encountered in the well, which may impair or prevent production or marketing of oil from the well.

Exploratory drilling involves substantially greater economic risks than development drilling because the percentage of wells completed as producing wells is usually less than with development drilling.  Exploratory drilling itself can involve varying degrees of risk and can generally be divided into higher risk attempts to discover a reservoir in a completely unproven area or relatively lower risk efforts in areas not too distant from existing reservoirs.  While exploration adjacent to or near existing reservoirs may be more likely to result in the discovery of oil than in completely unproven areas, exploratory efforts are nevertheless high risk activities.

Although the completion of a well is, to a certain extent, less risky than drilling, the process of completing a well is nevertheless associated with considerable risk.  In addition, even if a well is completed as a producer, the well for a variety of reasons may not produce sufficient oil in order to repay the investment in the well.  As a result, there is considerable economic risk associated with our activities.

Economic Factors in Oil Exploration.  The acquisition, exploration and development of oil properties, and the production and sale of oil are subject to many factors which are outside our control.  These factors include, among others, general economic conditions, proximity to pipelines, oil import quotas, supply, demand, and price of other fuels and the regulation of production, refining, transportation, pricing, marketing and taxation by Federal, state, and local governmental authorities.

Title Uncertainties.  Interests that we will acquire in properties may be subject to royalty and overriding royalty interests, liens incident to operating agreements, liens for current taxes and other burdens and encumbrances, easements and other restrictions, any of which may subject us to future undetermined expenses.  We do not intend to purchase title insurance, title memos, or title certificates for any leasehold interests we acquire.  It is possible that at some point we will have to undertake title work involving substantial costs.  In addition, it is possible that we may suffer title failures resulting in significant losses.

Uninsured Risks.   The drilling of wells involves hazards such as blowouts, unusual or unexpected formations, pressures or other conditions which could result in substantial losses or liabilities to third parties.  Although we intend to acquire adequate insurance, or to be named as an insured under coverage acquired by others (e.g., the driller or operator), we may not be insured against all such losses because such insurance may not be available, premium costs may be deemed unduly high, or for other reasons.  Accordingly, uninsured liabilities to third parties could result in the loss of our funds or property.

14

Government Regulation.    Our operations are affected from time to time and in varying degrees by political developments and Federal and state laws and regulations regarding the development, production and sale of crude oil.  These regulations require permits for drilling of wells and also cover the spacing of wells, the prevention of waste, and other matters.  Rates of production of oil have for many years been subject to Federal and state conservation laws and regulations and the petroleum industry is subject to Federal tax laws.  In addition, the production of oil may be interrupted or terminated by governmental authorities due to ecological and other considerations.  Compliance with these regulations may require a significant capital commitment by and expense to us and may delay or otherwise adversely affect our proposed operations.

From time to time legislation has been proposed relating to various conservation and other measures designed to decrease dependence on foreign oil.  No prediction can be made as to what additional legislation may be proposed or enacted.  Oil producers may face increasingly stringent regulation in the years ahead and a general hostility towards the oil and gas industry on the part of a portion of the public and of some public officials.  Future regulation will probably be determined by a number of economic and political factors beyond our control or the oil and gas industry.

Environmental Laws.  Our activities will be subject to existing federal and state laws and regulations governing environmental quality and pollution control.  Compliance with environmental requirements and reclamation laws imposed by Federal, state, and local governmental authorities may necessitate significant capital outlays and may materially affect our earnings.  It is impossible to predict the impact of environmental legislation and regulations (including regulations restricting access and surface use) on our operations in the future although compliance may necessitate significant capital outlays, materially affect our earning power or cause material changes in our intended business.  In addition, we may be exposed to potential liability for pollution and other damages.

The sale of common stock described above, or the perception that such sales could occur, may adversely affect the market price of our common stock.

Any decline in the price of our common stock may encourage short sales, which could place further downward pressure on the price of our common stock.  Short selling is a practice of selling shares which are not owned by a seller at that time, with the expectation that the market price of the shares will decline in value after the sale, providing the short seller a profit.

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ITEM 1B.  UNRESOLVED STAFF COMMENTS.

Not Applicable

ITEM 2.  PROPERTIES.

See Item 1 of this report.

ITEM 3.  LEGAL PROCEEDINGS.

None.

ITEM 4.  MINE SAFETY DISCLOSURE.

Not applicable.

16

PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

In December 2011 we completed our initial public offering.  The offering consisted of 4,800,000 Units priced at $1.00 per Unit.  Each unit consisted of one share of our common stock and one Class A warrant.  The Units began trading under the symbol “VNGEU” on the Over-The-Counter Bulletin Board (OTCBB) on November 29, 2011.  On December 10, 2011 the Units separated into shares of common stock and warrants.  The shares of common stock traded under the symbol (OTCBB: VNGE) and the Class A warrants trade under the symbol (OTCBB: VNGEW).  Each Class A warrant entitles the holder to purchase one share of our common stock at a price of $1.50 per share at any time on or before November 29, 2016.

Shown below is the range of high and low closing prices for our common stock for the periods indicated as reported by the FINRA.  The market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commissions and may not necessarily represent actual transactions.

Quarter Ended	High		Low
December 31, 2011	$	1.05	$	0.95
March 31, 2012	$	1.15	$	0.95
June 30, 2012	$	1.05	$	0.87
September 30, 2012	$	1.00	$	0.85

Holders of our common stock are entitled to receive dividends as may be declared by the Board of Directors.  Our Board of Directors is not restricted from paying any dividends but is not obligated to declare a dividend.  No cash dividends have ever been declared and it is not anticipated that cash dividends will ever be paid.

 Our Articles of Incorporation authorize our Board of Directors to issue up to 5,000,000 shares of preferred stock.  The provisions in the Articles of Incorporation relating to the preferred stock allow our directors to issue preferred stock with multiple votes per share and dividend rights which would have priority over any dividends paid with respect to the holders of our common stock.  The issuance of preferred stock with these rights may make the removal of management difficult even if the removal would be considered beneficial to shareholders generally, and will have the effect of limiting shareholder participation in certain transactions such as mergers or tender offers if these transactions are not favored by our management.

As of November 30, 2012, we had approximately 475 shareholders of record.

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We have not declared or paid any dividends on our common stock since our inception, and we do not anticipate declaring or paying any dividends on our common stock for the foreseeable future. We currently intend to retain any future earnings to finance future growth. Any future determination to pay dividends will be at the discretion of our board of directors and will depend on our financial condition, results of operations, capital requirements and other factors the board of directors considers relevant.

ITEM 6.  SELECTED FINANCIAL DATA.

Not applicable.

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with our financial statements included as part of this report.

Results of Operations

We were incorporated in Colorado on June 21, 2010 and commenced operations on July 19, 2010. We are in the early stages of implementing our business plan.

During the period of our inception to September 30, 2010 we did not generate any revenue. Accordingly, a comparison of our operating results for the year ended September 30, 2011 with the comparable period in 2010 would not be meaningful.

In November and December 2010 we entered into two agreements to acquire oil and gas leases covering 220 acres in the Batson Dome Field in Hardin County, Texas. In the first agreement, and in consideration for the assignment of a 40% working interest (32% net revenue interest) in leases covering 220 acres, we paid $40,000 in cash and issued a promissory note in the principal amount of $285,668. In the second agreement, and in consideration for the assignment of a 50% working interest (40% net revenue interest) in leases covering the same 220 acres, we paid $50,000 in cash and issued a promissory note in the principal amount of $357,085. The notes associated with the first and second agreements bore interest at 8% per year and were repaid in December 2010.

 In December 2010, we acquired two producing and three shut-in oil wells in the Batson Dome Field.  As of November 30, 2012, the two wells were producing approximately one barrel of oil per day, net to our 63% net revenue interest.  As of November 30, 2012, one shut-in well was being reworked and one shut-in well was plugged and abandoned. We estimate the costs of reworking the shut-in wells will be $375,000.

As of November 30, 2012, we had drilled and completed twelve wells in the Batson Dome Field.  Our share of the costs of drilling and completing these wells was approximately $7,200,000.  Each of these wells has shown multiple potentially productive zones at depths ranging from 2,100 to 3,700 feet.   During the three months ended  November 30, 2012 we produced approximately 16,000 bbls of oil.

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Material changes in our Statement of Operations for the year ended September 30, 2012 as compared to the same period in the prior year are discussed below:

	Increase (I)
Item	or Decrease (D)	Reason
Oil and Gas Sales	I	Completion of new wells
Cost and Expenses	I	Operation of new wells and increased depletion of oil reserves as a result of increased production

Operating expenses requiring cash for the year ended September 30, 2012 consisted primarily of:

●   lease operating expenses;

●   general and administrative expenses; and

●   interest expense.

The factors that will most significantly affect our future operating results will be:

●   the sale prices of crude oil;

●   the amount of production from oil wells in which we have an interest;

●   lease operating expenses;

●   the availability of drilling rigs, drill pipe and other supplies and equipment required to drill and complete oil wells; and

●   corporate overhead costs.

Our revenues will also be significantly affected by our ability to maintain and increase oil production.

Other than the foregoing we do not know of any trends, events or uncertainties that have had, or are reasonably expected to have, a material impact on our revenues or expenses.

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Liquidity and Capital Resources

In July 2010, we sold 4,900,000 shares of our common stock at a price of $0.001 per share to our officers and directors and third parties. In July, August, and September, 2010, we sold 1,012,500 shares of our common stock to a group of private investors at a price of $0.40 per share.

In November and December 2010, we sold 34 units in a private offering at a price of $100,000 per unit. Each unit consisted of one promissory note in the principal amount of $100,000 and 50,000 Series A warrants. At any time after April 30, 2011, the notes can be converted into shares of our common stock, initially, at a conversion price of $1.00 per share. Each Series A warrant entitles the holder to purchase one share of our common stock at a price of $4.00 per share at any time on or before October 31, 2014. The notes bear interest at 8% per year. In June, July and September 2012 notes in the principal amount of $3,075,000 were surrendered in payment of the notes sold in 2012.  The remaining notes, which had an outstanding principal balance of $325,000, were repaid in October 2012.

In February and March 2011, we sold 1,500,000 units at a price of $1.00 per unit. Each unit consisted of one share of our common stock and one Series C warrant. Each Series C warrant allows the holder to purchase one share of our common stock at a price of $2.00 per share. In March 2011, we issued 453,322 shares of our common stock to a placement agent upon the exercise of warrants which had an exercise price of $0.10 per share.

In December 2011 we sold 4,800,000 units in an initial public offering at a price of $1.00 per unit. Net proceeds to us from this offering, after payment of the underwriting discounts and offering expenses, were approximately $3,498,900. Each unit consisted of one share of common stock and one Class A warrant. Each Class A warrant entitles its holder to purchase one share of common stock at an exercise price of $1.50. The Class A warrants are exercisable at any time on or before November 29, 2016.

In June, July and September 2012 we sold convertible secured promissory notes to a group of private investors.  The notes bear interest at 15% per year, are payable quarterly, mature on June 30, 2015, and are convertible into shares of our common stock at a conversion price of $1.25 per share, subject to adjustment.  Notes in the cumulative principal amount of $5,179,500 were sold for cash and notes in the cumulative principal amount of $3,075,000 were exchanged for notes that we sold in 2010. Net proceeds from this financing:

●    were used to pay the remaining balance ($325,000) of our 2010 notes; and

●    will be used to fund a drilling program in our fields located in Southeast Texas.

Our sources and (uses) of funds for the two years ended September 30, 2012 are shown below:

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	Year Ended			Year Ended
	September 30, 2012			September 30, 2011
Cash provided by operations	$	383,083		$	477,266
Acquisition of oil and gas properties		-			(309,247	)
Purchases of furniture and equipment		(22,480	)		-
Drilling and completion costs		(6,113,295	)		(3,087,047	)
Debt issuance costs		(813,780	)		(400,051	)
Equity offering costs		(199,849	)		(525,291	)
Proceeds from issuance of common stock and warrants		4,224,000			1,340,155
Proceeds from exercise of warrants		-			45,289
Repayment of notes		-			(642,753	)
Proceeds from sale of convertible notes		5,179,500			3,400,000

As of November 30, 2012, our operating expenses were approximately $150,000 per month, which amount includes salaries and other corporate overhead, but excludes lease operating and interest expenses.

By agreement dated March 15, 2011, we entered into a farmout agreement with an unrelated third party pertaining to a 100-acre lease in the Batson Dome Field.  As of November 30, 2012 we  had drilled three wells on the lease. Pursuant to the farmout agreement we have the option of drilling additional wells on the lease, subject to certain conditions. We estimate the cost of drilling and completing any well on this lease will be approximately $500,000.

By agreement dated May 25, 2011, we entered into a farmout agreement with Exxon/Mobil Corporation pertaining to another 100-acre lease adjacent to our existing leases in the Batson Dome Field. Pursuant to the agreement, we have the obligation to commence drilling a well on the lease by June 14, 2013. Subject to the commencement of drilling the first well by June 14, 2013, and completing the well if warranted, we have the option of drilling additional wells on the lease; provided however, that unless we commence drilling each well within 180 days of the date we complete or abandon the latest well drilled, our right to drill any additional wells on the lease will terminate. We estimate the cost of drilling and completing any well on this lease will be approximately $1,000,000.

By agreement dated January 6, 2012, we entered into a three-year farmout agreement with an unrelated third party pertaining to another 70-acre lease in the Batson Dome Field.  We estimate the cost of drilling and completing any well on this lease will be approximately $1,000,000.

By agreement dated May 1, 2012, we entered into a farmout agreement with an unrelated third party pertaining to a 45-acre lease in the Hull-Daisetta Field. Pursuant to the agreement, we have the obligation to commence drilling a well on the lease by January 31, 2013.  Subject to the commencement of drilling the first well by January 31, 2013, and completing the well if warranted, we have the option of drilling additional wells on the lease; provided however, that unless we commence drilling each well within 180 days of the date the latest well is completed or abandoned, the right to drill any additional wells on the lease will terminate. We estimate the cost of drilling and completing any well on this lease will be approximately $750,000.

21

We estimate we will spend approximately $7,000,000 during the twelve months ending November 30, 2013 for drilling and completing wells and for various other projects.

Any cash generated by our operations, after payment of general, administrative and lease operating expenses, will be used to drill and, if warranted, complete oil wells, acquire oil and gas leases covering lands which we believe are favorable for the production of oil, and to fund working capital reserves. Our capital expenditure plans are subject to periodic revision based upon the availability of funds and expected return on investment.

We expect that our principal source of cash flow will be from the sale of crude oil reserves which are depleting assets. Cash flow from the sale of oil production depends upon the quantity of production and the price obtained for the production. An increase in prices will permit us to finance our operations to a greater extent with internally generated funds, may allow us to obtain equity financing more easily or on better terms, and lessens the difficulty of obtaining financing. However, price increases heighten the competition for oil prospects, increase the costs of exploration and development, 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 prices (i) will reduce our cash flow which in turn will reduce the funds available for exploring for and replacing oil reserves, (ii) will increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) will reduce the number of oil prospects which have reasonable economic terms, (iv) may cause us to permit leases to expire based upon the value of potential oil reserves in relation to the costs of exploration, (v) may result in marginally productive oil wells being abandoned as non-commercial, and (vi) may increase the difficulty of obtaining financing. However, price declines reduce the competition for oil properties and correspondingly reduce the prices paid for leases and prospects.

We plan to generate profits by drilling productive oil wells. However, we plan to obtain the funds required to drill, and if warranted, complete new wells (including any wells pertaining to our farmout agreements) with any net cash generated by our operations, through the sale of our securities, from loans from third parties or from third parties willing to pay our share of the cost of drilling and completing the wells as partners/participants in the resulting wells. We do not have any commitments or arrangements from any person to provide us with any additional capital. We may not be successful in raising the capital needed to drill oil wells. Any wells which may be drilled by us may not produce oil.

Other than as disclosed above, we do not know of any:

●   Trends, demands, commitments, events or uncertainties that will result in, or that are reasonably likely to result in, any material increase or decrease in our liquidity; or

●   Significant changes in our expected sources and uses of cash.

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Contractual Obligations

Our material future contractual obligations as of September 30, 2012 were as follows:

	Total		2013		2014		2015		Thereafter
2010 Convertible notes (1)	$	325,000	$	325,000	$	-		-		-
2012 Convertible notes	$	8,254,500		-		-	$	8,254,000	$	-
Office lease	$	65,800	$	65,800	$	-		-		-

(1) These notes were repaid in October 2012.

Critical Accounting Policies and New Accounting Pronouncements

See Note 2 to the financial statements included as part of this report, for a description of our critical accounting policies and the potential impact of the adoption of any new accounting pronouncements.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Not applicable.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

See the financial statements and accompanying notes included with this report.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

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ITEM 9A.  CONTROLS AND PROCEDURES.

An evaluation was carried out under the supervision and with the participation of our management, including our Principal Executive and Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report on Form 10-K.  Disclosure controls and procedures are procedures designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, such as this Form 10-K, is recorded, processed, summarized and reported, within the time period specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and is communicated to our management, including our Principal Executive and Financial Officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure. Based on that evaluation, our management concluded that, as of September 30, 2012, our disclosure controls and procedures were effective.

Management's Report on Internal Control over Financial Reporting

Our 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 our Principal Executive and Financial Officer and implemented by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements in accordance with U.S. generally accepted accounting principles.

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.

Warren Dillard, our Principal Executive and Financial Officer, evaluated the effectiveness of our internal control over financial reporting as of September 30, 2012 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or the COSO Framework. Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of those controls.

 Based on this evaluation, management concluded that our internal control over financial reporting was effective as of September 30, 2012.

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting that occurred during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.  OTHER INFORMATION.

None.

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PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Our officers and directors are listed below. Our directors are generally elected at our annual shareholders’ meeting and hold office until the next annual shareholders’ meeting, or until their successors are elected and qualified. Our executive officers are elected by our directors and serve at their discretion.

Name	Age	Position
Warren M. Dillard	70	President, Chief Executive, Financial and Accounting Officer and a Director
R. Gerald Bailey	71	Chairman of the Board and a Director
Michael L. Fraim	50	Vice President, Technology
Delton C. Drum	55	Vice President, Field Operations
Steven M. Powers	70	Vice President of Business Development, Secretary and a Director
Rick A. Wilber	65	Director
John P. Barton	68	Director

The principal occupations of our officers and directors during the past several years are as follows:

Warren M. Dillard has been our President, Chief Executive, Financial and Accounting Officer and a director since June 2010. Since February 2011 Mr. Dillard has been our Principal Financial and Accounting Officer. Since 2005, Mr. Dillard has served as the President and a director of Enercor, Inc., a private corporation involved in oil and gas exploration and development in the western United States. Since the spring of 2010, Mr. Dillard’s involvement with Enercor has been minimal. Mr. Dillard holds a degree in Accounting from Texas A & M University and an MBA in Finance from the Harvard Business School.

R. Gerald Bailey has been our Chairman of the Board and a director since June 2010 and has approximately 45 years of experience as a petroleum engineer. Currently, Mr. Bailey is serving as chairman of BCM Energy Partners, Inc., an oil production firm. Since 1997, Mr. Bailey has served as the chairman of Bailey Petroleum, LLC, a consulting firm for oil and gas exploration and development corporations. Between 1993 and 1997, Mr. Bailey served as the President of Exxon Corporation, Arabian Gulf. He received a BS in Chemical Engineering from the University of Houston, and a MS in Chemical Engineering from New Jersey Institute of Technology.

Michael L. Fraim, PhD. has been our Vice President for Technology since June 2010. Since 2006, Dr. Fraim has served as the Vice President, Technology for Ephraim Oil, LLC. Between 2004 and 2006, Dr. Fraim was employed by Alamos Consulting in Albuquerque, New Mexico. From time to time over the past five years, Dr. Fraim has been engaged on an independent contractor/consultant basis by various energy companies. Most recently, Mr. Fraim has been providing consulting services to large oil and gas companies through Texas A&M University. Dr. Fraim holds a bachelor’s degree, a masters degree and a PH.D degree in petroleum engineering from Texas A & M University.

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Delton C. Drum has been our Vice President for Field Operations since June 2010. Since 2003, Mr. Drum has been the President of C.F.O., Inc., an oil and gas firm involved in drilling and operating oil and gas wells. Since 1995, Mr. Drum has served as the Chief Executive Officer of Drum Equipment/ Drum Oil & Gas, Inc. Mr. Drum has approximately 30 years of experience in the oil and gas industry as an operator, driller and well owner.

Steven M. Powers has been a director since June 2010. Since February 2011, Mr. Powers has been our Vice President of Business Development and our Secretary. Since 2005, Mr. Powers has served as Chief Executive Officer, Chairman and a director of Enercor, Inc., a private corporation involved in oil and gas exploration and development. Prior to his association with Enercor, Mr. Powers was a real estate developer. Mr. Powers holds a degree in philosophy from the University of California at Santa Barbara as well as an MBA from the University of California at Los Angeles.

Rick A. Wilber has been a director since June 2010. Mr. Wilber has been a director of Synergy Resources Corporation, a publicly traded oil and gas exploration and development corporation, since September 2008. Mr. Wilber has been a Director of Ultimate Software Group Inc. since October 2002 and serves as a member of its audit and compensation committees. Since 1984, Mr. Wilber has been a private investor in, and a consultant to, numerous development stage companies. Mr. Wilber holds a Bachelor of Science degree from the U.S. Military Academy at West Point.

John P. Barton has been a director since June 2010. Since 2007, Mr. Barton has served as a managing partner of Energy Capital Partners, LLC, a venture capital firm. Since 2005, Mr. Barton has been a partner of Cambridge Energy Partners, LLC., an oil and gas investment firm. From time to time over the past five years Mr. Barton has been engaged on an independent contractor/consultant basis by various energy companies. Most recently, Mr. Barton has provided consulting services to Synergy Resources Corporation. Mr. Barton holds a degree in Economics and Finance from Millikin University.

We believe that each of our directors’ experience in oil and gas exploration and business development qualifies him to serve as one of our directors.

Rick Wilber and John Barton are the members of our compensation committee. Our Board of Directors serves as our audit committee.

Rick Wilber and John Barton are independent, as that term is defined in Section 803 A(2) of the NYSE MKT Company Guide. Warren Dillard acts as our financial expert.

We have adopted a code of ethics applicable to our principal executive, financial and accounting officers and persons performing similar functions.

ITEM 11.  EXECUTIVE COMPENSATION

The following table summarizes the compensation received by our principal executive and financial officers during the two years ended September 30, 2012.

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						Restricted				Other
	Fiscal	Salary		Bonus		Stock Awards		Option Awards		Annual Compensation
Name and Principal Position	Year	(1)		(2)		(3)		(4)		(5)		Total
Warren Dillard	2012	$	150,000		-		-		-	$	40,000	$	190,000
President, Principal Executive,	2011	$	135,000		-		-		-		-	$	135,000
Financial and Accounting Officer
R. Gerald Bailey	2012	$	190,000		-		-		-		-		190,000
Chairman of the Board	2011	$	105,000		-		-		-		-	$	105,000
Michael Fraim	2012	$	100,000		-		-		-		-	$	100,000
Vice President Technology	2011	$	10,000		-		-		-		-	$	10,000

(1) The dollar value of base salary (cash and non-cash) earned.

(2) The dollar value of bonus (cash and non-cash) earned.

(3) The value of the shares of restricted stock issued as compensation for services computed in accordance with ASC 718 on the date of grant.

(4) The value of all stock options computed in accordance with ASC 718 on the date of grant.

(5) All other compensation received that could not be properly reported in any other column of the table.

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The following shows the amounts we expect to pay to our officers and directors during the twelve months ending November 30, 2013 and the amount of time these persons expect to devote to us.

			Percent of Time to be
Name	Projected Compensation		Devoted to our Business
Warren Dillard	$	190,000		100	%
R. Gerald Bailey	$	240,000		25	%
Steven Powers	$	115,000		40	%
Rick A. Wilber	$	30,000		10	%
John Barton	$	54,000		30	%

Michael Fraim provides consulting services from time to time and is compensated on the basis of actual time spent.

Delton Drum is compensated through his company, C.F.O., Inc., which is the operator for any wells we drill in the Batson Dome Field. We entered into an operating agreement with C.F.O., Inc. dated October 1, 2010. As operator, C.F.O., Inc. receives $2,500 per month for each well being drilled or completed, subject to reductions for days when a well, or wells, are not being drilled. In addition, C.F.O., Inc. is paid $250 per month for each operating well. We may remove C.F.O., Inc. for good cause if it fails to cure a default under the operating agreement within 30 days’ notice from us of a default. C.F.O., Inc. is required to carry insurance for our benefit and may not undertake any single project requiring an expenditure in excess of $5,000 without our prior authorization, except in the case of an emergency. The operating agreement will remain in effect so long as the oil leases covered by the agreement continue in operation.

We have an employment agreement with Warren Dillard which provides that Mr. Dillard is paid a base salary of $12,500 per month, plus an amount equal to the federal and state taxes that he is required to pay with respect to his base salary. The employment agreement with Mr. Dillard can be terminated at any time, by either party, upon 10 days’ notice, without cause.

We have an employment agreement with R. Gerald Bailey. Pursuant to the agreement, we will pay Mr. Bailey $20,000 per month Our agreement with Mr. Bailey is terminable at any time, by either party without cause or penalty.

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We have an employment agreement with Steven Powers. Pursuant to the agreement, Mr. Powers devotes approximately 40% of his time to our business and we pay him a base salary of $7,500 per month, plus an amount equal to the federal and state taxes that he is required to pay with respect to his base salary. The employment agreement with Mr. Powers can be terminated at any time, by either party, upon 10 days’ notice, without cause.

We do not have any employment or compensation agreements with Rick Wilber or John Barton.

Non-Qualified Stock Option Plan. We have a non-qualified stock option plan which authorizes the issuance of up to 1,500,000 shares of our common stock to persons that exercise options granted pursuant to the plan. Our employees, directors, officers, consultants and advisors are eligible to be granted options pursuant to the plan, 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. In the future, the exercise price for options granted pursuant to the plan will not be less than 85% of the fair market value of our common stock on the date of grant.

The following tables show all options granted pursuant to the Non-Qualified Stock Option Plan.  As of November 30, 2012, none of the options had been exercised. The options are fully vested.

			Shares Issuable
	Grant		Upon Exercise		Exercise		Expiration
Name	Date		of Options (1)		Price		Date
Warren M. Dillard		1-10-11		200,000	$	1.00		1-10-14
R. Gerald Bailey		1-10-11		200,000	$	1.00		1-10-14
Steven M. Powers		1-10-11		100,000	$	1.00		1-10-14
Rick A. Wilber		1-10-11		150,000	$	1.00		1-10-14
John P. Barton		1-10-11		100,000	$	1.00		1-10-14
Ben Barton		1-10-11		100,000	$	1.00		1-10-14

(1)    Any options which have not been exercised will automatically terminate upon the option holder’s death, 90 days after the date the option holder voluntarily resigns as an officer, director or employee or in the event the option holder is terminated for cause. For purposes of these options, cause is defined as (i) the failure by the option holder to substantially perform his duties and obligations owed to us (other than any failure resulting from incapacity due to physical or mental illness); (ii) engaging in misconduct or a breach of fiduciary duty which is, or potentially is,materially injurious to us; (iii) commission of a felony; or (iv) the commission of a crime which is, or potentially is, materially injurious to us.

Long-Term Incentive Plans. We do not provide our officers or employees with pension, stock appreciation rights, long-term incentive or other plans.

Employee Pension, Profit Sharing or other Retirement Plans. We do not have a defined benefit, pension plan, profit sharing or other retirement plan, although we may adopt one or more of such plans in the future.

29

Compensation of Directors During Year Ended September 30, 2012. During the year ended September 30, 2012, we did not compensate our directors for acting as such.

Compensation Committee Interlocks and Insider Participation. Rick Wilber and John Barton are the members of our compensation committee. During the year ended September 30, 2012, both Mr. Wilber and Mr. Barton participated in deliberations concerning executive officer compensation. During the year ended September 30, 2012, none of our officers was also a member of the compensation committee or a director of another entity, which other entity had one of its executive officers serving as one of our directors.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The following table shows the beneficial ownership of our common stock, as of November 30, 2012, by (i) each person whom we know beneficially owns more than 5% of the outstanding shares of our common stock, (ii) each of our officers, (iii) each of our directors, and (iv) all the officers and directors as a group. Unless otherwise indicated, each owner has sole voting and investment powers over his shares of common stock. Unless otherwise indicated, beneficial ownership is determined in accordance with the Rule 13d-3 promulgated under the Securities and Exchange Act of 1934, as amended, and includes voting or investment power with respect to shares beneficially owned.

	Number of Shares			Percentage of Class
Name and Address of Beneficial Owner	Beneficially Owned
Warren M. Dillard (2)		1,062,732	(2)(3)		8.3	%
1330 Post Oak Blvd., Suite 1600
Houston, Texas 77056
R. Gerald Bailey		396,032	(3)		3.1	%
1330 Post Oak Blvd., Suite 1600
Houston, Texas 77056
Michael L. Fraim		30,000			*
9266 N. Ventura Ave.
Ventura, CA 93001
Delton C. Drum		40,000			*
2626 Royal Trail Dr.
Kingwood, TX 77339

30

Name and Address of Beneficial Owner	Number of Shares Beneficially Owned			Percentage of Class
Steven M. Powers (2)		957,732	(2)(4)		7.5	%
1999 Avenue of the Stars, Ste. 1100
Los Angeles, CA 90067
Rick A. Wilber		1,173,332	(5)		9.2	%
10360 Kestrel Street
Plantation, FL 33324
John P. Barton (2)		467,732	(2)(4)(6)		3.7	%
1200 17th Street, Suite 570
Denver, CO 80202
All officers and directors as a group		4,127,560	(7)		31.8	%
(7 persons)

______________

* Less than 1%

(1) Assumes none of our outstanding notes is converted and none of our outstanding warrants is exercised.

(2) Shares are beneficially held through trusts or other entities under the control of this beneficial owner.

(3) Includes 200,000 shares issuable upon exercise of an option that is currently exercisable.

(4) Includes 100,000 shares issuable upon exercise of an option that is currently exercisable.

(5) Includes 150,000 shares issuable upon exercise of an option that is currently exercisable.

(6) Includes 100,000 shares owned by Mr. Barton's wife.

(7) Includes 750,000 shares issuable upon exercise of options that are currently exercisable.

31

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

In July 2010, we sold 4,900,000 shares of our common stock at a price of $0.001 per share to our officers and directors and unrelated third parties.

We acquired working interests in our oil and gas leases in the Batson Dome Field, as well as two producing and three shut-in oil wells, from C.F.O., Inc., a corporation controlled by Delton Drum, one of our officers. C.F.O., Inc., which retained a 10% working interest in these leases and wells, paid $200,000 for the leases and wells sold to us. We pay C.F.O., Inc. to operate our oil wells. We believe that the terms of the transactions with C.F.O., Inc. were at least as favorable to us as those generally available from unaffiliated third parties.

We have not issued any preferred stock or made any loans to, or guaranteed any loans on behalf of, any of our founders, officers, directors, five percent or greater stockholders, or any affiliates of the foregoing persons (each an ‘‘Affiliated Person’’). In the future, we will not engage in material affiliated transactions with any Affiliated Person unless the terms of such transactions are approved by a majority of our independent directors who (i) do not have an interest in the transaction and (ii) are independent under state law definitions of independence requiring that the director neither be an officer nor beneficially own 5% or more of our common stock. Material affiliated transactions include and are not limited to the following transactions between us and any Affiliated Person: issuances of common or preferred stock to any Affiliated Person; making any loan to, or forgiving any loan with any Affiliated Person; and guaranteeing any loan on behalf of any Affiliated Person. We will enter into future material affiliated transactions only on terms that are no less favorable to us than those that can be obtained from unaffiliated third parties.

Prior to engaging into future material affiliated transactions, we will appoint, as necessary, and maintain at least two independent directors on our board of directors who are independent under state law definitions of independence requiring that the director neither be an officer nor beneficially own 5% or more of our common stock.

We will provide our independent directors with access to our legal counsel, at our expense, or independent legal counsel in connection with any material affiliated transaction involving our founders, officers, directors, five percent or greater stockholders, or any affiliates of the foregoing persons. Our officers, directors, and counsel will (a) conduct due diligence necessary to assure that there is a reasonable basis for our representations regarding the approval process for material affiliated transactions, and (b) consider whether to embody the representations in our articles of incorporation or bylaws.

32

ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES.

Briggs & Veselka Co. audited our financial statements for the two years ended September 30, 2012.  The following table shows the fees billed to us during the periods presented by Briggs & Veselka.

	Year Ended		Year Ended
	September 30, 2012		September 30, 2011
Audit Fees	$	69,849	$	20,076
Audit-Related Fees	$	27,055	$	156,202
Tax Fees	$	15,401	$	8,458
All Other Fees	$	3,087		--

Audit fees represent amounts billed for professional services rendered for the audit of our annual financial statements and reviews of our quarterly financial statements.

Audit-related fees represent amounts billed for the preparation of a comfort letter in connection with our initial public offering, consents related to other regulatory filing, audit/review of interim financial statements included in our registration statement on Form S-1, and consulting related to the implementation of accounting standards.

Tax fees include professional services for tax return preparation and income tax audit support.

All other fees includes professional services related to assistance with acquisitions.

The policy of our directors is to pre-approve all audit and non-audit services provided by our independent auditors.

33

PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

The following exhibits are filed with this Registration Statement:

Exhibits
3.1*	Articles of Incorporation
3.2*	Bylaws
4.1*	Form of Common Stock Certificate
4.2*	Form of Unit Certificate
4.3*	Form of Class A Warrant Certificate
4.5*	Form of Warrant Agreement
4.6*	Form of Representative's Warrant
4.7*	Non-Qualified Stock Option Plan
4.8**	Form of Series A Warrant
4.9**	Form of Series B Warrant
4.10**	Form of Series C Warrant
4.11**	Form of Series D Warrant
4.12**	Form of Series E Warrant
10.1*	Purchase Agreement between C.F.O., Inc. and Vanguard Energy Corporation
10.2*	Purchase Agreement between Sidekick Xploration, LLC and Enecor, Inc.

10.3*	Assignment between C.F.O., Inc. and Vanguard Energy Corporation
10.4*	Employment Agreement with Warren Dillard
10.5*	Employment Agreement with R. Gerald Bailey
10.6*	Employment Agreement with Steven Powers
10.7*	Farmout Agreement with Claire Oil & Gas, Inc.
10.8*	Operating Agreement with C.F.O, Inc.
10.9*	Farmout Agreement with Exxon/Mobil
10.10*	Form of Convertible Note
10.11*	Amendment to Farmout Agreement with Claire Oil & Gas, Inc.
10.12*	Form of Lock-Up Agreement required by State Securities Administrators
14*	Code of Ethics
21*	Subsidiaries
99	Oil and Gas Reserve Report

___________________

* Incorporated by reference to the same exhibit filed with the Company’s Registration Statement on Form S-1 (File # 333-174194).

** Incorporated by reference to the same exhibit filed with the Company’s registration statement on Form S-1 (File # 333-180987).

34

CONTENTS

	Page
	Number
Report of Independent Registered Public Accounting Firm		F- 1
Consolidated Balance Sheets		F- 2
Consolidated Statements of Operations		F- 3
Consolidated Statements of Changes in Stockholders’ Equity		F- 4
Consolidated Statements of Cash Flows		F- 5
Notes to the Consolidated Financial Statements		F- 6

35

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

Vanguard Energy Corporation

We have audited the accompanying consolidated balance sheets of Vanguard Energy Corporation ("the Company") as of September 30, 2012 and 2011 and the related consolidated statements of operations, changes in stockholders' equity, and cash flows for each of the years 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 upon our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). 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 audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. 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 our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of September 30, 2012 and 2011, and the results of its operations and its cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ Briggs & Veselka Co.

Briggs & Veselka Co.

Houston, Texas

December 27, 2012

F-1

VANGUARD ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

	September 30,			September 30,
	2012			2011
ASSETS
Current assets
Cash and cash equivalents	$	3,090,422		$	453,243
Accounts receivable		615,631			257,147
Other assets		6,132			4,428
Total current assets		3,712,185			714,818
Property and equipment
Oil and gas, on the basis of full cost accounting
Proved properties		9,288,166			3,606,967
Unproved properties and properties under development, not being amortized		1,427,294			619,679
Furniture and equipment		24,494			2,014
Less: accumulated depreciation, depletion and amortization		(1,108,956	)		(264,657	)
Total property and equipment		9,630,998			3,964,003
Debt issuance costs		857,412			338,345
Other assets		15,570			527,886
Total assets	$	14,216,165		$	5,545,052
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	414,873		$	180,031
Other liabilities		344,712			75,056
Current portion of notes payable, net of discount of $77,584 and $0		247,416			-
Current portion of conversion feature liability		564			-
Total current liabilities		1,007,565			255,087
Notes payable, net of discount of $635,748 and $1,066,539		7,618,752			2,333,461
Participation liability		1,573,605			1,172,315
Conversion feature liability		583,454			720,593
Warrant liabilities		68,746			400,319
Asset retirement obligations		96,410			24,629
Total liabilities		10,948,532			4,906,404
Commitments and contingencies		-			-
Stockholders' equity
Preferred stock, $0.00001 par value; 5,000,000 shares authorized, none issued or outstanding		-			-
Common stock, $0.00001 par value; 50,000,000 shares authorized,
12,741,512 and 7,880,822 shares issued and outstanding		127			79
Additional paid-in capital		5,522,204			1,866,110
Accumulated deficit		(2,254,698	)		(1,227,541	)
Total stockholders' equity		3,267,633			638,648
Total liabilities and stockholders' equity	$	14,216,165		$	5,545,052

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

F-2

VANGUARD ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

	Fiscal Year			Fiscal Year
	Ended			Ended
	September 30, 2012			September 30, 2011
Revenues
Oil and gas sales	$	3,369,407		$	1,899,584
Costs and expenses
Lease operating expense		672,233			200,742
Production taxes		155,616			87,217
Depreciation, depletion and amortization		844,299			264,657
Asset retirement obligation accretion		8,922			3,260
General and administrative		1,564,475			1,013,304
Total costs and expenses		3,245,545			1,569,180
Income from operations		123,862			330,404
Other income (expense)
Interest income		3,062			904
Interest expense		(1,171,756	)		(679,629	)
Change in fair value of warrant and
conversion feature liabilities		1,081,371			(761,076	)
Change in estimate of participation liability		(653,057	)		-
Loss on debt extinguishment		(410,639	)		-
Total other income (expense)		(1,151,019	)		(1,439,801	)
Loss before income taxes		(1,027,157	)		(1,109,397	)
Provision for income taxes		-			-
Net loss	$	(1,027,157	)	$	(1,109,397	)
Loss per share – Basic	$	(0.09	)	$	(0.15	)
Weighted average number of
common shares		11,901,830			7,170,906
Loss per share – Diluted	$	(0.09	)	$	(0.15	)
Weighted average number of common
and potential common shares		11,901,830			7,170,906

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

F-3

VANGUARD ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

										Total
	Common Stock				Additional		Accumulated			Stockholders’
	Shares		Amount		Paid In Capital		Deficit			Equity
Balance at
October 1, 2010		5,912,500	$	59	$	409,841	$	(118,144	)	$	291,756
Stock-based
compensation		15,000		-		258,731		-			258,731
Exercise of warrants		453,322		5		181,299		-			181,304
Issuance of
common stock units		1,500,000		15		1,016,239		-			1,016,254
Net loss		-		-		-		(1,109,397	)		(1,109,397	)
Balance at
October 1, 2011		7,880,822	$	79	$	1,866,110	$	(1,227,541	)	$	638,648
Stock-based
compensation		60,690		-		59,700		-			59,700
Issuance of
common stock units		4,800,000		48		3,596,394		-			3,596,442
Net loss		-		-		-		(1,027,157	)		(1,027,157	)
Balance at
September 30, 2012		12,741,512	$	127	$	5,522,204	$	(2,254,698	)	$	3,267,633

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

F-4

VANGUARD ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Fiscal Year			Fiscal Year
	Ended			Ended
	September 30, 2012			September 30, 2011
Cash flows from operating activities
Net loss	$	(1,027,157	)	$	(1,109,397	)
Adjustments to reconcile net loss
to net cash from operating activities:
Loss on debt extinguishment		410,639			-
Change in estimate of participation liability		653,057			-
Depreciation, depletion and amortization		844,299			264,657
Amortization of debt issuance costs		237,809			205,697
Asset retirement obligation accretion		8,922			3,260
Amortization of debt discount		736,446			280,256
Accretion of participation liability		97,535			108,503
Stock-based compensation expense		59,700			258,731
Change in fair value of warrant and conversion
feature liabilities		(1,081,371	)		761,076
Change in operating assets and liabilities:
Accounts receivable		(358,484	)		(252,247	)
Other assets		(14,680	)		42,977
Accounts payable		(54,291	)		93,721
Other liabilities		(129,341	)		(179,968	)
Net cash from operating activities		383,083			477,266
Cash flows from investing activities
Purchase of furniture and equipment		(22,480	)		(2,014	)
Purchase of oil and gas properties		-			(309,247	)
Capital expenditures on oil and gas properties		(6,113,295	)		(3,087,047	)
Net cash from investing activities		(6,135,775	)		(3,398,308	)
Cash flows from financing activities
Debt issuance costs		(813,780	)		(400,051	)
Equity offering costs		(199,849	)		(525,291	)
Proceeds from issuance of common stock and warrants		4,224,000			1,340,155
Proceeds from exercise of warrants		-			45,289
Repayment of note payable		-			(642,753	)
Proceeds from issuance of notes payable		5,179,500			3,400,000
Net cash from financing activities		8,389,871			3,217,349
Net change in cash and cash equivalents		2,637,179			296,307
Cash and cash equivalents
Beginning of period		453,243			156,936
End of period	$	3,090,422		$	453,243

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

F-5

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – ORGANIZATION

Organization—Vanguard Energy Corporation (the "Company") was organized under the laws of the State of Colorado on June 21, 2010. The Company conducts business in Texas through VE Corporation, a Colorado corporation and wholly owned subsidiary. The Company commenced operations on July 19, 2010 and is engaged in the acquisition, development and operation of onshore oil and gas properties in Texas.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Basis of Presentation— The consolidated financial statements include the accounts of Vanguard Energy Corporation and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

The Company's fiscal year-end is September 30. The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") and pursuant to the accounting and disclosure rules and regulations of the U.S. Securities and Exchange Commission ("SEC"). A summary of the significant accounting policies applied in the preparation of the accompanying financial statements follows.

Management Estimates—The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the fair value of acquired assets and liabilities (Note 3), asset retirement obligations (Note 4), participation, conversion feature and warrant liabilities (Note 5), income taxes (Note 6) and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (Note 12).

Reclassifications – Certain amounts previously presented for prior periods have been reclassified to conform to the current presentation. The reclassifications had no effect on net loss, working capital or equity previously reported.

Cash and Cash Equivalents—The Company considers all highly liquid instruments purchased with a maturity date of three months or less to be cash equivalents.

Oil and Gas Properties—The Company follows the full cost accounting method to account for oil and natural gas properties, whereby costs incurred in the acquisition, exploration and development of oil and gas reserves are capitalized. Such costs include lease acquisition, geological and geophysical activities, rentals on nonproducing leases, drilling, completing and equipping of oil and gas wells and administrative costs directly attributable to those activities and asset retirement costs. Disposition of oil and gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such adjustment would significantly alter the relationship between capital costs and proved reserves of oil and gas, in which case the gain or loss is recognized to  operations.

The capitalized costs of oil and gas properties, excluding unevaluated and unproved properties, are amortized as depreciation, depletion and amortization expense using the units-of-production method based on estimated proved recoverable oil and gas reserves.

The costs associated with unevaluated and unproved properties, initially excluded from the amortization base, relate to unproved leasehold acreage, wells and production facilities in progress and wells pending determination of the existence of proved reserves, together with capitalized interest costs for these projects. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well once a determination of the existence of proved reserves has been made or upon impairment of a lease. Costs associated with wells in progress and completed wells that have yet to be evaluated are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry wells are transferred to the amortization base immediately upon determination that the well is unsuccessful.

F-6

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All items classified as unproved property are assessed on a quarterly basis for possible impairment or reduction in value. Properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization.

Under full cost accounting rules for each cost center, capitalized costs of evaluated oil and gas properties, including asset retirement costs, less accumulated amortization and related deferred income taxes, may not exceed an amount (the "cost ceiling") equal to the sum of (a) the present value of future net cash flows from estimated production of proved oil and gas reserves, based on current prices and operating conditions, discounted at ten percent (10%), plus (b) the cost of properties not being amortized, plus (c) the lower of cost or estimated fair value of any unproved properties included in the costs being amortized, less (d) any income tax effects related to differences between the book and tax basis of the properties involved. If capitalized costs exceed this limit, the excess is charged to  operations.  For purposes of the ceiling test calculation, current prices are defined as the unweighted arithmetic average of the first day of the month price for each month within the 12 month period prior to the end of the reporting period.  Prices are adjusted for basis or location differentials.  Unless sales contracts specify otherwise, prices are held constant for the productive life of each well.  Similarly, current costs are assumed to remain constant over the entire calculation period.

Given the volatility of oil and gas prices, it is reasonably possible that the estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline in the future, even if only for a short period of time, it is possible that impairments of oil and gas properties could occur. In addition, it is reasonably possible that impairments could occur if costs are incurred in excess of any increases in the present value of future net cash flows from proved oil and gas reserves, or if properties are sold for proceeds less than the discounted present value of the related proved oil and gas reserves.

Revenue Recognition—Oil and gas sales result from undivided interests held by the Company in oil and gas properties. Sales of oil and gas produced from oil and gas operations are recognized when the product is delivered to the purchaser and title transfers to the purchaser. The Company had no natural gas sales imbalance positions at September 30, 2012 or 2011. Charges for gathering and transportation are included in production expenses.

Asset Retirement Obligations—The Company records a liability for asset retirement obligations ("ARO") associated with its oil and gas wells when those assets are placed in service. The corresponding cost is capitalized as an asset and included in the carrying amount of oil and gas properties and is depleted over the useful life of the properties. Subsequently, the ARO liability is accreted to its then-present value.

Inherent in the fair value calculation of an ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Settlements greater than or less than amounts accrued as ARO are recorded as a gain or loss upon settlement.

Capitalized Interest—Interest is capitalized as part of the historical cost of developing and constructing assets for significant projects. Significant oil and gas investments in unproved properties, significant exploration and development projects for which depreciation, depletion and amortization expense is not currently recognized, and exploration or development activities that are in progress qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depletion or impairment, along with other capitalized costs related to that asset.

F-7

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Debt Issuance Costs—Costs incurred in connection with the issuance of long-term debt are capitalized and amortized over the term of the related debt.

Participation Liability—The participation liability associated with outstanding long-term debt is recorded at fair value as determined utilizing a present value factor of 10 applied to proved developed reserves. Payments made for the participation liability are reported as interest expense. Changes in the fair value of the participation liability are recorded as additions or deductions to the discount on the long-term debt to the extent this debt remains outstanding.  Once the associated debt is repaid, changes in the participation liability are recorded to other expense in the statements of operations.

Conversion Feature Liability and Warrant Liabilities—The conversion feature liability and warrant liabilities are recorded at fair value based upon valuation models utilizing relevant factors such as expected life, estimated volatility, risk-free interest and expected dividend rate. Changes in the fair value of these liabilities are reported in the statements of operations.

Stock-Based Compensation—The Company accounts for employee stock-based compensation using the fair value method. The fair value attributable to stock options is calculated based on the Black-Scholes option pricing model and is amortized to expense over the service period which is equivalent to the time required to vest the stock options.

Income Taxes—Income taxes are provided based on the liability method for financial reporting purposes. Under this method deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount expected to be realized.

Uncertain tax positions are recognized in the financial statements only if that position is more likely than not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense.

The Company is required to file federal income tax returns in the United States and in various state and local jurisdictions. The Company's tax returns filed since inception are subject to examination by taxing authorities in the jurisdictions in which it operates in accordance with the normal statutes of limitations in the applicable jurisdiction.

Earnings (Loss) Per Share—Basic earnings (loss) per share have been calculated based upon the weighted-average number of common shares outstanding. The weighted-average number of common shares outstanding used in the computations of earnings (loss) per share was 11,901,830 for 2012 and 7,170,906 for 2011. The calculation of diluted weighted-average shares outstanding for 2012 and 2011 excludes 19,751,560 shares and 8,110,000 shares, respectively, issuable pursuant to outstanding warrants, stock options and debt conversion features because their effect is anti-dilutive.

Concentration of Credit Risk—The Company is subject to credit risk resulting from the concentration of its oil and natural gas receivables with significant purchasers. One purchaser accounted for all of the Company's oil and gas sales revenues for 2012 and 2011. The Company does not require collateral. While the Company believes its recorded receivable will be collected, in the event of default the Company would follow normal collection procedures. The Company does not believe the loss of this purchaser would materially impact its operating results as oil and gas are fungible products with well-established markets and numerous purchasers.

F-8

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

At times, the Company maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits.

Fair Value Measurements—The carrying value of cash and cash equivalents, accounts receivable, and accounts payable, as reflected in the balance sheets, approximate fair value because of the short-term maturity of these instruments. The estimated fair value of long-term debt was determined by discounting future cash flows using rates currently available to the Company for debt with similar terms and remaining maturities. The Company calculated that the estimated fair value of the long term debt is not significantly different than the carrying value of the debt. The participation liability associated with outstanding long-term debt was determined by utilizing a present value factor of 10 applied to proved developed reserves associated with the wells drilled with the proceeds of the notes.

Fair value is defined as the price that would be received to sell an asset or price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are classified for disclosure purposes according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair-value-measurement hierarchy are as follows:

●   Level 1—Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

●   Level 2—Inputs that reflect quoted prices for identical assets or liabilities in markets that are not active; quoted prices for similar assets or liabilities in active markets; inputs other than quoted prices that are observable for the asset or the liability; or inputs that are derived principally from or corroborated by observable market data by correlation or other means.

●   Level 3—Unobservable inputs reflecting the Company's own assumptions incorporated in valuation techniques used to determine fair value. These assumptions are required to be consistent with market participant assumptions that are reasonably available.

In determining fair value, the Company utilizes observable market data when available, or models that incorporate observable market data. In addition to market information, the Company incorporates transaction-specific details that, in management's judgment, market participants would take into account in measuring fair value. The Company utilizes the most observable inputs available for the valuation technique employed. If a fair value measurement reflects inputs at multiple levels within the hierarchy, the fair-value measurement of both financial and nonfinancial assets and liabilities are characterized based upon the lowest level of input that is significant to the fair value measurement.

Recently Issued Accounting Pronouncements – In April 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2010-13. ASU 2010-13 provides amendments to Topic 718, Stock Compensation, to clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity's equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. The amendments in ASU No. 2010-13 are effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2010. The Company’s adoption of the new guidance did not have a material effect on the Company’s consolidated financial statements.

F-9

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

In December 2010, the FASB issued ASU 2010-29, which addresses diversity in practice concerning the interpretation of the pro forma revenue and earnings disclosure requirements for business combinations. This ASU specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. This ASU also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. ASU 2010-29 is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. The adoption of this guidance did not have a material impact on the Company's financial statements.

In May 2011, the FASB issued ASU 2011-04, which clarifies some existing fair value measurement concepts, eliminates wording differences between U.S. GAAP and International Financial Reporting Standards (“IFRS”), and in some limited cases, changes some fair value measurement principles to achieve convergence between U.S. GAAP and IFRS. ASU 2011-04 is effective for the Company beginning after December 15, 2011. The adoption of this guidance did not have a material impact on the Company's financial statements.

Various other accounting standards updates were recently issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, and are not expected to a have a material impact on the Company's financial position, results of operations or cash flows.

NOTE 3 –ACQUISITIONS

By agreement dated March 15, 2011, the Company entered into a farmout agreement with an unrelated third party pertaining to a 100-acre lease in the Batson Dome Field. As of September 30, 2012, the Company had drilled three wells on the lease. Pursuant to the farmout agreement the Company has the option of drilling additional wells on the lease; provided however, that if it does not drill at least six wells in any twelve month period the right to drill any additional wells on the lease will terminate. The estimated cost of drilling and completing any well on this lease is approximately $500,000.As of September 30, 2012, the Company had drilled three wells on this lease.

By agreement dated May 25, 2011, the Company entered into a farmout agreement with an unrelated third party pertaining to a 100-acre lease in the Batson Dome Field. Pursuant to the agreement, the Company had the obligation to commence drilling a well on the lease by June 14, 2012. In June 2012, the Company paid $10,000 to extend the agreement, whereby it now has an obligation to commence drilling by June 14, 2013. Subject to the commencement of drilling the first well by June 14, 2013, and completing the well if warranted, the Company has the option of drilling additional wells on the lease; provided however, that unless the Company commences drilling each well within 180 days of the date the latest well is completed or abandoned, the right to drill any additional wells on the lease will terminate. The estimated cost of drilling and completing any well on this lease is approximately $1,000,000.  As of September 30, 2012, the Company had not commenced any drilling operations on the lease subject to the farmout agreement.

By agreement dated January 6, 2012, the Company entered into a three-year farmout agreement with an unrelated third party pertaining to another 70-acre lease in the Batson Dome Field. The estimated cost of drilling and completing any well on this lease is approximately $1,000,000.

F-10

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

By agreement dated May 1, 2012, the Company entered into a farmout agreement with an unrelated third party pertaining to  a 45-acre lease in the Hull-Daisetta Field. Pursuant to the agreement, the Company has the obligation to commence drilling a well on the lease by January 31, 2013. Subject to the commencement of drilling the first well by January 31, 2013, and completing the well if warranted, the Company has the option of drilling additional wells on the lease; provided however, that unless the Company commences drilling each well within 180 days of the date the latest well is completed or abandoned, the right to drill any additional wells on the lease will terminate. The estimated cost of drilling and completing any well on this lease is approximately $750,000.  As of September 30, 2012, the Company had not drilled any wells on this lease.

On September 30, 2010, the Company acquired a forty percent (40%) working interest in mineral leases for 220 acres in Hardin County, Texas, within the area known as the Batson Dome Field, from C.F.O., Inc., a corporation controlled by Delton Drum, one of the Company’s officers, for the total consideration of $325,668, consisting of a cash payment of $40,000 and a secured 90-day promissory note for $285,668.  On October 1, 2010, the Company acquired an additional fifty percent (50%) working interest in the Batson Dome Field for the total consideration of $407,085, consisting of a cash payment of $50,000 and a secured 90-day promissory note for $357,085.  The 90-day promissory notes bore interest at eight percent (8%) per annum and were repaid in December 2010.  Although the leases are in a previously developed oil and gas field, these purchases excluded any interest in existing well bores or surface equipment.

On December 16, 2010, and in payment of $259,247 in cash, the Company acquired a ninety percent (90%) working  interest in 10 acres adjacent to its existing 220 acres under lease in the Batson Dome Field, as well as a ninety percent (90%) working interest in two producing oil wells and three shut in wells located on the 10 acre lease. The leases and wells were acquired from C.F.O., Inc.  This purchase was accounted for under the acquisition method of accounting and, as such, the assets and liabilities of the acquired properties are recognized at their estimated fair values as of the date of the acquisition.  The estimated fair value of these properties approximates the consideration paid, which the Company concluded approximates the fair value that would be paid by a typical market participant. Acquisition-related costs of approximately $15,000 were expensed. The purchase price for the acquisition was allocated as follows:

Consideration paid -- cash	$	259,247
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed and undeveloped properties		274,463
Asset retirement obligations		(15,216	)
Total identifiable net assets	$	259,247

The unaudited financial information in the table below summarizes the combined results of the Company's operations and the properties acquired, on a pro forma basis, as though the purchase had taken place at the October 1, 2010. The pro forma information is based on the Company's results of operations for 2012 and 2011 on historical results of the properties acquired, and on estimates of the effect of the transactions to the combined results. Because the acquisitions occurred in prior periods, the 2012 pro forma amounts are the same as the actual amounts. The pro forma information is not necessarily indicative of results that actually would have occurred had the transaction been in effect for the periods indicated, or of results that may occur in the future.

F-11

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

	Fiscal Year						Fiscal Year
	Ended						Ended
	September 30, 2012						September 30, 2011
	Actual			Proforma			Actual			Proforma
Revenues	$	3,369,407		$	3,369,407		$	1,899,584		$	1,906,804
Net loss		(1,027,157	)		(1,027,157	)		(1,109,397	)		(1,107,798	)
Loss per share – Basic and diluted		(0.09	)		(0.09	)		(0.15	)		(0.15	)

Through these acquisitions, the Company owns a ninety percent (90%) working interest in mineral leases for 230 acres in the Batson Dome Field. C.F.O., Inc. is a related party and owns the remaining ten percent (10%) working interest and is the operator for the mineral leases pursuant to a joint operating agreement between the Company and C.F.O., Inc.  The Company has recorded a receivable from C.F.O., Inc. for their 10% share of capital expenditures.  At September 30, 2012, this amount totaled $238,940 and is expected to be repaid within the next twelve months from C.F.O., Inc.’s share of production or from other sources.

NOTE 4 – ASSET RETIREMENT OBLIGATIONS

During the fiscal years presented, the Company brought a number of oil and gas wells into productive status and will have asset retirement obligations once the wells are permanently removed from service. The primary obligations involve the removal and disposal of surface equipment, plugging and abandoning the wells, and site restoration. For the purpose of determining the fair value of ARO incurred during the fiscal years presented, the Company used the following assumptions:

	September 30, 2012			September 30, 2011
Inflation rate		4	%		4	%
Estimated asset life	9.5 years			9.5 years
Credit adjusted risk free interest rate		18	%		18	%

F-12

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the change in the Company's ARO for 2011 and 2012:

Asset retirement obligations at October 1, 2010	$	-
Obligations assumed in acquisition		15,216
Additional retirement obligations incurred		6,153
Changes in estimate		-
Accretion expense		3,260
Settlements		-
Asset retirement obligations at September 30, 2011	$	24,629
Obligations assumed in acquisition		-
Additional retirement obligations incurred		36,959
Change in estimate		49,428
Accretion expense		8,922
Settlements		(23,528	)
Asset retirement obligations at September 30, 2012	$	96,410

F-13

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5 – LONG-TERM DEBT

2010 Convertible Promissory Notes – In December 2010, the Company completed the issuance of $3,400,000 in Convertible Promissory Notes, due and payable on October 31, 2012 and convertible, at the holder’s option, into common stock of the Company at $1.00 per share at any time after April 30, 2011.  The 2010 Convertible Promissory Notes bear interest at 8% per year, payable quarterly.  In addition, the note holders were issued 1,700,000 Series A warrants to purchase the Company’s common stock at $4.00 per share any time on or before October 31, 2014 and were additionally granted a twenty percent (20%) net profits interest payable quarterly from any net profits generated from wells drilled and completed with the proceeds of the notes.  The notes are secured by the oil and gas leases acquired, and any oil or gas wells drilled on the leases, with the proceeds from the sale of the notes. 

Direct costs of $400,051 were incurred in connection with the issuance of the 2010 Convertible Promissory Notes.  The Company also issued the placement agent Series B warrants for the purchase of up to 340,000 shares of common stock at a price of $1.20 per share at any time prior to October 31, 2014, 170,000 shares of common stock at a price of $4.00 per share at any time prior to October 31, 2014, and 453,322 shares of common stock at a price of $0.10 per share at any time prior to March 31, 2011.  As of September 30, 2012, 453,322 warrants have been exercised. The warrants also provide for adjustment to their exercise prices  under certain circumstances.

During 2012, $3,075,000 of the 2010 Convertible Promissory Notes outstanding were surrendered in exchange for new 2012 Convertible Promissory Notes as discussed below. The remaining notes, which had an outstanding principal balance of $325,000, were repaid in October 2012.

2012 Convertible Promissory Notes – During 2012, the Company issued $8,254,500 of Convertible Promissory Notes, due and payable on June 30, 2015 and convertible at the holder’s option, into common stock of the Company at $1.25 per share.  The Convertible Promissory Notes bear interest at 15% per year, payable quarterly. Of the total amount raised, $5,179,500 represented new cash investors and $3,075,000 represented investors from the 2010 convertible note offering who chose to roll their investment in that earlier offering into the Company's new offering. Net proceeds from this financing are being used to fund an accelerated developmental drilling program in the Company's oil fields located in Southeast Texas and to pay any of the 2010 Convertible Promissory Notes that remain outstanding on October 31, 2012, the maturity date of those notes.

Except in certain circumstances, the conversion price of the 2012 Convertible Promissory Notes will be lowered if the Company sells any additional shares of common stock or any securities convertible into common stock, at a price below the then applicable conversion price.  The conversion price will also be proportionately adjusted in the event of any stock split, or capital reorganization.  On or prior to December 31, 2013, the Company may repay the Notes, without penalty, upon twenty days written notice to the Note holders if, during any twenty trading days within a period of thirty consecutive trading days, the closing price of the Company’s common stock is $2.25 or greater and the Company’s common stock has an average daily trading volume of 100,000 shares or more during the twenty trading days. After December 31, 2013 the Company may prepay the Notes upon twenty days written notice to the Note holders.

Direct costs of $813,780 were incurred in connection with the issuance of the 2012 Convertible Promissory Notes.  The Company recognized a loss on debt extinguishment of $410,639 related to the investors who chose to roll their investment in the 2010 Convertible Promissory Notes into the new offering. The placement agents for this offering received a cash commission of $619,905 as well as 537,360 Series E warrants. Each Series E warrant entitles the holder to purchase one share of the Company’s common stock. The Series E warrants may be exercised at any time on or before June 30, 2017 at a price of $1.55 per share.

Total Indebtedness under Convertible Promissory Notes – The Company’s combined gross outstanding balance of the 2010 and 2012 Convertible Promissory Notes was $8,579,500 as of September 30, 2012.  As of September 30, 2012, the combined unamortized discount on the 2010 and 2012 Convertible Promissory Notes totaled $713,332.  Interest expense for the amortization of debt issuance costs and discount on the notes was $965,748 and $485,910 for the years ended September 30, 2012 and 2011, respectively.  The combined effective interest rate of the 2010 and 2012 Convertible Promissory Notes (net of the participation liability discussed below) was 26.5% as of September 30, 2012.

F-14

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Net Profits Interest Participation Liability – The note holder’s twenty percent (20%) net profits interest granted with the issuance of the 2010 Convertible Promissory Notes is owned by Vanguard Net Profits, LLC, a Texas limited liability company (the “Fund”). The Company has a 1% interest in the Fund and is the Fund’s manager.  Persons that purchased the Company’s 2010 Convertible Promissory Notes own the remaining interest in the Fund.

The Company has recognized a participation liability related to the net profits interest granted. This participation liability is reflected in the liability section of the balance sheets at its estimated fair value of $1,573,605 as of September 30, 2012 and $1,172,315 as of September 30, 2011. At any time, the Company may purchase the net profits interests held by the Fund for $3,400,000.

The Company estimated the fair value of the participation liability utilizing a present value factor of 10 applied to proved developed reserves associated with the wells drilled and completed with the proceeds of the notes.   Changes in the fair value of the participation liability are recorded as additions or deductions to the discount on the long-term debt to the extent 2010 Convertible Promissory Notes remain outstanding.  Otherwise, changes in the participation liability are recorded to other expense in the statements of operations.

The Company incurred expense associated with this net profits interest during the years ended September 30, 2012 and 2011 of $97,535 and $108,503, respectively. This amount is reported as interest expense in the statement of operations. The Company also made payments under this arrangement of $375,470 and $329,006 during the years ended September 30, 2012 and 2011, respectively.

NOTE 6 – INCOME TAXES

The provision for income taxes consists of the following:

	Fiscal Year Ended		Fiscal Year Ended
	September 30, 2012		September 30, 2011
Current	$	-	$	-
Deferred		-		-
Total	$	-	$	-

F-15

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The provision for income taxes differs from the amount computed by applying the federal statutory income tax rate (34%) on operations as follows:

	Fiscal Year Ended			Fiscal Year Ended
	September 30, 2012			September 30, 2011
Income tax expense computed at statutory rates	$	(349,233	)	$	(377,195	)
Non-deductible items		(366,608	)		259,666
Change in valuation allowance		715,841			117,529
Total	$	-		$	-

The components of the net deferred tax asset were as follows:

	September 30,			September 30,
	2012			2011
Deferred tax assets
Net operating loss carryforwards	$	2,987,160		$	824,260
Stock-based compensation		103,367			82,869
Other		-			-
Deferred tax liability - oil & gas properties		(2,319,346	)		(749,431	)
Participation liability		102,739			-
Net deferred tax assets before valuation allowance		873,920			157,698
Valuation allowance		(873,920	)		(157,698	)
Net deferred tax asset	$	-		$	-

A valuation allowance has been established to offset reported deferred tax assets. The Company's accumulated net operating losses were approximately $8.8 million at September 30, 2012 and begin to expire if not utilized in the year 2030.

F-16

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7 – STOCKHOLDERS' EQUITY

Preferred Stock—5,000,000 shares authorized, none issued or outstanding.

Common Stock—The Company is authorized to issue an aggregate of 50,000,000 shares of common stock with $0.00001 par value. In July 2010, the Company sold 4,900,000 shares of common stock at $0.001 per share in a private placement. In September 2010, the Company completed a second private placement of 1,012,500 shares of common stock at $0.40 per share. Net proceeds from the private placements were used for general corporate purposes, including capital expenditures.

In February and March 2011, the Company sold 1,500,000 units at a price of $1.00 per unit to private investors. Each unit consisted of one share of common stock and one Series C warrant. Each Series C warrant allows the holder to purchase one share of Company common stock at a price of $2.00 per share at any time prior to February 28, 2016. The Company also issued the placement agent Series D warrants for the purchase of up to 150,000 shares of common stock at a price of $1.20 per share at any time prior to February 28, 2016.

On December 2, 2011 the Company sold 4,800,000 units in an initial public offering at a price of $1.00 per unit.  Each unit consisted of one share of the Company's common stock and one Class A warrant.  Each Class A warrant entitles its holder to purchase one share of the Company's common stock at an exercise price of $1.50.  The Class A warrants are exercisable at any time on or before November 29, 2016.  The underwriters for the offering were paid a commission of $432,000 (9% of the gross offering proceeds) and a non-accountable expense allowance of $144,000 (3% of the gross offering proceeds). The underwriters also received warrants to purchase up to 480,000 units.  Proceeds from the IPO were approximately $3,498,900 net of the underwriters’ discount and offering expenses.

During the years ended September 30, 2012 and 2011, the Company issued 60,690 and 15,000 shares, respectively, of restricted stock for investor relations consulting services. The Company recognized expense of $59,700 during 2012 and $15,000 during 2011 related to the issuance of these shares.

Following the above issuances of common stock, the Company has 12,741,512 shares issued and outstanding as of September 30, 2012.

F-17

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Warrants—The following table summarizes certain information regarding outstanding warrants as of September 30, 2012 and 2011:

				Exercise	Warrants Outstanding
Type	Issuance Date	Expiration Date		Price	2012	2011
Series A	December 1, 2010	October 31, 2014		$4.00	1,700,000	1,700,000
Series B	December 1, 2010	October 31, 2014		$1.20	340,000	340,000
Series B	December 1, 2010	October 31, 2014		$4.00	170,000	170,000
Series B	December 1, 2010	March 31, 2011	(1)	$0.10	-	-
Series C	February 28, 2011	February 28, 2016		$2.00	1,500,000	1,500,000
Series D	February 28, 2011	February 28, 2016		$1.20	150,000	150,000
Class A	December 2, 2011	November 29, 2016		$1.50	4,800,000	-
Series E	June 29, 2012	June 15, 2017		$1.55	296,300	-
Series E	July 6, 2012	June 15, 2017		$1.55	72,500	-
Series E	July 31, 2012	June 15, 2017		$1.55	57,160	-
Series E	September 5, 2012	June 15, 2017		$1.55	111,400	-

(1)    Exercised in March 2011.

NOTE 8 – STOCK-BASED COMPENSATION

On January 10, 2011, the Board of Directors approved a Non-Qualified Stock Option Plan (the "Plan") which authorizes the issuance of up to 1,500,000 shares of Company common stock to persons that exercise options granted pursuant to the Plan. The Company's employees, directors, officers, consultants and advisors are eligible to be granted options pursuant to the Plan, 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.

F-18

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Options for the purchase of 850,000 shares of the Company's common stock were issued to members of executive management and the Board of Directors on January 10, 2011. The stock options have an exercise price of $1.00 per share and were fully vested on the date of grant. The fair value of each stock option grant was estimated on the date of grant using the Black-Scholes option pricing model and the following assumptions:

Risk-free interest rate		0.99	%
Expected dividend rate		0.00	%
Expected volatility		40.80	%
Expected life (years)		3
Calculated value of options granted	$	0.29

No stock options have been exercised to date. The Company recognized stock-based compensation expense of $243,731 during 2011 related to the issuance of these options.

NOTE 9 – COMMITMENTS AND CONTINGENCIES

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

The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company also conducts periodic reviews, on a Company-wide basis, to identify changes in its environmental risk profile.

Management Agreements – In June 2010, the Company entered into an agreement with an entity controlled by its Chief Executive Officer ("CEO") to provide for his personal part-time management consulting services for $7,500 per month, on a month-to-month basis. Also in June 2010, the Company entered into a consulting services agreement with its Chairman of the Board to provide for his personal part-time management consulting services for $3,000 per month, on a month-to-month basis. Beginning in January 2011, the monthly payments were increased to $12,500 for the CEO and $10,000 for the Chairman. In May 2011, these consulting arrangements were replaced with employment agreements for each executive.

Office Lease – The Company leases office space under an operating lease. Rent expense for 2012 and 2011 totaled $81,641 and $47,076, respectively.   Future minimum payments on office leases are shown below.

F-19

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Contractual Obligations – The Company’s material future contractual obligations by fiscal year as of September 30, 2012 were as follows:

	Total		2013		2014		2015		Thereafter
Convertible notes	$	8,579,500	$	325,000		-	$	8,254,500		-
Office leases	$	65,800	$	65,800		-		-		-

The Company has no contractual capital commitments outstanding at September 30, 2012.  Management estimates the Company will spend approximately $7,000,000 during fiscal year 2013 for drilling and completing wells in the Batson Dome Field and various other projects.

NOTE 10 – FAIR VALUE OF FINANCIAL INSTRUMENTS

The following table summarizes the financial liabilities measured at fair value on a recurring basis as of September 30, 2012 and 2011:

	Level		September 30, 2012		September 30, 2011
Participation liability		3	$	1,573,605	$	1,172,315
Conversion feature liability		3		584,018		720,593
Warrant liabilities		3		68,746		400,319
Total liabilities			$	2,226,369	$	2,293,227

Assets and liabilities that are not recognized or disclosed on a recurring basis include those measured at fair value in a business combination and the initial recognition of asset retirement obligations.

F-20

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The following tables present a reconciliation of those liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3):

	Participation Liability			Conversion Feature Liability			Warrant Liabilities			Total
Balance at September 30, 2011	$	1,172,315		$	720,593		$	400,319		$	2,293,227
Purchases, issuances and settlements		(349,302	)		613,223			-			263,921
(Gains) losses included in earnings		750,592			(749,798	)		(331,573	)		(330,779	)
Balance at September 30, 2012	$	1,573,605		$	584,018		$	68,746		$	2,226,369

NOTE 11 – SUPPLEMENTAL CASH FLOW INFORMATION

	Fiscal Year Ended		Fiscal Year Ended
	September 30, 2012		September 30, 2011
Interest paid	$	250,734	$	242,702
Interest capitalized (non-cash)		350,142		225,529
Exchange of 2010 Notes for 2012 Notes		3,075,000		-
Noncash investing and financing activities:
Capital expenditures included in accounts payable		289,133		84,365
Issuance of notes payable for oil and gas properties		-		357,085
Warrant liability settled on exercise		-		136,015
Recognition of liabilities for issuance of:
Series A warrants		-		1,188
Series B warrants		-		143,948
Series C warrants		-		274,516
Series D warrants		-		49,385
Issuance of Series E Warrants to placement agent		97,583		-
Recognition of conversion feature liability		670,893		26,771
Recognition of participation liability		-		737,886
Asset retirement obligations incurred		86,386		4,588

F-21

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 12 – SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Results of operations.  Results of operations for producing activities consist of all activities for the exploration, production and sale of oil and gas.  Net revenues from production include only the revenues from the production and sale of oil and natural gas. Production costs are those incurred to operate and maintain wells and related equipment and facilities used in oil and gas operations. Income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.

	Fiscal Year Ended September 30, 2012		Fiscal Year Ended September 30, 2011
Net revenues from production
Third-party sales	$	3,369,407	$	1,899,584
Production costs
Lease operating expense		672,233		200,742
Production taxes		155,616		87,217
Asset retirement obligation accretion		8,922		3,260
		836,771		291,219
Depreciation, depletion and amortization		842,571		264,489
		1,690,065		1,343,876
Income tax expense		573,270		455,843
Results of operations from producing activities	$	1,116,795	$	888,033

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development. Amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year for oil and gas property acquisition, exploration and development activities. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful exploration wells, as well as dry hole costs, leasehold impairments, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities.

F-22

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

	Fiscal Year Ended September 30, 2012		Fiscal Year Ended September 30, 2011
Property acquisitions
Unproved	$	59,784		$	407,085
Proved		-			259,247
Exploration		170,857			108,587
Development		6,258,174			3,084,194
Total Costs Incurred	$	6,488,815		$	3,859,113

Capitalized costs. Capitalized costs include the cost of properties, equipment and facilities for oil and natural-gas producing activities. Capitalized costs for proved properties include costs for oil and natural-gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified.

	September 30, 2012		September 30, 2011
Capitalized costs
Unproved properties	$	1,427,294		$	619,679
Proved properties		9,288,166			3,606,967
		10,715,460			4,226,646
Less: Accumulated DD&A		1,107,060			264,657
Net capitalized costs	$	9,608,400		$	3,961,989

Costs Not Being Amortized. The following table sets forth a summary of oil and gas property costs not being amortized at September 30, 2012, by the period in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The majority of the evaluation activities are expected to be completed within five years.

F-23

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

			Fiscal Year Ended			Fiscal Year Ended		Inception to
	Total		September 30, 2012			September 30, 2011		September 30, 2010
Property acquisition costs	$	327,962		$	-	$	151,417		$	176,545
Exploration and development		1,055,713			950,334		76,433			28,946
Capitalized interest		43,619			21,872		10,886			10,861
Total	$	1,427,294		$	972,206	$	238,736		$	216,352

Oil and Gas Reserve Information.    Nova Resources, Inc., an independent engineering firm, prepared the estimates of the proved reserves, future production, and income attributable to the leasehold interests as of September 30, 2012 and 2011. The estimated proved net recoverable reserves presented below include only those quantities that were expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under the then existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves estimated to be recovered through existing wells. Proved Undeveloped Reserves include those reserves that may be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure for recompletion or secondary recovery operations is required. All of the Company's Proved Reserves are located onshore in the continental United States of America.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise.

The following table sets forth estimates of the proved oil and gas reserves (net of royalty interests) for the Company and changes therein, for the periods indicated.

F-24

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Estimated Quantities of Proved Reserves

	Oil
	(Bbls)
September 30, 2010		164,950
Revisions of prior estimates		34,803
Purchases of reserves in place		362,790
Production		(26,733	)
September 30, 2011		535,810
Revisions of prior estimates		192,386
Purchases of reserves in place		46,557
Production		(48,889	)
September 30, 2012		725,864

	September 30, 2012		September 30, 2011
Estimated Quantities of Proved Developed Reserves		313,617		163,963
Estimated Quantities of Proved Undeveloped Reserves		412,247		371,847

Standardized Measure of Discounted Future Net Cash Flows.    The Standardized Measure related to proved oil and gas reserves is summarized below. Future cash inflows were computed by applying a twelve month average of the first day of the month prices to estimated future production, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expense. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows, less the tax basis of properties involved. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Company.

F-25

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Standardized Measure of Oil and Gas

	September 30, 2012			September 30, 2011			September 30, 2010
Future cash inflows	$	74,669,619		$	50,622,329		$	13,672,292
Future production costs		(9,364,444	)		(6,273,765	)		(1,611,534	)
Future development costs		(6,175,000	)		(5,557,500	)		(2,750,000	)
Future income taxes		(13,639,715	)		(10,992,652	)		(2,381,361	)
Future net cash flows		45,490,460			27,798,412			6,929,397
Discount of future net cash flows at 10% per annum		(8,509,198	)		(5,107,917	)		(2,381,915	)
Standardized measure of discounted future net cash flows	$	36,981,262		$	22,690,495		$	4,547,482

The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves for the periods indicated.

Changes in Standardized Measure

	Fiscal Year Ended September 30, 2012			Fiscal Year Ended September 30, 2011
Sales of oil and gas produced, net of production costs	$	(2,532,636	)	$	(1,608,365	)
Purchases of minerals in place		-			11,457,772
Net change due to revisions in quantity estimates		17,466,030			-
Net changes in prices and production costs		3,134,171			4,459,237
Accretion of discount before income taxes		2,269,050			454,748
Changes in timing and other		(6,045,848	)		3,379,621
Net change	$	14,290,767		$	18,143,013

F-26

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 13 – QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Fiscal Year Ended September 30, 2012
Revenues	$	745,171		$	862,505		$	851,899		$	909,832
Income (loss) from operations		187,773			91,222			(149,878	)		(5,255	)
Net income (loss)		17,380			254,367			(328,199	)		(970,705	)
Income (loss) per share – Basic and diluted (1)	$	0.00		$	0.02		$	(0.03	)	$	(0.09	)
Fiscal Year Ended September 30, 2011
Revenues	$	-		$	397,915		$	917,067		$	584,602
Income (loss) from operations		(144,183	)		(227,246	)		516,532			185,301
Net income (loss)		(172,399	)		(1,241,088	)		270,552			33,538
Income (loss) per share – Basic and diluted (1)	$	(0.03	)	$	(0.18	)	$	0.03		$	0.00

(1) The sum of the individual quarterly income (loss) per share amounts may not agree with year-to-date net income per common share as each quarterly computation is based on the weighted-average number of common shares outstanding during that period. Securities deemed anti-dilutive were excluded from each quarter in which the Company reported a net loss.

F-27

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the Registrant has caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized on the 27th day of December, 2012.

VANGUARD ENERGY CORPORATION
By:	/s/ Warren Dillard
	Warren Dillard, Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of l934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Warren M. Dillard	Principal Executive, Financial and Accounting Officer and Director	December 27, 2012
Warren M. Dillard
/s/ Gerald Bailey	Director	December 27, 2012
Gerald Bailey
/s/ Steven M. Powers	Director	December 27, 2012
Steven M. Powers

36

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

I, Warren Dillard, certify that:

1.  I have reviewed this annual report on Form 10-K of Vanguard Energy Corporation;

2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.  The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15 and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)     designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)     designed such internal control over financial reporting, or cause such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)     evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)     disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.  The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of the internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a)     all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)     any fraud, whether or not material, that involves management or other employees who have significant role in the registrant's internal control over financial reporting.

December 27, 2012	By:	/s/ Warren Dillard
		Warren Dillard
		Principal Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

I, Warren Dillard, certify that:

1. I have reviewed this annual report on Form 10-K of Vanguard Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15 and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)     designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)     designed such internal control over financial reporting, or cause such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)     evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)     disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of the internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a)     all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)     any fraud, whether or not material, that involves management or other employees who have significant role in the registrant's internal control over financial reporting.

December 27, 2012	By:	/s/ Warren Dillard
		Warren Dillard
		Principal Financial Officer

EX-32.1

EXHIBIT 32.1

In connection with the Annual Report of Vanguard Energy Corporation (the "Company") on Form 10-K for the period ending September 30, 2012 as filed with the Securities and Exchange Commission (the "Report"), Warren Dillard, the Company’s Principal Executive and Financial Officer, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1)           The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)           The information contained in the Report fairly presents, in all material respects, the financial condition and results of the Company.

December 27, 2012	By:	/s/ Warren Dillard
		Warren Dillard
		Principal Executive and Financial Officer

EX-99

EXHIBIT 99

N O V A  R E S O U R C E ,  I N C .

VANGUARD ENERGY CORPORATION

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

In

Hardin County, Texas

SEC Parameters

as of

September 30, 2012

c

\s\ Joseph V. Rochefort

Joseph V. Rochefort QRE

CPG # 3358; CGP # 90

QRE CT51-101

President

NOVA RESOURCE INCORPORATED

Texas Corporation 01605143-00

NOVA RESOURCE INCORPORATED PETROLEUM CONSULTANTS

P. O. Box 743324, Dallas, Texas 75374

Fax (972) 530-3930

Tel. (214) 543-6148

nobvapet@tx.rr.com

1

September 30, 2012

VANGUARD ENERGY CORPORATION

1330 Post Oak Blvd.

Suite 1600

Houston, Texas U.S.A. 77056

Gentlemen:

At the request of Vanguard Energy Corporation (Vanguard), Nova Resource, Inc.(Nova) has conducted it’s own independent and “Certified SEC Reserves Analysis and Valuation Study and Report” dated September 30, 2012 of the proven reserves of your oil and gas properties known as Vanguard’s New Batson Dome Field Properties located in Hardin County Texas using information and data that has been supplied to Nova by Vanguard and it’s operators, recently become available, and has been generated by Nova regarding the calculated economically recoverable oil and gas reserves as of September 30, 2012 and that are based upon and conform to the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party Certified SEC Reserves and Valuation Report dated September 30, 2012, and presented here, was prepared for public disclosure by Vanguard in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent Nova’s estimated net reserves attributable to the leasehold and royalty interests in certain properties as represented on September 30, 2012.  The report generated by Nova Resource Incorporated is Nova’s estimate of reserves of such properties located in Hardin County, Texas and otherwise known as the New Batson Dome Field Properties (the “Properties”).

The report and properties referred to herein and estimated by Nova Resource, Inc., assume Vanguard owns 90% working interest of the C.F.O. operated properties and 100% working interest of the Traton operated properties and, accordingly, account for the appropriate total net proved natural oil and gas hydrocarbon reserves of the Properties as of September 30, 2012.

Based upon Nova’s independent study of the properties Nova hereby certifies that the representations herein are Nova’s Certified SEC Reserves and Valuation Calculations as of September 30, 2012 and that these calculation conform to all present SEC requirements and regulations and definitions and may be used by Vanguard in any public disclosure.

Based upon our review, including the data, technical processes and interpretations, it is our opinion that the overall procedures and methodologies utilized by our staff in preparing their estimates of the proved reserves, future production and discounted future net income as of September 30, 2012 comply with the current SEC regulations and that the overall proved reserves, future production and discounted future net income for the  report and  properties as estimated by Nova are, in the aggregate, reasonable within SEC guidelines.

The estimated reserves and future net income amounts presented by Nova are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based upon the average prices during the trailing 12-month period prior to the ending date of the period covered in the report, determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements or price bonuses, as required by SEC regulations. The actual future prices may vary significantly from these prices and therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in the report. The net reserves as estimated by Nova attributable to the Properties as shown in this report are summarized as follows:

2

SEC PARAMETERS

Estimated Net Reserves

Certain Leasehold and Royalty Interests of

Vanguard Energy Corporation’s

Batson Dome Field Properties

of Hardin County, Texas

as of September 30, 2012

	Developed
	Producing		Non-Producing		Undeveloped			Total Proved
Net Reserves of Properties
Gas —MCF		0		0		0		0
Oil/Condensate—Bbls		231,859		81,758		412,247		725,864
Future Cash Inflows	$	23,851,355	$	8,410,387	$	42,407,877	$	74,669,619
Future Production  Costs	$	3,465,765	$	1,209,537	$	4,689,142	$	9,364,444
Future Development  Costs	$	0	$	325,000	$	5,850,000	$	6,175,000
SEC -10% ($)
PV-10% Value Oil	$	13,429,444	$	4,824,103	$	24,603,986	$	42,857,533

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (Barrels). All gas volumes are reported on as “as sold basis” expressed in thousands of cubic feet (MCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In the report all oil volumes are reported on an “as sold basis” expressed in Barrels at the official temperature and volume bases of the areas in which the oil reserves are located. All discounted future net income/present value data are expressed as U.S. dollars ($).

The estimates of reserves, future production and income attributable to properties in this report were prepared using economic software from the SPE ex-president’s Petroleum Economics Evaluation Software. Nova has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not considered material.

The future revenue/present value is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells aka Lease Operating Expenses (LOE), ad valorem taxes, recompletion costs and development costs. The future income present value is before the deduction of state and federal income taxes and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 90 % of the estimated revenue from proved reserves.

The discounted present value shown above is calculated using a discount rate of 10 percent per annum compounded annually.

The results shown above are presented for information  purposes only and should not be construed as the estimate of fair market value.

3

Reserves Included in The Report

In Nova’s opinion, the procedures and methodologies used by Nova’s staff  to determine the proved reserves conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to the report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in the report. The proved developed non-producing reserves included in this report consist of shut-in and behind pipe categories plus Proved Un-Developed are wells remaining to be drilled with reasonable certainty to by likely to produce similar volumes of reserves given the identical economic conditions that exist as of September 30, 2012.

No attempt was made to quantify or otherwise account for any accumulated imbalances that may exist. Gas volumes included herein do not attribute gas consumed in operations as reserves.

Reserves are those estimated remaining quantities of oil and gas and related substances that are anticipated to be economically producible, as of a given date, from known accumulations by application of defined conditions. All reserve estimates involve and assessment of the uncertainty relating to the likelihood that the actual remaining quantities recovered will be greater or less that the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of the data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Vanguard’s request, only proved reserves attributable to the properties were reviewed.

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. The proved reserves were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available, or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves are estimates only and should not be construed as being exact quantities, and if recovered, the revenues there from, and the actual costs related thereto, could be more or less than the estimated amounts.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with definitions set forth by the Securities and Exchange Commission Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves.

Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount or reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental method, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” This report referred only to estimates made by Nova Resource, Inc. The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are likely as not to be recovered.” The SEC states that “ possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

4

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to factors such as changes in economic conditions, results on future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted.

Vanguard’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The proved reserves for the properties as calculated and that were estimated by Nova were estimated by performance methods, the volumetric method, analogy, or a combination of methods utilizing the present economic conditions and limited to those proved reserves economically recoverable. The performance methods include, but may not be limited to, decline curve analysis that utilized extrapolations of historical production and pressure data available through September 30, 2012, in those cases where such data were considered to be definitive. The data utilized in the analysis were furnished to Nova’s staff using commercial and private sources and were considered sufficient for the purpose.

Ninety percent of the proved developed non-producing and the un-developed reserves were estimated primarily by the performance and historical extrapolation methods. The data utilized were considered sufficient for the purpose.

As stated previously, proved reserves must be anticipated to be producible from a given data forward based upon existing economic conditions including prices and costs at which producibility from a reservoir is to be determined. Nova has reviewed certain primary economic data utilized by Vanguard’s operator and other operators in the area from identical reservoirs relating to hydrocarbon prices and costs.

Hydrocarbon Prices

The hydrocarbon prices and costs determined for the properties are based upon SEC required trailing twelve month  unweighted  arithmetic averages of prices in effect for the first of each month, unless prices were defined by contractual arrangements and cost based upon existing sales costs. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used by Nova until expiration of the contract.  Vanguard supplied prices and these were confirmed using  public private data sources.  Vanguard supplied, as of August 31, 2012,  the differential bonus of $ 4.75 per barrel of crude sold.  All Vanguard supplied data is assumed valid with or without confirmation auditing.

The product prices which were actually used by Nova to determine the future gross revenue for each property reflect any known adjustments to the prices for gravity, quality, local conditions, gathering and transportation fees, and/or distance from market, referred to as the “differentials.”

In addition, the table below summarizes the volume weighted benchmark TTM prices adjusted for differentials and referred to herein as the “TTM prices.” The data shown is presented in accordance with SEC disclosure requirements.

Geographic Area	Product	TTM Average
Texas Gulf Coast	Oil	$ 98.12 / Bbl + $ 4.75 regn Bonus = $ 102.87
Texas Gulf Coast	Gas	4  3.42/Mcf

The effect of derivative instruments designated as price hedges of oil and gas quantities are not reflected in Nova’s individual property evaluations.

Operating costs furnished by Vanguard’s operators are based on the operating expense reports supplied by the operator and include only costs directly applicable to the leases or wells or operations thereof. The operating costs include a portion of general and administrative costs allocated directly to the lease and wells. The operating costs furnished were accepted as factual data and determined to be reasonable; however, we have not conducted an independent verification of the data supplied by the operators. No deductions were made for loan repayments, interests expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs furnished by the operators are based upon authorizations by Vanguard for expenditures for the proposed work or actual costs for similar projects. The development costs furnished by Vanguard were accepted as factual and reasonable; however, we have not conducted and an independent verification of the data supplied by Vanguard nor have we made any field examination of the properties. Vanguard’s estimates of zero abandonment costs after salvage value for the onshore properties were accepted without independent verification. Nova has estimated that abandonment costs should match the salvage value and therefore should equal zero after salvage; however, Nova makes no warranty for this or for Vanguard’s estimation of abandonment estimates.

5

No consideration was given in this report to potential environmental liabilities that may exist nor were costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

The proved developed non-producing and undeveloped reserves for the properties estimated by Nova have been incorporated herein in accordance with Vanguard’s plans to develop these reserves as of September 30, 2012. The implementation of Vanguard’s development plans as presented to Nova is subject to the approval process adopted by Vanguard’s management and funding sources. As a result of Novs’s inquires during the course of our review of Vanguard’s plans, Vanguard has informed Nova that the development activities for the properties reviewed have been subjected to and received the internal approvals required by Vanguard management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreements (JOA) requirements or other administrative approvals external to Vanguard. Additionally, Vanguard has informed Nova that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans to develop the properties.

The costs and parameters used were held constant throughout the life of the properties.

To estimate economically recoverable proved oil and gas reserves and related future net cash flow and present values, Nova considers many factors and assumptions including, but not limited to, the use of reservoir and reserve and production parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecast of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Nova’s forecasts for future production rates are based on historical performance from wells currently on production in the region.  No further reserves or valuation were given to any wells beyond their projected  production  limit except for a two percent salvage value for equipment. Where no production decline trends have been established by Nova due to the limited historical production records from wells on the properties, surrounding wells historical production records have been used and extrapolated to wells of the property. Where applicable the  present decline rate of any well used was determine by calculated field wide production volumes and decline curves determined  to be equal to field wide economically recoverable reserves . The calculated field wide rate of decline to equal the field wide calculated present economically recoverable reserves was then applied by Nova to determine the present economic life of the production from the reservoir.

Test data and other related information were used by Nova to estimate the anticipated initial production rates from those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Vanguard. Wells or locations that are not currently producing may or may not start producing earlier or later than anticipated by Vanguard and thus estimates due to unforeseen factors causing such changes may occur. Such factors may include further interpretation, delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently producing, or production from wells from locations that are not currently producing, may be more or less that estimated because of changes including, but not limited to, reservoir performance, operating conditions, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables, prices, or other constraints which may be set by regulatory bodies.

               Vanguard’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax which may be subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves and amounts of income to differ significantly from the estimated quantities.

The estimates of proved reserves were based upon Nova’s study of the properties and data supplied by Vanguard and it’s operators related to interests owned by Vanguard; however, Nova has not made any field examination of the properties. No consideration was given to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past or projected operating practices.

Certain technical personnel of Nova are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with Nova’s technical personnel and had access to their work papers and supporting data.

Vanguard has informed Nova that they have furnished  Nova all of the material accounts, records, geological and engineering data, reports and other data in their possession. In performing our forecast of the estimated future proved reserves, production and income, Nova has relied upon the data furnished to by Vanguard and it’s operators with respect to property interests owned by Vanguard, production and well tests from examined wells, reported direct costs of operating the wells or leases, other costs including ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based upon SEC requirements, geological and engineering data. Nova reviewed such data for its reasonableness; however, Nova has not conducted an independent verification of Vanguard’s supplied data. In summary, Nova considers the assumptions, data, methods and analytical procedures used by our firm and reviewed by us appropriate for the purpose hereof, and Nova has used all such methods and procedures that Nova considers necessary and appropriate under the circumstances to render the conclusions as stated. Nova considers the factual data used in this report appropriate and sufficient for the purpose of preparing the estimation of reserves and future net revenue herein.

6

Future Production Rates

For wells currently on production, Nova’s forecasts of future production rates are based on historical performance data. Adjustments for the effects of curtailment where appropriate, were used until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to economic depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Offset analogies and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence on an anticipated date furnished by the operators. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Nova’s estimates due to unforeseen factors causing a change in the timing of initial production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completions and/or recompletion of wells and/or constraints set by regulatory bodies.

The future production rates from wells currently in production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities or subsurface conditions, compression and artificial lift, pipeline capacity and/or transportation capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Audit Opinion

Based on Nova’s study, including data, technical processes and methodologies presented by Vanguard and it’s operators, it is Nova’s opinion that the overall procedures and mythologies utilized by Nova in preparing their estimates of the proved reserves, future production and discounted future net income as of September 30, 2012  comply with current SEC regulations and that the overall proved reserves, future production and discounted future net income for the reviewed properties as estimated are, in the aggregate, reasonable within established audit guidelines.

Standards of Independence and Professional Qualifications

Nova is an independent certified petroleum geological, geophysical and professional petroleum engineering consulting firm that has been providing petroleum-consulting services throughout the world for over thirty years. Nova is an employee-owned incorporated firm and maintains offices in Dallas, Texas U.S.A. We have numerous petroleum engineers and  certified petroleum geologists and geophysicists and certified licenses operator personnel as members of our staff on our permanent basis as well as many outside staff. By virtue of our size and scope of worldwide activity and services and the large number of clients for which we provide services, no single client or job represents a material portion of Nova’s annual revenue. Neither Nova nor its employees nor staff serve as officers or directors of any client’s publicly traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. Neither Nova nor it’s staff  own any  interests in any of our client’s properties. This allows Nova to bring the highest level of independence and objectivity to each engagement for our services.

Nova actively participates in industry-related professional societies and organizations and has been performing reserves evaluations according to SEC regulation for over twenty-five years for both major oil and gas corporations as well as mid-size and small independent oil and gas companies worldwide. Many of our staff have authored or co-authored technical papers and reports on the subject of reserves related topics.

Nova staff engineers, geologists, geophysicists and operating personnel are required to receive the appropriate professional accreditation in the form of registered or certified professional engineer’s license or a registered or certified professional geoscientist’s credentials from an appropriate governmental authority or from the recognized self-regulating professional organization or regulatory operating body.

Nova is independent with respect to Vanguard. Neither Nova nor any of our employees have any interest in the subject properties, and neither the employment to do these services nor the compensation is contingent upon Nova’s reviews or estimates of reserves for any properties.

The results of our evaluation and valuation, presented herein, are based on technical reviews and analysis by teams of geoscientists and engineers from Nova. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.

7

Terms of Usage

The results of our third party reserves analysis and valuation study, the report, presented in report summary form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Vanguard.

We have provided Vanguard with a digital version of the original signed copy of this certified SEC reserves analysis and valuation report summary letter. In the event there are any differences between the digital version included in filings made by Vanguard and the original signed letter, the original signed letter shall control and supercede the digital version.

The data and work papers used in the preparation, study, analysis and valuation report are available for examination by authorized parties in Nova’s public offices. Please contact Nova if we can be of further service.

Respectfully,

Nova Resource, Inc.

\s\ Joseph V. Rochefort

CPG # 3358, CGP, # 90,

QRE CT51-101; SIPES # 1901

8

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by a team of geoscientists and engineers from Nova Resource, Inc. Joseph V. Rochefort was the primary technical person responsible for overseeing the review of the estimate of reserves, future production and income.

Mr. Rochefort, the president of Nova Resource, Inc. (Nova) is responsible for coordinating and supervising staff and consultants of the company in ongoing reservoir evaluation studies worldwide. Before forming Nova, Mr. Rochefort served in a number of technical and managerial positions with Exxon, Sun, Arco, and Mobil, now ExxonMobil. Mr. Rochefort’s resume is available for review.

Mr. Rochefort graduated from both Texas Christian University and from Texas Tech University with BS degrees in geology and physics and Masters degrees in geology. Mr. Rochefort achieved his over thirty years of expertise in technical and managerial responsibilities in oil and gas reserves and reservoirs evaluation and has attained Certification as a Professional Petroleum Geologist # 3358, a Professional Petroleum Geophysicist # 90, and as a Qualified Reserves Evaluator under authority of CT51-101 and is Independent as shown by membership in SIPES with registration number # 1901. Mr. Rochefort has been designated an expert witness regarding oil and gas reserves evaluation in several judicial cases. Mr. Rochefort has written several internal guidelines regarding oil and gas reserves evaluations and has co-authored several technical articles and one book regarding hydrocarbon accumulations. Mr. Rochefort maintains his expertise in oil and gas reserves analysis by attending continuing education courses of at least 16 hours per year. Mr. Rochefort has created an internally generated course for staff pertaining to the formalized training related to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Rochefort has attended several training classes during 2009, 2010 , 2011 and 2012 covering such topics as reservoir engineering, geoscience and petroleum economics evaluation methods, procedures, software and ethics to maintain his expertise as a Qualified Reserves Evaluator. Mr. Rochefort has been recognized by the SEC as a Qualified Reserves Evaluator for over 15 years.

Based upon his educational background, professional training and more than 30 years of experience in the estimation and evaluation and generation of reserves evaluation analyses of petroleum reserves, Mr. Rochefort has attained the professional qualifications and expertise as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers and as a Qualified Reserves Evaluator under authority of CT51-101.

9

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting: Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting: Final Rule” includes revisions and additions to the definition section of Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for complete definitions (direct passages excerpts in part or wholly from the aforementioned SEC document are incorporated herein in italics).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in 229.1202 Instruction to item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical and/or biological methods, and the use of miscible and immiscible displacement fluids as well as other methods.

               Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as to be either conventional orunconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coal seam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

              Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

The Securities and Exchange Commission Regulation S-X 210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. IN addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs Isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from known accumulation by a non-productive reservoir (ie., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (ie., potentially recoverable resources from undiscovered accumulations).

10

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X 210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)      The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B)   Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil and gas on the basis of available geoscience and engineering data.

(ii)   In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)   Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(iv)   Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

11

RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (sec)

And

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and SPE PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulations S-X 210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time or the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operations.

Developed Non-Producing (PDNP)

Developed Non-Producing reserves include shut-in and behind-pipe reserves.

12

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X 210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category 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.

(i)   reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii)   Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii)   Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery techniques is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

13

XML

8. STOCK-BASED COMPENSATION (Details)	12 Months Ended
	Sep. 30, 2012
Stock-Based Compensation Details
Risk-free interest rate	0.99%
Expected dividend rate	0.00%
Expected volatility	40.80%
Expected life (years)	3 years
Calculated value of options granted	0.29

XML

5. LONG-TERM DEBT (Details Narrative) (USD $)	3 Months Ended	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2012	Sep. 30, 2011
Long-Term Debt Details Narrative
Warrants exercised	453,322	453,322
2010 and 2012 Convertible Promissory Notes	$ 3,075,000	$ 3,075,000
Unamortized discount on notes	713,332	713,332
Interest expense of debt issuance costs and discount	965,748	485,910
Combinded effective interest rate	26.50%	26.50%
Participation Liability Fair Value	1,573,605	1,573,605	1,172,315
Net profits interest granted expenses	97,535	108,503
Payments under participation arrangement	$ 375,470	$ 329,006

XML

12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details 4)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Supplemental Information Relating To Oil And Gas Producing Activities Details 4
Beginning, Reserves	535,810	164,950
Revisions of prior estimatess	192,386	34,803
Purchases of reserves in place	46,557	362,790
Production	(48,889)	(26,733)
Ending, Reserves	725,864	535,810

XML

6. INCOME TAXES (Details Narrative) (USD $)	Sep. 30, 2012
Income Taxes Details Narrative
Accumulated net operating losses	$ 8,900,000

XML

12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details 2) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Capitalized costs
Unproved properties	$ 1,427,294	$ 619,679
Proved properties	9,288,166	3,606,967
Gross capitalized costs	10,715,460	4,226,646
Less: Accumulated DD&A	1,107,060	264,657
Net capitalized costs	$ 9,608,400	$ 3,961,989

XML

4. ASSET RETIREMENT OBLIGATIONS (Details)	Sep. 30, 2012	Sep. 30, 2011
Asset Retirement Obligations Details
Inflation rate	4.00%	4.00%
Estimated asset life	9 years 6 months	9 years 6 months
Credit adjusted risk free interest rate	18.00%	18.00%

XML

9. COMMITMENTS AND CONTINGENCIES (Details Narrative) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Commitments And Contingencies Details Narrative
Rent expense	$ 81,641	$ 47,076

XML

8. STOCK-BASED COMPENSATION (Tables)

12 Months Ended

Sep. 30, 2012

Stockholders' equity

SCHEDULE OF STOCK OPTIONS GRANTS

Risk-free interest rate		0.99	%
Expected dividend rate		0.00	%
Expected volatility		40.80	%
Expected life (years)		3
Calculated value of options granted	$	0.29

XML

12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details 6) (USD $)	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Supplemental Information Relating To Oil And Gas Producing Activities Details 6
Future cash inflows	$ 74,669,619	$ 50,622,329	$ 13,672,292
Future production costs	(9,364,444)	(6,273,765)	(1,611,534)
Future development costs	(6,175,000)	(5,557,500)	(2,750,000)
Future income taxes	(13,639,715)	(10,992,652)	(2,381,361)
Future net cash flows	45,490,460	27,798,412	6,929,397
Discount of future net cash flows at 10% per annum	(8,509,198)	(5,107,917)	(2,381,915)
Standardized measure of discounted future net cash flows	$ 36,981,262	$ 22,690,495	$ 4,547,482

XML

10. FAIR VALUE OF FINANCIAL INSTRUMENTS (Details 1) (USD $)	Sep. 30, 2012
Balance at September 30, 2011	$ 2,293,227
Purchases, issuances and settlements	263,921
(Gains) losses included in earnings	(330,779)
Balance at September 30, 2012	2,226,369
Participation Liability
Balance at September 30, 2011	1,172,315
Purchases, issuances and settlements	(349,302)
(Gains) losses included in earnings	750,592
Balance at September 30, 2012	1,573,605
Conversion Feature Liablility
Balance at September 30, 2011	720,593
Purchases, issuances and settlements	613,223
(Gains) losses included in earnings	(749,798)
Balance at September 30, 2012	584,018
Warrant Liabilities
Balance at September 30, 2011	400,319
Purchases, issuances and settlements	0
(Gains) losses included in earnings	(331,573)
Balance at September 30, 2012	$ 68,746

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6. INCOME TAXES (Details 2) (USD $)	Sep. 30, 2012	Sep. 30, 2011
Deferred tax assets
Net operating loss carryforwards	$ 2,987,160	$ 824,260
Stock-based compensation	103,367	82,869
Other
Deferred tax liability - oil & gas properties	(2,319,346)	(749,431)
Participation liability	102,739
Net deferred tax assets before valuation allowance	873,920	157,698
Valuation allowance	(873,920)	(157,698)
Net deferred tax asset

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13. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Details) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Net income (loss)	$ (1,027,157)	$ (1,109,397)
First Quarter
Revenues	745,171
Income (loss) from operations	187,773	(144,183)
Net income (loss)	17,380	(172,399)
Income (loss) per share - Basic and diluted (1)	$ 0.00	$ (0.03)
Second Quarter
Revenues	862,505	397,915
Income (loss) from operations	91,222	(227,246)
Net income (loss)	254,367	(1,241,088)
Income (loss) per share - Basic and diluted (1)	$ 0.02	$ (0.18)
Third Quarter
Revenues	851,899	917,067
Income (loss) from operations	(149,878)	516,532
Net income (loss)	(328,199)	270,552
Income (loss) per share - Basic and diluted (1)	$ (0.03)	$ 0.03
Fourth Quarter
Revenues	909,832	584,602
Income (loss) from operations	(5,255)	185,301
Net income (loss)	$ (970,705)	$ 33,538
Income (loss) per share - Basic and diluted (1)	$ (0.09)	$ 0.00

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12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details 3) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Supplemental Information Relating To Oil And Gas Producing Activities Details 3
Property acquisition costs		$ 151,417
Exploration and development	950,334	76,433
Capitalized interest	21,872	10,886
Total	$ 972,206	$ 238,735

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3. ACQUISITIONS

12 Months Ended

Sep. 30, 2012

Notes to Financial Statements

3. ACQUISITIONS

By agreement dated March 15, 2011, the Company entered into a farmout agreement with an unrelated third party pertaining to a 100-acre lease in the Batson Dome Field. As of September 30, 2012, the Company had drilled three wells on the lease. Pursuant to the farmout agreement the Company has the option of drilling additional wells on the lease; provided however, that if it does not drill at least six wells in any twelve month period the right to drill any additional wells on the lease will terminate. The estimated cost of drilling and completing any well on this lease is approximately $500,000.As of September 30, 2012, the Company had drilled three wells on this lease.

By agreement dated May 25, 2011, the Company entered into a farmout agreement with an unrelated third party pertaining to a 100-acre lease in the Batson Dome Field. Pursuant to the agreement, the Company had the obligation to commence drilling a well on the lease by June 14, 2012. In June 2012, the Company paid $10,000 to extend the agreement, whereby it now has an obligation to commence drilling by June 14, 2013. Subject to the commencement of drilling the first well by June 14, 2013, and completing the well if warranted, the Company has the option of drilling additional wells on the lease; provided however, that unless the Company commences drilling each well within 180 days of the date the latest well is completed or abandoned, the right to drill any additional wells on the lease will terminate. The estimated cost of drilling and completing any well on this lease is approximately $1,000,000.  As of September 30, 2012, the Company had not commenced any drilling operations on the lease subject to the farmout agreement.

By agreement dated January 6, 2012, the Company entered into a three-year farmout agreement with an unrelated third party pertaining to another 70-acre lease in the Batson Dome Field. The estimated cost of drilling and completing any well on this lease is approximately $1,000,000.

By agreement dated May 1, 2012, the Company entered into a farmout agreement with an unrelated third party pertaining to  a 45-acre lease in the Hull-Daisetta Field. Pursuant to the agreement, the Company has the obligation to commence drilling a well on the lease by January 31, 2013. Subject to the commencement of drilling the first well by January 31, 2013, and completing the well if warranted, the Company has the option of drilling additional wells on the lease; provided however, that unless the Company commences drilling each well within 180 days of the date the latest well is completed or abandoned, the right to drill any additional wells on the lease will terminate. The estimated cost of drilling and completing any well on this lease is approximately $750,000.  As of September 30, 2012, the Company had not drilled any wells on this lease.

On September 30, 2010, the Company acquired a forty percent (40%) working interest in mineral leases for 220 acres in Hardin County, Texas, within the area known as the Batson Dome Field, from C.F.O., Inc., a corporation controlled by Delton Drum, one of the Company’s officers, for the total consideration of $325,668, consisting of a cash payment of $40,000 and a secured 90-day promissory note for $285,668.  On October 1, 2010, the Company acquired an additional fifty percent (50%) working interest in the Batson Dome Field for the total consideration of $407,085, consisting of a cash payment of $50,000 and a secured 90-day promissory note for $357,085.  The 90-day promissory notes bore interest at eight percent (8%) per annum and were repaid in December 2010.  Although the leases are in a previously developed oil and gas field, these purchases excluded any interest in existing well bores or surface equipment.

On December 16, 2010, and in payment of $259,247 in cash, the Company acquired a ninety percent (90%) working  interest in 10 acres adjacent to its existing 220 acres under lease in the Batson Dome Field, as well as a ninety percent (90%) working interest in two producing oil wells and three shut in wells located on the 10 acre lease. The leases and wells were acquired from C.F.O., Inc.  This purchase was accounted for under the acquisition method of accounting and, as such, the assets and liabilities of the acquired properties are recognized at their estimated fair values as of the date of the acquisition.  The estimated fair value of these properties approximates the consideration paid, which the Company concluded approximates the fair value that would be paid by a typical market participant. Acquisition-related costs of approximately $15,000 were expensed. The purchase price for the acquisition was allocated as follows:

Consideration paid -- cash	$	259,247
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed and undeveloped properties		274,463
Asset retirement obligations		(15,216	)
Total identifiable net assets	$	259,247

The unaudited financial information in the table below summarizes the combined results of the Company's operations and the properties acquired, on a pro forma basis, as though the purchase had taken place at the October 1, 2010. The pro forma information is based on the Company's results of operations for 2012 and 2011 on historical results of the properties acquired, and on estimates of the effect of the transactions to the combined results. Because the acquisitions occurred in prior periods, the 2012 pro forma amounts are the same as the actual amounts. The pro forma information is not necessarily indicative of results that actually would have occurred had the transaction been in effect for the periods indicated, or of results that may occur in the future.

	Fiscal Year						Fiscal Year
	Ended						Ended
	September 30, 2012						September 30, 2011
	Actual			Proforma			Actual			Proforma
Revenues	$	3,369,407		$	3,369,407		$	1,899,584		$	1,906,804
Net loss		(1,027,157	)		(1,027,157	)		(1,109,397	)		(1,107,798	)
Loss per share – Basic and diluted		(0.09	)		(0.09	)		(0.15	)		(0.15	)

Through these acquisitions, the Company owns a ninety percent (90%) working interest in mineral leases for 230 acres in the Batson Dome Field. C.F.O., Inc. is a related party and owns the remaining ten percent (10%) working interest and is the operator for the mineral leases pursuant to a joint operating agreement between the Company and C.F.O., Inc.  The Company has recorded a receivable from CFO, Inc. for their 10% share of capital expenditures.  At September 30, 2012, this amount totaled $238,940 and is expected to be repaid within the next twelve months from CFO, Inc.’s share of production or from other sources.

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11. SUPPLEMENTAL CASH FLOW INFORMATION (Details) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Supplemental Cash Flow Information Details
Interest paid	$ 250,734	$ 242,702
Interest capitalized (non-cash)	350,142	225,529
Exchange of 2010 Notes for 2012 Notes	3,075,000
Noncash investing and financing activities:
Capital expenditures included in accounts payable	289,133	84,365
Issuance of notes payable for oil and gas properties		357,085
Warrant liability settled on exercise		136,015
Recognition of liabilities for issuance of:
Series A warrants		1,188
Series B warrants		143,948
Series C warrants		274,516
Series D warrants		49,385
Issuance of Series E Warrants to placement agent	97,583
Recognition of conversion feature liability	670,893	26,771
Recognition of participation liability		737,886
Asset retirement obligations incurred	$ 86,386	$ 4,588

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12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables)

12 Months Ended

Sep. 30, 2012

Supplemental Information Relating To Oil And Gas Producing Activities Tables

Schedule of operations

	Fiscal Year Ended September 30, 2012		Fiscal Year Ended September 30, 2011
Net revenues from production
Third-party sales	$	3,369,407	$	1,899,584
Production costs
Lease operating expense		672,233		200,742
Production taxes		155,616		87,217
Asset retirement obligation accretion		8,922		3,260
		836,771		291,219
Depreciation, depletion and amortization		842,571		264,489
		1,690,065		1,343,876
Income tax expense		573,270		455,843
Results of operations from producing activities	$	1,116,795	$	888,033

Schedule of development costs

	Fiscal Year Ended September 30, 2012		Fiscal Year Ended September 30, 2011
Property acquisitions
Unproved	$	59,784		$	407,085
Proved		-			259,247
Exploration		170,857			108,587
Development		6,258,174			3,084,194
Total Costs Incurred	$	6,488,815		$	3,859,113

Schedule of capitalized costs

	September 30, 2012		September 30, 2011
Capitalized costs
Unproved properties	$	1,427,294		$	619,679
Proved properties		9,288,166			3,606,967
		10,715,460			4,226,646
Less: Accumulated DD&A		1,107,060			264,657
Net capitalized costs	$	9,608,400		$	3,961,989

Schedule of costs not being amortized

			Fiscal Year Ended			Fiscal Year Ended		Inception to
	Total		September 30, 2012			September 30, 2011		September 30, 2010
Property acquisition costs	$	327,962		$	-	$	151,417		$	176,545
Exploration and development		1,055,712			950,334		76,433			28,946
Capitalized interest		43,620			21,872		10,886			10,861
Total	$	1,427,294		$	972,206	$	238,735		$	216,353

Schedule of proved oil and gas reserves

	Oil
	(Bbls)
September 30, 2010		164,950
Revisions of prior estimates		34,803
Purchases of reserves in place		362,790
Production		(26,733	)
September 30, 2011		535,810
Revisions of prior estimates		192,386
Purchases of reserves in place		46,557
Production		(48,889	)
September 30, 2012		725,864

	September 30, 2012		September 30, 2011
Estimated Quantities of Proved Developed Reserves		313,617		163,963
Estimated Quantities of Proved Undeveloped Reserves		412,247		371,847

Schedule of standardized measure of discounted future net cash flows

Standardized Measure of Oil and Gas

	September 30, 2012			September 30, 2011			September 30, 2010
Future cash inflows	$	74,669,619		$	50,622,329		$	13,672,292
Future production costs		(9,364,444	)		(6,273,765	)		(1,611,534	)
Future development costs		(6,175,000	)		(5,557,500	)		(2,750,000	)
Future income taxes		(13,639,715	)		(10,992,652	)		(2,381,361	)
Future net cash flows		45,490,460			27,798,412			6,929,397
Discount of future net cash flows at 10% per annum		(8,509,198	)		(5,107,917	)		(2,381,915	)
Standardized measure of discounted future net cash flows	$	36,981,262		$	22,690,495		$	4,547,482

The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves for the periods indicated.

Changes in Standardized Measure

	Fiscal Year Ended September 30, 2012			Fiscal Year Ended September 30, 2012
Sales of oil and gas produced, net of production costs	$	(2,532,636	)	$	(1,608,365	)
Purchases of minerals in place		-			11,457,772
Net change due to revisions in quantity estimates		17,466,030			-
Net changes in prices and production costs		3,134,171			4,459,237
Accretion of discount before income taxes		2,269,050			454,748
Changes in timing and other		(6,045,848	)		3,379,621
Net change	$	14,290,767		$	18,143,013

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11. SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

12 Months Ended

Sep. 30, 2012

Notes to Financial Statements

Supplemental Cash Flow Information

	Fiscal Year Ended		Fiscal Year Ended
	September 30, 2012		September 30, 2011
Interest paid	$	250,734	$	242,702
Interest capitalized (non-cash)		350,142		225,529
Exchange of 2010 Notes for 2012 Notes		3,075,000		-
Noncash investing and financing activities:
Capital expenditures included in accounts payable		289,133		84,365
Issuance of notes payable for oil and gas properties		-		357,085
Warrant liability settled on exercise		-		136,015
Recognition of liabilities for issuance of:
Series A warrants		-		1,188
Series B warrants		-		143,948
Series C warrants		-		274,516
Series D warrants		-		49,385
Issuance of Series E Warrants to placement agent		97,583		-
Recognition of conversion feature liability		670,893		26,771
Recognition of participation liability		-		737,886
Asset retirement obligations incurred		86,386		4,588

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7. STOCKHOLDERS EQUITY (Details Narrative) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Stockholders Equity Details Narrative
Issuance of restricted stock for investor relations consulting services	60,690	15,000
Stock issuance expense	$ 59,700	$ 15,000

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12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Supplemental Information Relating To Oil And Gas Producing Activities Details
Third-party sales	$ 3,369,407	$ 1,899,584
Production costs
Lease operating expense	672,233	200,742
Production taxes	155,616	87,217
Asset retirement obligation accretion	8,922	3,260
Subtotal production costs	836,771	291,219
Depreciation, depletion and amortization	842,571	264,489
Total production costs	1,690,065	1,343,876
Income tax expense	573,270	455,843
Results of operations from producing activities	$ 1,116,795	$ 888,033

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13. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Tables)

12 Months Ended

Sep. 30, 2012

Quarterly Financial Information Tables

Schedule of quarterly financial information

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Fiscal Year Ended September 30, 2012
Revenues	$	745,171		$	862,505		$	851,899		$	909,832
Income (loss) from operations		187,773			91,222			(149,878	)		(5,255	)
Net income (loss)		17,380			254,367			(328,199	)		(970,705	)
Income (loss) per share – Basic and diluted (1)	$	0.00		$	0.02		$	(0.03	)	$	(0.09	)
Fiscal Year Ended September 30, 2011
Revenues	$	-		$	397,915		$	917,067		$	584,602
Income (loss) from operations		(144,183	)		(227,246	)		516,532			185,301
Net income (loss)		(172,399	)		(1,241,088	)		270,552			33,538
Income (loss) per share – Basic and diluted (1)	$	(0.03	)	$	(0.18	)	$	0.03		$	0.00

(1) The sum of the individual quarterly income (loss) per share amounts may not agree with year-to-date net income per common share as each quarterly computation is based on the weighted-average number of common shares outstanding during that period. Securities deemed anti-dilutive were excluded from each quarter in which the Company reported a net loss.

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3. ACQUISITIONS (Details) (USD $)	Sep. 30, 2012
Acquisitions Details
Consideration paid -- cash	$ 259,247
Proved developed and undeveloped properties	274,463
Asset retirement obligations	(15,216)
Total identifiable net assets	$ 259,247

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2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Sep. 30, 2012

Notes to Financial Statements

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Basis of Presentation— The consolidated financial statements include the accounts of Vanguard Energy Corporation and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

The Company's fiscal year-end is September 30. The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") and pursuant to the accounting and disclosure rules and regulations of the U.S. Securities and Exchange Commission ("SEC"). A summary of the significant accounting policies applied in the preparation of the accompanying financial statements follows.

Management Estimates—The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the fair value of acquired assets and liabilities (Note 3), asset retirement obligations (Note 4), participation, conversion feature and warrant liabilities (Note 5), income taxes (Note 6) and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (Note 12).

Cash and Cash Equivalents—The Company considers all highly liquid instruments purchased with a maturity date of three months or less to be cash equivalents.

Oil and Gas Properties—The Company follows the full cost accounting method to account for oil and natural gas properties, whereby costs incurred in the acquisition, exploration and development of oil and gas reserves are capitalized. Such costs include lease acquisition, geological and geophysical activities, rentals on nonproducing leases, drilling, completing and equipping of oil and gas wells and administrative costs directly attributable to those activities and asset retirement costs. Disposition of oil and gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such adjustment would significantly alter the relationship between capital costs and proved reserves of oil and gas, in which case the gain or loss is recognized to  operations.

The capitalized costs of oil and gas properties, excluding unevaluated and unproved properties, are amortized as depreciation, depletion and amortization expense using the units-of-production method based on estimated proved recoverable oil and gas reserves.

The costs associated with unevaluated and unproved properties, initially excluded from the amortization base, relate to unproved leasehold acreage, wells and production facilities in progress and wells pending determination of the existence of proved reserves, together with capitalized interest costs for these projects. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well once a determination of the existence of proved reserves has been made or upon impairment of a lease. Costs associated with wells in progress and completed wells that have yet to be evaluated are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry wells are transferred to the amortization base immediately upon determination that the well is unsuccessful.

All items classified as unproved property are assessed on a quarterly basis for possible impairment or reduction in value. Properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization.

Under full cost accounting rules for each cost center, capitalized costs of evaluated oil and gas properties, including asset retirement costs, less accumulated amortization and related deferred income taxes, may not exceed an amount (the "cost ceiling") equal to the sum of (a) the present value of future net cash flows from estimated production of proved oil and gas reserves, based on current prices and operating conditions, discounted at ten percent (10%), plus (b) the cost of properties not being amortized, plus (c) the lower of cost or estimated fair value of any unproved properties included in the costs being amortized, less (d) any income tax effects related to differences between the book and tax basis of the properties involved. If capitalized costs exceed this limit, the excess is charged to  operations.  For purposes of the ceiling test calculation, current prices are defined as the unweighted arithmetic average of the first day of the month price for each month within the 12 month period prior to the end of the reporting period.  Prices are adjusted for basis or location differentials.  Unless sales contracts specify otherwise, prices are held constant for the productive life of each well.  Similarly, current costs are assumed to remain constant over the entire calculation period.

Given the volatility of oil and gas prices, it is reasonably possible that the estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline in the future, even if only for a short period of time, it is possible that impairments of oil and gas properties could occur. In addition, it is reasonably possible that impairments could occur if costs are incurred in excess of any increases in the present value of future net cash flows from proved oil and gas reserves, or if properties are sold for proceeds less than the discounted present value of the related proved oil and gas reserves.

Revenue Recognition—Oil and gas sales result from undivided interests held by the Company in oil and gas properties. Sales of oil and gas produced from oil and gas operations are recognized when the product is delivered to the purchaser and title transfers to the purchaser. The Company had no natural gas sales imbalance positions at September 30, 2012 or 2011. Charges for gathering and transportation are included in production expenses.

Asset Retirement Obligations—The Company records a liability for asset retirement obligations ("ARO") associated with its oil and gas wells when those assets are placed in service. The corresponding cost is capitalized as an asset and included in the carrying amount of oil and gas properties and is depleted over the useful life of the properties. Subsequently, the ARO liability is accreted to its then-present value.

Inherent in the fair value calculation of an ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Settlements greater than or less than amounts accrued as ARO are recorded as a gain or loss upon settlement.

Capitalized Interest—Interest is capitalized as part of the historical cost of developing and constructing assets for significant projects. Significant oil and gas investments in unproved properties, significant exploration and development projects for which depreciation, depletion and amortization expense is not currently recognized, and exploration or development activities that are in progress qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depletion or impairment, along with other capitalized costs related to that asset.

Debt Issuance Costs—Costs incurred in connection with the issuance of long-term debt are capitalized and amortized over the term of the related debt.

Participation Liability—The participation liability associated with outstanding long-term debt is recorded at fair value as determined utilizing a present value factor of 10 applied to proved developed reserves. Payments made for the participation liability are reported as interest expense. Changes in the fair value of the participation liability are recorded as additions or deductions to the discount on the long-term debt to the extent this debt remains outstanding.  Once the associated debt is repaid, changes in the participation liability are recorded to other expense in the statements of operations.

Conversion Feature Liability and Warrant Liabilities—The conversion feature liability and warrant liabilities are recorded at fair value based upon valuation models utilizing relevant factors such as expected life, estimated volatility, risk-free interest and expected dividend rate. Changes in the fair value of these liabilities are reported in the statements of operations.

Stock-Based Compensation—The Company accounts for employee stock-based compensation using the fair value method. The fair value attributable to stock options is calculated based on the Black-Scholes option pricing model and is amortized to expense over the service period which is equivalent to the time required to vest the stock options.

Income Taxes—Income taxes are provided based on the liability method for financial reporting purposes. Under this method deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount expected to be realized.

Uncertain tax positions are recognized in the financial statements only if that position is more likely than not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense.

The Company is required to file federal income tax returns in the United States and in various state and local jurisdictions. The Company's tax returns filed since inception are subject to examination by taxing authorities in the jurisdictions in which it operates in accordance with the normal statutes of limitations in the applicable jurisdiction.

Earnings (Loss) Per Share—Basic earnings (loss) per share have been calculated based upon the weighted-average number of common shares outstanding. The weighted-average number of common shares outstanding used in the computations of earnings (loss) per share was 11,901,830 for 2012 and 7,170,906 for 2011. The calculation of diluted weighted-average shares outstanding for 2012 and 2011 excludes 19,751,560 shares and 8,110,000 shares, respectively, issuable pursuant to outstanding warrants, stock options and debt conversion features because their effect is anti-dilutive.

Concentration of Credit Risk—The Company is subject to credit risk resulting from the concentration of its oil and natural gas receivables with significant purchasers. One purchaser accounted for all of the Company's oil and gas sales revenues for 2012 and 2011. The Company does not require collateral. While the Company believes its recorded receivable will be collected, in the event of default the Company would follow normal collection procedures. The Company does not believe the loss of this purchaser would materially impact its operating results as oil and gas are fungible products with well-established markets and numerous purchasers.

At times, the Company maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits.

Fair Value Measurements—The carrying value of cash and cash equivalents, accounts receivable, and accounts payable, as reflected in the balance sheets, approximate fair value because of the short-term maturity of these instruments. The estimated fair value of long-term debt was determined by discounting future cash flows using rates currently available to the Company for debt with similar terms and remaining maturities. The Company calculated that the estimated fair value of the long term debt is not significantly different than the carrying value of the debt. The participation liability associated with outstanding long-term debt was determined by utilizing a present value factor of 10 applied to proved developed reserves associated with the wells drilled with the proceeds of the notes.

Fair value is defined as the price that would be received to sell an asset or price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are classified for disclosure purposes according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair-value-measurement hierarchy are as follows:

·   Level 1—Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

·   Level 2—Inputs that reflect quoted prices for identical assets or liabilities in markets that are not active; quoted prices for similar assets or liabilities in active markets; inputs other than quoted prices that are observable for the asset or the liability; or inputs that are derived principally from or corroborated by observable market data by correlation or other means.

·   Level 3—Unobservable inputs reflecting the Company's own assumptions incorporated in valuation techniques used to determine fair value. These assumptions are required to be consistent with market participant assumptions that are reasonably available.

In determining fair value, the Company utilizes observable market data when available, or models that incorporate observable market data. In addition to market information, the Company incorporates transaction-specific details that, in management's judgment, market participants would take into account in measuring fair value. The Company utilizes the most observable inputs available for the valuation technique employed. If a fair value measurement reflects inputs at multiple levels within the hierarchy, the fair-value measurement of both financial and nonfinancial assets and liabilities are characterized based upon the lowest level of input that is significant to the fair value measurement.

Recently Issued Accounting Pronouncements – In April 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2010-13. ASU 2010-13 provides amendments to Topic 718, Stock Compensation, to clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity's equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. The amendments in ASU No. 2010-13 are effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2010. The Company’s adoption of the new guidance did not have a material effect on the Company’s consolidated financial statements.

In December 2010, the FASB issued ASU 2010-29, which addresses diversity in practice concerning the interpretation of the pro forma revenue and earnings disclosure requirements for business combinations. This ASU specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. This ASU also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. ASU 2010-29 is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. The adoption of this guidance did not have a material impact on the Company's financial statements.

In May 2011, the FASB issued ASU 2011-04, which clarifies some existing fair value measurement concepts, eliminates wording differences between U.S. GAAP and International Financial Reporting Standards (“IFRS”), and in some limited cases, changes some fair value measurement principles to achieve convergence between U.S. GAAP and IFRS. ASU 2011-04 is effective for the Company beginning after December 15, 2011. The adoption of this guidance did not have a material impact on the Company's financial statements.

Various other accounting standards updates were recently issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, and are not expected to a have a material impact on the Company's financial position, results of operations or cash flows.

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3. ACQUISITIONS (Details 1) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Actual
Revenues	$ 3,369,407	$ 1,899,584
Net loss	(1,027,157)	(1,109,397)
Loss per share-Basic and diluted	(0.09)	(0.15)
Proforma
Revenues	3,369,407	1,906,804
Net loss	$ (1,027,157)	$ (1,107,798)
Loss per share-Basic and diluted	(0.09)	(0.15)

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9. COMMITMENTS AND CONTINGENCIES (Details) (USD $)	Sep. 30, 2012
Convertible Notes
2013	$ 325,000
2014
2015	8,254,500
Thereafter
Total	8,579,500
Office Leases
2013	65,800
2014
2015
Thereafter
Total	$ 65,800

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3. ACQUISITIONS (Details Narrative) (USD $)	Sep. 30, 2012
Acquisitions Details Narrative
Receivable from CFO, Inc. 10% share of capital expenditures	$ 238,940

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Consolidated Balance Sheets (USD $)	Sep. 30, 2012	Sep. 30, 2011
ASSETS
Cash and cash equivalents	$ 3,090,422	$ 453,243
Accounts receivable	615,631	257,147
Other assets	6,132	4,428
Total current assets	3,712,185	714,818
Property and equipment - Oil and gas, on the basis of full cost accounting
Proved properties	9,288,166	3,606,967
Unproved properties and properties under development, not being amortized	1,427,294	619,679
Furniture and equipment	24,494	2,014
Less: accumulated depreciation, depletion and amortization	(1,108,956)	(264,657)
Total property and equipment	9,630,998	3,964,003
Debt issuance costs	857,412	338,345
Other assets	15,570	527,886
Total assets	14,216,165	5,545,052
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable	414,873	180,031
Other liabilities	344,712	75,056
Current portion of notes payable, net of discount of $77,584 and $0	247,416	0
Current portion of conversion feature liability	564	0
Total current liabilities	1,007,565	255,087
Notes payable, net of discount of $635,748 and $1,066,539	7,618,752	2,333,461
Participation liability	1,573,605	1,172,315
Conversion feature liability	583,454	720,593
Warrant liabilities	68,746	400,319
Asset retirement obligations	96,410	24,629
Total liabilities	10,948,532	4,906,404
Commitments and contingencies
Stockholders' equity
Preferred stock, $0.00001 par value; 5,000,000 shares authorized, none issued or outstanding	0	0
Common stock, $0.00001 par value; 50,000,000 shares authorized, 12,741,512 and 7,880,822 shares issued and outstanding	127	79
Additional paid-in capital	5,522,204	1,866,110
Accumulated deficit	(2,254,698)	(1,227,541)
Total stockholders' equity	3,267,633	638,648
Total liabilities and stockholders' equity	$ 14,216,165	$ 5,545,052

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12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details 1) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Property acquisitions
Unproved	$ 59,784	$ 407,085
Proved		259,247
Exploration	170,857	108,587
Development	6,258,174	3,084,194
Total Costs Incurred	$ 6,488,815	$ 3,859,113

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Consolidated Statements of Cash Flows (Unaudited) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Cash flows from operating activities:
Net income (loss)	$ (1,027,157)	$ (1,109,397)
Adjustments to reconcile net income (loss) to net cash from operating activities:
Loss on debt extinguishment	410,639
Change in estimate of participation liability	653,057
Depreciation, depletion and amortization	844,299	264,657
Amortization of debt issuance costs	237,809	205,697
Asset retirement obligation accretion	8,922	3,260
Amortization of debt discount	736,446	280,256
Accretion of participation liability	97,535	108,503
Stock-based compensation expense	59,700	258,731
Change in fair value of warrant and conversion feature liabilities	(1,081,371)	761,076
Change in operating assets and liabilities:
Accounts receivable	(358,484)	(252,247)
Other assets	(14,680)	42,977
Accounts payable	(54,291)	93,721
Other liabilities	(129,341)	(179,968)
Net cash from operating activities	383,083	477,266
Cash flows from investing activities
Purchase of furniture and equipment	(22,480)	(2,014)
Purchase of oil and gas properties		(309,247)
Capital expenditures on oil and gas properties	6,113,295	(3,087,047)
Net cash from investing activities	6,135,775	(3,398,308)
Cash flows from financing activities
Debt issuance costs	(813,780)	(400,051)
Equity offering costs	(199,849)	(525,291)
Proceeds from issuance of common stock and warrants	4,224,000	1,340,155
Proceeds from exercise of warrants		45,289
Repayment of note payable		(642,753)
Proceeds from issuance of notes payable	5,179,500	3,400,000
Net cash from financing activities	8,389,871	3,217,349
Net change in cash and cash equivalents	2,637,179	296,307
Cash and cash equivalents Beginning of period	453,243	156,936
Cash and cash equivalents End of period	$ 3,090,422	$ 453,243

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6. INCOME TAXES (Details) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Income Taxes Details
Current	$ 0	$ 0
Deferred	0	0
Total	$ 0	$ 0

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4. ASSET RETIREMENT OBLIGATIONS (Tables)

12 Months Ended

Sep. 30, 2012

Accounting Policies [Abstract]

SCHEDULE OF ASSET RETIREMENT OBLIGATIONS

	September 30, 2012			September 30, 2011
Inflation rate		4	%		4	%
Estimated asset life	9.5 years			9.5 years
Credit adjusted risk free interest rate		18	%		18	%

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

The following table shows the change in the Company's ARO for 2011 and 2012:

Asset retirement obligations at October 1, 2010	$	-
Obligations assumed in acquisition		15,216
Additional retirement obligations incurred		6,153
Changes in estimate		-
Accretion expense		3,260
Settlements		-
Asset retirement obligations at September 30, 2011	$	24,629
Obligations assumed in acquisition		-
Additional retirement obligations incurred		36,959
Change in estimate		49,428
Accretion expense		8,922
Settlements		(23,528	)
Asset retirement obligations at September 30, 2012	$	96,410

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6. INCOME TAXES (Details 1) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Income Taxes Details 1
Income tax expense computed at statutory rates	$ (349,233)	$ (377,195)
Non-deductible items	(366,608)	259,666
Change in valuation allowance	715,841	117,529
Total	$ 0	$ 0

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7. STOCKHOLDERS EQUITY (Tables)

12 Months Ended

Sep. 30, 2012

Stockholders' equity

SCHEDULE OF STOCKHOLDERS EQUITY

Warrants—The following table summarizes certain information regarding outstanding warrants as of September 30, 2012 and 2011:

				Exercise	Warrants Outstanding
Type	Issuance Date	Expiration Date		Price	2012	2011
Series A	December 1, 2010	October 31, 2014		$4.00	1,700,000	1,700,000
Series B	December 1, 2010	October 31, 2014		$1.20	340,000	340,000
Series B	December 1, 2010	October 31, 2014		$4.00	170,000	170,000
Series B	December 1, 2010	March 31, 2011	(1)	$0.10	-	-
Series C	February 28, 2011	February 28, 2016		$2.00	1,500,000	1,500,000
Series D	February 28, 2011	February 28, 2016		$1.20	150,000	150,000
Class A	December 2, 2011	November 29, 2016		$1.50	4,800,000	-
Series E	June 29, 2012	June 15, 2017		$1.55	296,300	-
Series E	July 6, 2012	June 15, 2017		$1.55	72,500	-
Series E	July 31, 2012	June 15, 2017		$1.55	57,160	-
Series E	September 5, 2012	June 15, 2017		$1.55	111,400	-

(1)    Exercised in March 2011.

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1. ORGANIZATION

12 Months Ended

Sep. 30, 2012

Notes to Financial Statements

1. ORGANIZATION

Organization—Vanguard Energy Corporation (the "Company") was organized under the laws of the State of Colorado on June 21, 2010. The Company conducts business in Texas through VE Corporation, a Colorado corporation and wholly owned subsidiary. The Company commenced operations on July 19, 2010 and is engaged in the acquisition, development and operation of onshore oil and gas properties in Texas.

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Consolidated Balance Sheets (Parenthetical) (USD $)	Sep. 30, 2012	Sep. 30, 2011
Liabilities
Discount on Note Payable	$ 635,748	$ 1,066,539
Stockholders' equity
Preferred stock, par value	$ 0.00001	$ 0.00001
Preferred stock, authorized shares	5,000,000	5,000,000
Preferred stock, issued shares	0	0
Preferred stock, outstanding shares	0	0
Common stock, par value	$ 0.00001	$ 0.00001
Common stock, authorized shares	50,000,000	50,000,000
Common stock, issued shares	12,741,512	7,865,822
Common stock, outstanding shares	12,741,512	7,865,822

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11. SUPPLEMENTAL CASH FLOW INFORMATION

12 Months Ended

Sep. 30, 2012

Notes to Financial Statements

11. SUPPLEMENTAL CASH FLOW INFORMATION

	Fiscal Year Ended		Fiscal Year Ended
	September 30, 2012		September 30, 2011
Interest paid	$	250,734	$	242,702
Interest capitalized (non-cash)		350,142		225,529
Exchange of 2010 Notes for 2012 Notes		3,075,000		-
Noncash investing and financing activities:
Capital expenditures included in accounts payable		289,133		84,365
Issuance of notes payable for oil and gas properties		-		357,085
Warrant liability settled on exercise		-		136,015
Recognition of liabilities for issuance of:
Series A warrants		-		1,188
Series B warrants		-		143,948
Series C warrants		-		274,516
Series D warrants		-		49,385
Issuance of Series E Warrants to placement agent		97,583		-
Recognition of conversion feature liability		670,893		26,771
Recognition of participation liability		-		737,886
Asset retirement obligations incurred		86,386		4,588

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Document and Entity Information (USD $)	12 Months Ended
	Sep. 30, 2012	Dec. 15, 2012
Document And Entity Information
Entity Registrant Name	Vanguard Energy Corp
Entity Central Index Key	0001497649
Document Type	10-K
Document Period End Date	Sep. 30, 2012
Amendment Flag	false
Current Fiscal Year End Date	--09-30
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float	$ 9,300,000
Entity Common Stock, Shares Outstanding		12,741,512
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2012

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12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

12 Months Ended

Sep. 30, 2012

Notes to Financial Statements

12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

NOTE 12 – SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Results of operations.  Results of operations for producing activities consist of all activities for the exploration, production and sale of oil and gas.  Net revenues from production include only the revenues from the production and sale of oil and natural gas. Production costs are those incurred to operate and maintain wells and related equipment and facilities used in oil and gas operations. Income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.

	Fiscal Year Ended September 30, 2012		Fiscal Year Ended September 30, 2011
Net revenues from production
Third-party sales	$	3,369,407	$	1,899,584
Production costs
Lease operating expense		672,233		200,742
Production taxes		155,616		87,217
Asset retirement obligation accretion		8,922		3,260
		836,771		291,219
Depreciation, depletion and amortization		842,571		264,489
		1,690,065		1,343,876
Income tax expense		573,270		455,843
Results of operations from producing activities	$	1,116,795	$	888,033

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development. Amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year for oil and gas property acquisition, exploration and development activities. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful exploration wells, as well as dry hole costs, leasehold impairments, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities.

	Fiscal Year Ended September 30, 2012		Fiscal Year Ended September 30, 2011
Property acquisitions
Unproved	$	59,784		$	407,085
Proved		-			259,247
Exploration		170,857			108,587
Development		6,258,174			3,084,194
Total Costs Incurred	$	6,488,815		$	3,859,113

Capitalized costs. Capitalized costs include the cost of properties, equipment and facilities for oil and natural-gas producing activities. Capitalized costs for proved properties include costs for oil and natural-gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified.

	September 30, 2012		September 30, 2011
Capitalized costs
Unproved properties	$	1,427,294		$	619,679
Proved properties		9,288,166			3,606,967
		10,715,460			4,226,646
Less: Accumulated DD&A		1,107,060			264,657
Net capitalized costs	$	9,608,400		$	3,961,989

Costs Not Being Amortized. The following table sets forth a summary of oil and gas property costs not being amortized at September 30, 2012, by the period in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The majority of the evaluation activities are expected to be completed within five years.

			Fiscal Year Ended			Fiscal Year Ended		Inception to
	Total		September 30, 2012			September 30, 2011		September 30, 2010
Property acquisition costs	$	327,962		$	-	$	151,417		$	176,545
Exploration and development		1,055,713			950,334		76,433			28,946
Capitalized interest		43,619			21,872		10,886			10,861
Total	$	1,427,294		$	972,206	$	238,736		$	216,352

Oil and Gas Reserve Information.    Nova Resources, Inc., an independent engineering firm, prepared the estimates of the proved reserves, future production, and income attributable to the leasehold interests as of September 30, 2012 and 2011. The estimated proved net recoverable reserves presented below include only those quantities that were expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under the then existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves estimated to be recovered through existing wells. Proved Undeveloped Reserves include those reserves that may be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure for recompletion or secondary recovery operations is required. All of the Company's Proved Reserves are located onshore in the continental United States of America.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise.

The following table sets forth estimates of the proved oil and gas reserves (net of royalty interests) for the Company and changes therein, for the periods indicated.

Estimated Quantities of Proved Reserves

	Oil
	(Bbls)
September 30, 2010		164,950
Revisions of prior estimates		34,803
Purchases of reserves in place		362,790
Production		(26,733	)
September 30, 2011		535,810
Revisions of prior estimates		192,386
Purchases of reserves in place		46,557
Production		(48,889	)
September 30, 2012		725,864

	September 30, 2012		September 30, 2011
Estimated Quantities of Proved Developed Reserves		313,617		163,963
Estimated Quantities of Proved Undeveloped Reserves		412,247		371,847

Standardized Measure of Discounted Future Net Cash Flows.    The Standardized Measure related to proved oil and gas reserves is summarized below. Future cash inflows were computed by applying a twelve month average of the first day of the month prices to estimated future production, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expense. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows, less the tax basis of properties involved. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Company.

Standardized Measure of Oil and Gas

	September 30, 2012			September 30, 2011			September 30, 2010
Future cash inflows	$	74,669,619		$	50,622,329		$	13,672,292
Future production costs		(9,364,444	)		(6,273,765	)		(1,611,534	)
Future development costs		(6,175,000	)		(5,557,500	)		(2,750,000	)
Future income taxes		(13,639,715	)		(10,992,652	)		(2,381,361	)
Future net cash flows		45,490,460			27,798,412			6,929,397
Discount of future net cash flows at 10% per annum		(8,509,198	)		(5,107,917	)		(2,381,915	)
Standardized measure of discounted future net cash flows	$	36,981,262		$	22,690,495		$	4,547,482

The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves for the periods indicated.

Changes in Standardized Measure

	Fiscal Year Ended September 30, 2012			Fiscal Year Ended September 30, 2012
Sales of oil and gas produced, net of production costs	$	(2,532,636	)	$	(1,608,365	)
Purchases of minerals in place		-			11,457,772
Net change due to revisions in quantity estimates		17,466,030			-
Net changes in prices and production costs		3,134,171			4,459,237
Accretion of discount before income taxes		2,269,050			454,748
Changes in timing and other		(6,045,848	)		3,379,621
Net change	$	14,290,767		$	18,143,013

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Consolidated Statements of Operations (Unaudited) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Revenues
Oil and gas sales	$ 3,369,407	$ 1,899,584
Costs and expenses
Lease operating expense	672,233	200,742
Production taxes	155,616	87,217
Depreciation, depletion and amortization	844,299	264,657
Asset retirement obligation accretion	8,922	3,260
General and administrative	1,564,475	1,013,304
Total costs and expenses	3,245,545	1,569,180
Income (loss) from operations	123,862	330,404
Other income (expense)
Interest income	3,062	904
Interest expense	(1,171,756)	(679,629)
Change in fair value of warrant and conversion feature liabilities	1,081,371	(761,076)
Change in estimate of participation liability	(653,057)
Loss on debt extinguishment	(410,639)
Total other income (expense)	(1,151,019)	(1,439,801)
Loss before income taxes	(1,027,157)	(1,109,397)
Provision for income taxes	0	0
Net loss	$ (1,027,157)	$ (1,109,397)
Loss per share - Basic	$ (0.09)	$ (0.15)
Weighted average number of common shares	11,901,830	7,170,906
Loss per share - Diluted	$ (0.09)	$ (0.15)
Weighted average number of common and potential common shares	11,901,830	7,170,906

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6. INCOME TAXES

12 Months Ended

Sep. 30, 2012

Notes to Financial Statements

6. INCOME TAXES

The provision for income taxes consists of the following:

	Fiscal Year Ended		Fiscal Year Ended
	September 30, 2012		September 30, 2011
Current	$	-	$	-
Deferred		-		-
Total	$	-	$	-

The provision for income taxes differs from the amount computed by applying the federal statutory income tax rate (34%) on operations as follows:

	Fiscal Year Ended			Fiscal Year Ended
	September 30, 2012			September 30, 2011
Income tax expense computed at statutory rates	$	(349,233	)	$	(377,195	)
Non-deductible items		(366,608	)		259,666
Change in valuation allowance		715,841			117,529
Total	$	-		$	-

The components of the net deferred tax asset were as follows:

	September 30,			September 30,
	2012			2011
Deferred tax assets
Net operating loss carryforwards	$	2,987,160		$	824,260
Stock-based compensation		103,367			82,869
Other		-			-
Deferred tax liability - oil & gas properties		(2,319,346	)		(749,431	)
Participation liability		102,739			-
Net deferred tax assets before valuation allowance		873,920			157,698
Valuation allowance		(873,920	)		(157,698	)
Net deferred tax asset	$	-		$	-

A valuation allowance has been established to offset reported deferred tax assets. The Company's accumulated net operating losses were approximately $8.9 million at September 30, 2012 and begin to expire if not utilized in the year 2030.

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5. LONG-TERM DEBT

12 Months Ended

Sep. 30, 2012

Notes to Financial Statements

5. LONG-THERM DEBT

2010 Convertible Promissory Notes – In December 2010, the Company completed the issuance of $3,400,000 in Convertible Promissory Notes, due and payable on October 31, 2012 and convertible, at the holder’s option, into common stock of the Company at $1.00 per share at any time after April 30, 2011.  The 2010 Convertible Promissory Notes bear interest at 8% per year, payable quarterly.  In addition, the note holders were issued 1,700,000 Series A warrants to purchase the Company’s common stock at $4.00 per share any time on or before October 31, 2014 and were additionally granted a twenty percent (20%) net profits interest payable quarterly from any net profits generated from wells drilled and completed with the proceeds of the notes.  The notes are secured by the oil and gas leases acquired, and any oil or gas wells drilled on the leases, with the proceeds from the sale of the notes. 

Direct costs of $400,051 were incurred in connection with the issuance of the 2010 Convertible Promissory Notes.  The Company also issued the placement agent Series B warrants for the purchase of up to 340,000 shares of common stock at a price of $1.20 per share at any time prior to October 31, 2014, 170,000 shares of common stock at a price of $4.00 per share at any time prior to October 31, 2014, and 453,322 shares of common stock at a price of $0.10 per share at any time prior to March 31, 2011.  As of September 30, 2012, 453,322 warrants have been exercised. The warrants also provide for adjustment to their exercise prices  under certain circumstances.

During 2012, $3,075,000 of the 2010 Convertible Promissory Notes outstanding were surrendered in exchange for new 2012 Convertible Promissory Notes as discussed below. The remaining notes, which had an outstanding principal balance of $325,000, were repaid in October 2012.

2012 Convertible Promissory Notes – During 2012, the Company issued $8,254,500 of Convertible Promissory Notes, due and payable on June 30, 2015 and convertible at the holder’s option, into common stock of the Company at $1.25 per share.  The Convertible Promissory Notes bear interest at 15% per year, payable quarterly. Of the total amount raised, $5,179,500 represented new cash investors and $3,075,000 represented investors from the 2010 convertible note offering who chose to roll their investment in that earlier offering into the Company's new offering. Net proceeds from this financing are being used to fund an accelerated developmental drilling program in the Company's oil fields located in Southeast Texas and to pay any of the 2010 Convertible Promissory Notes that remain outstanding on October 31, 2012, the maturity date of those notes.

Except in certain circumstances, the conversion price of the 2012 Convertible Promissory Notes will be lowered if the Company sells any additional shares of common stock or any securities convertible into common stock, at a price below the then applicable conversion price.  The conversion price will also be proportionately adjusted in the event of any stock split, or capital reorganization.  On or prior to December 31, 2013, the Company may repay the Notes, without penalty, upon twenty days written notice to the Note holders if, during any twenty trading days within a period of thirty consecutive trading days, the closing price of the Company’s common stock is $2.25 or greater and the Company’s common stock has an average daily trading volume of 100,000 shares or more during the twenty trading days. After December 31, 2013 the Company may prepay the Notes upon twenty days written notice to the Note holders.

Direct costs of $813,780 were incurred in connection with the issuance of the 2012 Convertible Promissory Notes.  The Company recognized a loss on debt extinguishment of $410,639 related to the investors who chose to roll their investment in the 2010 Convertible Promissory Notes into the new offering. The placement agents for this offering received a cash commission of $619,905 as well as 537,360 Series E warrants. Each Series E warrant entitles the holder to purchase one share of the Company’s common stock. The Series E warrants may be exercised at any time on or before June 30, 2017 at a price of $1.55 per share.

Total Indebtedness under Convertible Promissory Notes – The Company’s combined gross outstanding balance of the 2010 and 2012 Convertible Promissory Notes was $8,579,500 as of September 30, 2012.  As of September 30, 2012, the combined unamortized discount on the 2010 and 2012 Convertible Promissory Notes totaled $713,332.  Interest expense for the amortization of debt issuance costs and discount on the notes was $965,748 and $485,910 for the years ended September 30, 2012 and 2011, respectively.  The combined effective interest rate of the 2010 and 2012 Convertible Promissory Notes (net of the participation liability discussed below) was 26.5% as of September 30, 2012.

Net Profits Interest Participation Liability – The note holder’s twenty percent (20%) net profits interest granted with the issuance of the 2010 Convertible Promissory Notes is owned by Vanguard Net Profits, LLC, a Texas limited liability company (the “Fund”). The Company has a 1% interest in the Fund and is the Fund’s manager.  Persons that purchased the Company’s 2010 Convertible Promissory Notes own the remaining interest in the Fund.

The Company has recognized a participation liability related to the net profits interest granted. This participation liability is reflected in the liability section of the balance sheets at its estimated fair value of $1,573,605 as of September 30, 2012 and $1,172,315 as of September 30, 2011. At any time, the Company may purchase the net profits interests held by the Fund for $3,400,000.

The Company estimated the fair value of the participation liability utilizing a present value factor of 10 applied to proved developed reserves associated with the wells drilled and completed with the proceeds of the notes.   Changes in the fair value of the participation liability are recorded as additions or deductions to the discount on the long-term debt to the extent 2010 Convertible Promissory Notes remain outstanding.  Otherwise, changes in the participation liability are recorded to other expense in the statements of operations.

The Company incurred expense associated with this net profits interest during the years ended September 30, 2012 and 2011 of $97,535 and $108,503, respectively. This amount is reported as interest expense in the statement of operations. The Company also made payments under this arrangement of $375,470 and $329,006 during the years ended September 30, 2012 and 2011, respectively.

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6. INCOME TAXES (Tables)

12 Months Ended

Sep. 30, 2012

Income Taxes Tables

Schedule for the provision for income taxes

	Fiscal Year Ended		Fiscal Year Ended
	September 30, 2012		September 30, 2011
Current	$	-	$	-
Deferred		-		-
Total	$	-	$	-

The provision for income taxes differs from the amount computed by applying the federal statutory income tax rate (34%) on operations as follows:

	Fiscal Year Ended			Fiscal Year Ended
	September 30, 2012			September 30, 2011
Income tax expense computed at statutory rates	$	(349,233	)	$	(377,195	)
Non-deductible items		(366,608	)		259,666
Change in valuation allowance		715,841			117,529
Total	$	-		$	-

The components of the net deferred tax asset were as follows:

	September 30,			September 30,
	2012			2011
Deferred tax assets
Net operating loss carryforwards	$	2,987,160		$	824,260
Stock-based compensation		103,367			82,869
Other		-			-
Deferred tax liability - oil & gas properties		(2,319,346	)		(749,431	)
Participation liability		102,739			-
Net deferred tax assets before valuation allowance		873,920			157,698
Valuation allowance		(873,920	)		(157,698	)
Net deferred tax asset	$	-		$	-

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13. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

12 Months Ended

Sep. 30, 2012

Quarterly Financial Information Disclosure [Abstract]

13. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Fiscal Year Ended September 30, 2012
Revenues	$	745,171		$	862,505		$	851,899		$	909,832
Income (loss) from operations		187,773			91,222			(149,878	)		(5,255	)
Net income (loss)		17,380			254,367			(328,199	)		(970,705	)
Income (loss) per share – Basic and diluted (1)	$	0.00		$	0.02		$	(0.03	)	$	(0.09	)
Fiscal Year Ended September 30, 2011
Revenues	$	-		$	397,915		$	917,067		$	584,602
Income (loss) from operations		(144,183	)		(227,246	)		516,532			185,301
Net income (loss)		(172,399	)		(1,241,088	)		270,552			33,538
Income (loss) per share – Basic and diluted (1)	$	(0.03	)	$	(0.18	)	$	0.03		$	0.00

(1) The sum of the individual quarterly income (loss) per share amounts may not agree with year-to-date net income per common share as each quarterly computation is based on the weighted-average number of common shares outstanding during that period. Securities deemed anti-dilutive were excluded from each quarter in which the Company reported a net loss.

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9. COMMITMENTS AND CONTINGENCIES

12 Months Ended

Sep. 30, 2012

Notes to Financial Statements

9. COMMITMENTS AND CONTINGENCIES

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

The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company also conducts periodic reviews, on a Company-wide basis, to identify changes in its environmental risk profile.

Management Agreements – In June 2010, the Company entered into an agreement with an entity controlled by its Chief Executive Officer ("CEO") to provide for his personal part-time management consulting services for $7,500 per month, on a month-to-month basis. Also in June 2010, the Company entered into a consulting services agreement with its Chairman of the Board to provide for his personal part-time management consulting services for $3,000 per month, on a month-to-month basis. Beginning in January 2011, the monthly payments were increased to $12,500 for the CEO and $10,000 for the Chairman. In May 2011, these consulting arrangements were replaced with employment agreements for each executive.

Office Lease – The Company leases office space under an operating lease. Rent expense for 2012 and 2011 totaled $81,641 and $47,076, respectively.   Future minimum payments on office leases are shown below.

Contractual Obligations – The Company’s material future contractual obligations by fiscal year as of September 30, 2012 were as follows:

	Total		2013		2014		2015		Thereafter
Convertible notes	$	8,579,500	$	325,000		-	$	8,254,500		-
Office leases	$	65,800	$	65,800		-		-		-

Except for the above, the Company has no contractual capital commitments outstanding at September 30, 2012.  Management estimates the Company will spend approximately $7,000,000 during fiscal year 2013 for drilling and completing wells in the Batson Dome Field and various other projects.

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7. STOCKHOLDERS EQUITY

12 Months Ended

Sep. 30, 2012

Stockholders' equity

7. STOCKHOLDERS EQUITY

Preferred Stock—5,000,000 shares authorized, none issued or outstanding.

Common Stock—The Company is authorized to issue an aggregate of 50,000,000 shares of common stock with $0.00001 par value. In July 2010, the Company sold 4,900,000 shares of common stock at $0.001 per share in a private placement. In September 2010, the Company completed a second private placement of 1,012,500 shares of common stock at $0.40 per share. Net proceeds from the private placements were used for general corporate purposes, including capital expenditures.

In February and March 2011, the Company sold 1,500,000 units at a price of $1.00 per unit to private investors. Each unit consisted of one share of common stock and one Series C warrant. Each Series C warrant allows the holder to purchase one share of Company common stock at a price of $2.00 per share at any time prior to February 28, 2016. The Company also issued the placement agent Series D warrants for the purchase of up to 150,000 shares of common stock at a price of $1.20 per share at any time prior to February 28, 2016.

On December 2, 2011 the Company sold 4,800,000 units in an initial public offering at a price of $1.00 per unit.  Each unit consisted of one share of the Company's common stock and one Class A warrant.  Each Class A warrant entitles its holder to purchase one share of the Company's common stock at an exercise price of $1.50.  The Class A warrants are exercisable at any time on or before November 29, 2016.  The underwriters for the offering were paid a commission of $432,000 (9% of the gross offering proceeds) and a non-accountable expense allowance of $144,000 (3% of the gross offering proceeds). The underwriters also received warrants to purchase up to 480,000 units.  Proceeds from the IPO were approximately $3,498,900 net of the underwriters’ discount and offering expenses.

During the years ended September 30, 2012 and 2011, the Company issued 60,690 and 15,000 shares, respectively, of restricted stock for investor relations consulting services. The Company recognized expense of $59,700 during 2012 and $15,000 during 2011 related to the issuance of these shares.

Following the above issuances of common stock, the Company has 12,741,512 shares issued and outstanding as of September 30, 2012.

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

Warrants—The following table summarizes certain information regarding outstanding warrants as of September 30, 2012 and 2011:

			Exercise		Warrants Outstanding
Series	Issuance Date	Expiration Date	Price		2012		2011
A	December 1, 2010	October 31, 2014	$	4.00		1,700,000		1,700,000
B	December 1, 2010	October 31, 2014	$	1.20		340,000		340,000
B	December 1, 2010	October 31, 2014	$	4.00		170,000		170,000
B	December 1, 2010	March 31, 2011 (1)	$	0.10		-		-
C	February 28, 2011	February 28, 2016	$	2.00		1,500,000		1,500,000
D	February 28, 2011	February 28, 2016	$	1.20		150,000		150,000
A	December 2, 2011	November 29, 2016	$	1.50		4,800,000		-
E	June 29, 2012	June 15, 2017	$	1.55		296,300		-
E	July 6, 2012	June 15, 2017	$	1.55		72,500		-
E	July 31, 2012	June 15, 2017	$	1.55		57,160		-
E	September 5, 2012	June 15, 2017	$	1.55		111,400		-

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8. STOCK-BASED COMPENSATION

12 Months Ended

Sep. 30, 2012

Stockholders' equity

8. STOCK-BASED COMPENSATION

On January 10, 2011, the Board of Directors approved a Non-Qualified Stock Option Plan (the "Plan") which authorizes the issuance of up to 1,500,000 shares of Company common stock to persons that exercise options granted pursuant to the Plan. The Company's employees, directors, officers, consultants and advisors are eligible to be granted options pursuant to the Plan, 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.

Options for the purchase of 850,000 shares of the Company's common stock were issued to members of executive management and the Board of Directors on January 10, 2011. The stock options have an exercise price of $1.00 per share and were fully vested on the date of grant. The fair value of each stock option grant was estimated on the date of grant using the Black-Scholes option pricing model and the following assumptions:

Risk-free interest rate		0.99	%
Expected dividend rate		0.00	%
Expected volatility		40.80	%
Expected life (years)		3
Calculated value of options granted	$	0.29

No stock options have been exercised to date. The Company recognized stock-based compensation expense of $243,731 during 2011 related to the issuance of these options.

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10. FAIR VALUE OF FINANCIAL INSTRUMENTS

12 Months Ended

Sep. 30, 2012

Notes to Financial Statements

10. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following table summarizes the financial liabilities measured at fair value on a recurring basis as of September 30, 2012 and 2011:

			September		September 30,
	Level			30, 2012		2011
Participation liability		3	$	1,573,605	$	1,172,315
Conversion feature liability		3		584,018		720,593
Warrant liabilities		3		68,746		400,319
Total liabilities			$	2,226,369	$	2,293,227

Assets and liabilities that are not recognized or disclosed on a recurring basis include those measured at fair value in a business combination and the initial recognition of asset retirement obligations.

The following tables present a reconciliation of those liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3):

				Conversion
	Participation			Feature			Warrant
	Liability			Liability			Liabilities			Total
Balance at September 30, 2011	$	1,172,315		$	720,593		$	400,319		$	2,293,227
Purchases, issuances and settlements		(349,302	)		613,223			-			263,921
(Gains) losses included in earnings		750,592			(749,798	)		(331,573	)		(330,779	)
Balance at September 30, 2012	$	1,573,605		$	584,018		$	68,746		$	2,226,369

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4. ASSET RETIREMENT OBLIGATIONS (Details 1) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Asset Retirement Obligations Details 1
Asset retirement obligations at October 1, 2010	$ 24,629
Obligations assumed in acquisition		15,216
Additional retirement obligations incurred	36,959	6,153
Changes in estimate	49,428
Accretion expense	8,922	3,260
Settlements	(23,528)
Asset retirement obligations at September 30, 2011	$ 96,410	$ 24,629

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12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details 7) (USD $)	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Supplemental Information Relating To Oil And Gas Producing Activities Details 7
Sales of oil and gas produced, net of production costs	$ (2,532,636)	$ (1,608,365)
Purchases of minerals in place		11,457,772
Net change due to revisions in quantity estimates	17,466,030
Net changes in prices and production costs	3,134,171	4,459,237
Accretion of discount before income taxes	2,269,050	454,748
Changes in timing and other	(6,045,848)	3,379,621
Net change	$ 14,290,767	$ 18,143,013

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3. ACQUISITIONS (Tables)

12 Months Ended

Sep. 30, 2012

Acquisitions Tables

Schedule of purchase price for the acquisition

Consideration paid -- cash	$	259,247
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed and undeveloped properties		274,463
Asset retirement obligations		(15,216	)
Total identifiable net assets	$	259,247

Schedule of pro forma of company's operations and properties acquired

	Fiscal Year						Fiscal Year
	Ended						Ended
	September 30, 2012						September 30, 2011
	Actual			Proforma			Actual			Proforma
Revenues	$	3,369,407		$	3,369,407		$	1,899,584		$	1,906,804
Net loss		(1,027,157	)		(1,027,157	)		(1,109,397	)		(1,107,798	)
Loss per share – Basic and diluted		(0.09	)		(0.09	)		(0.15	)		(0.15	)

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9. COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Sep. 30, 2012

Notes to Financial Statements

Contractual Obligations Schedule

	Total		2013		2014		2015		Thereafter
Convertible notes	$	8,579,500	$	325,000		-	$	8,254,500		-
Office leases	$	65,800	$	65,800		-		-		-

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12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details 5)	Sep. 30, 2012	Sep. 30, 2011
Supplemental Information Relating To Oil And Gas Producing Activities Details 5
Estimated Quantities of Proved Developed Reserves	313,617	163,963
Estimated Quantities of Proved Undeveloped Reserves	412,247	371,847

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10. FAIR VALUE OF FINANCIAL INSTRUMENTS (Details) (USD $)	Sep. 30, 2012	Sep. 30, 2011
Fair Value Of Financial Instruments Details
Participation liability-Level 3	$ 1,573,605	$ 1,172,315
Conversion feature liability-Level 3	584,018	720,593
Warrant liabilities-Level 3	68,746	400,319
Total liabilities	$ 2,226,369	$ 2,293,227

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Consolidated Statements of Changes in Shareholders Equity (USD $)	Common Stock	Additional Paid-In Capital	Accumulated Deficit	Total
Beginning Balance, Amount at Sep. 30, 2010	$ 59	$ 409,841	$ (118,144)	$ 291,756
Beginning Balance, Shares at Sep. 30, 2010	5,912,500
Stock-based compensation	15,000	258,731		258,731
Exercise of warrants, Shares	453,322
Exercise of warrants, Amount	5	181,299		181,304
Issuance of common stock units, Shares	1,500,000
Issuance of common stock units, Amount	15	1,016,239		1,016,254
Net loss			(1,109,397)	(1,109,397)
Ending Balance, Amount at Sep. 30, 2011	79	1,866,110	(1,227,541)	638,648
Ending Balance, Shares at Sep. 30, 2011	7,880,822
Stock-based compensation	60,690	59,700		59,700
Issuance of common stock units, Shares	4,800,000
Issuance of common stock units, Amount	48	3,596,394		3,596,442
Net loss			(1,027,157)	(1,027,157)
Ending Balance, Amount at Sep. 30, 2012	$ 127	$ 5,522,204	$ (2,254,698)	$ 3,267,633
Ending Balance, Shares at Sep. 30, 2012	12,741,512

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4. ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Sep. 30, 2012

Accounting Policies [Abstract]

4. ASSET RETIREMENT OBLIGATIONS

During the fiscal years presented, the Company brought a number of oil and gas wells into productive status and will have asset retirement obligations once the wells are permanently removed from service. The primary obligations involve the removal and disposal of surface equipment, plugging and abandoning the wells, and site restoration. For the purpose of determining the fair value of ARO incurred during the fiscal years presented, the Company used the following assumptions:

	September 30, 2012			September 30, 2011
Inflation rate		4	%		4	%
Estimated asset life	9.5 years			9.5 years
Credit adjusted risk free interest rate		18	%		18	%

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

The following table shows the change in the Company's ARO for 2011 and 2012:

Asset retirement obligations at October 1, 2010	$	-
Obligations assumed in acquisition		15,216
Additional retirement obligations incurred		6,153
Changes in estimate		-
Accretion expense		3,260
Settlements		-
Asset retirement obligations at September 30, 2011	$	24,629
Obligations assumed in acquisition		-
Additional retirement obligations incurred		36,959
Change in estimate		49,428
Accretion expense		8,922
Settlements		(23,528	)
Asset retirement obligations at September 30, 2012	$	96,410

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10. FAIR VALUE OF FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Sep. 30, 2012

Notes to Financial Statements

Financial Liabilities

			September		September 30,
	Level			30, 2012		2011
Participation liability		3	$	1,573,605	$	1,172,315
Conversion feature liability		3		584,018		720,593
Warrant liabilities		3		68,746		400,319
Total liabilities			$	2,226,369	$	2,293,227

Liabilities Using Signigicant Unobservable Inputs

				Conversion
	Participation			Feature			Warrant
	Liability			Liability			Liabilities			Total
Balance at September 30, 2011	$	1,172,315		$	720,593		$	400,319		$	2,293,227
Purchases, issuances and settlements		(349,302	)		613,223			-			263,921
(Gains) losses included in earnings		750,592			(749,798	)		(331,573	)		(330,779	)
Balance at September 30, 2012	$	1,573,605		$	584,018		$	68,746		$	2,226,369

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7. STOCKHOLDERS EQUITY (Details) (USD $)	Sep. 30, 2012
Series A1
Issuance Date	DECEMBER 1, 2010
Expiration Date	OCTOBER 31, 2014
Exercise Price	$ 4.00
Warrants Outstanding-2012	1,700,000
Warrants Outstanding-2011	1,700,000
Series B1
Issuance Date	DECEMBER 1, 2010
Expiration Date	OCTOBER 31, 2014
Exercise Price	$ 1.20
Warrants Outstanding-2012	340,000
Warrants Outstanding-2011	340,000
Series B2
Issuance Date	DECEMBER 1, 2010
Expiration Date	OCTOBER 31, 2014
Exercise Price	$ 4.00
Warrants Outstanding-2012	170,000
Warrants Outstanding-2011	170,000
Series B3
Issuance Date	DECEMBER 1, 2010
Expiration Date	MARCH 31, 2011
Exercise Price	$ 0.10
Warrants Outstanding-2012
Warrants Outstanding-2011
Series C
Issuance Date	FEBRUARY 28, 2011
Expiration Date	FEBRUARY 28, 2016
Exercise Price	$ 2.00
Warrants Outstanding-2012	1,500,000
Warrants Outstanding-2011	1,500,000
Series D
Issuance Date	FEBRUARY 28, 2011
Expiration Date	FEBRUARY 28, 2016
Exercise Price	$ 1.20
Warrants Outstanding-2012	150,000
Warrants Outstanding-2011	150,000
Class A
Issuance Date	DECEMBER 2, 2011
Expiration Date	NOVEMBER 29, 2016
Exercise Price	$ 1.50
Warrants Outstanding-2012	4,800,000
Warrants Outstanding-2011
Series E1
Issuance Date	JUNE 29, 2012
Expiration Date	JUNE 15, 2017
Exercise Price	$ 1.55
Warrants Outstanding-2012	296,300
Warrants Outstanding-2011
Series E2
Issuance Date	JULY 6, 2012
Expiration Date	JUNE 15, 2017
Exercise Price	$ 1.55
Warrants Outstanding-2012	72,500
Warrants Outstanding-2011
Series E3
Issuance Date	JULY 31, 2012
Expiration Date	JUNE 15, 2017
Exercise Price	$ 1.55
Warrants Outstanding-2012	57,160
Warrants Outstanding-2011
Series E4
Issuance Date	SEPTEMBER 5, 2012
Expiration Date	JUNE 15, 2017
Exercise Price	$ 1.55
Warrants Outstanding-2012	111,400
Warrants Outstanding-2011

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2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Sep. 30, 2012

Notes to Financial Statements

Principles of Consolidation and Basis of Presentation

Principles of Consolidation and Basis of Presentation— The consolidated financial statements include the accounts of Vanguard Energy Corporation and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

The Company's fiscal year-end is September 30. The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") and pursuant to the accounting and disclosure rules and regulations of the U.S. Securities and Exchange Commission ("SEC"). A summary of the significant accounting policies applied in the preparation of the accompanying financial statements follows.

Management Estimates

Management Estimates—The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the fair value of acquired assets and liabilities (Note 3), asset retirement obligations (Note 4), participation, conversion feature and warrant liabilities (Note 5), income taxes (Note 6) and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (Note 12).

Reclassifications

Reclassifications – Certain amounts previously presented for prior periods have been reclassified to conform to the current presentation. The reclassifications had no effect on net loss, working capital or equity previously reported.

Cash and Cash Equivalents

Cash and Cash Equivalents—The Company considers all highly liquid instruments purchased with a maturity date of three months or less to be cash equivalents.

Oil and Gas Properties

Oil and Gas Properties—The Company follows the full cost accounting method to account for oil and natural gas properties, whereby costs incurred in the acquisition, exploration and development of oil and gas reserves are capitalized. Such costs include lease acquisition, geological and geophysical activities, rentals on nonproducing leases, drilling, completing and equipping of oil and gas wells and administrative costs directly attributable to those activities and asset retirement costs. Disposition of oil and gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such adjustment would significantly alter the relationship between capital costs and proved reserves of oil and gas, in which case the gain or loss is recognized to  operations.

The capitalized costs of oil and gas properties, excluding unevaluated and unproved properties, are amortized as depreciation, depletion and amortization expense using the units-of-production method based on estimated proved recoverable oil and gas reserves.

The costs associated with unevaluated and unproved properties, initially excluded from the amortization base, relate to unproved leasehold acreage, wells and production facilities in progress and wells pending determination of the existence of proved reserves, together with capitalized interest costs for these projects. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well once a determination of the existence of proved reserves has been made or upon impairment of a lease. Costs associated with wells in progress and completed wells that have yet to be evaluated are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry wells are transferred to the amortization base immediately upon determination that the well is unsuccessful.

All items classified as unproved property are assessed on a quarterly basis for possible impairment or reduction in value. Properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization.

Under full cost accounting rules for each cost center, capitalized costs of evaluated oil and gas properties, including asset retirement costs, less accumulated amortization and related deferred income taxes, may not exceed an amount (the "cost ceiling") equal to the sum of (a) the present value of future net cash flows from estimated production of proved oil and gas reserves, based on current prices and operating conditions, discounted at ten percent (10%), plus (b) the cost of properties not being amortized, plus (c) the lower of cost or estimated fair value of any unproved properties included in the costs being amortized, less (d) any income tax effects related to differences between the book and tax basis of the properties involved. If capitalized costs exceed this limit, the excess is charged to  operations.  For purposes of the ceiling test calculation, current prices are defined as the unweighted arithmetic average of the first day of the month price for each month within the 12 month period prior to the end of the reporting period.  Prices are adjusted for basis or location differentials.  Unless sales contracts specify otherwise, prices are held constant for the productive life of each well.  Similarly, current costs are assumed to remain constant over the entire calculation period.

Given the volatility of oil and gas prices, it is reasonably possible that the estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline in the future, even if only for a short period of time, it is possible that impairments of oil and gas properties could occur. In addition, it is reasonably possible that impairments could occur if costs are incurred in excess of any increases in the present value of future net cash flows from proved oil and gas reserves, or if properties are sold for proceeds less than the discounted present value of the related proved oil and gas reserves.

Revenue Recognition

Revenue Recognition—Oil and gas sales result from undivided interests held by the Company in oil and gas properties. Sales of oil and gas produced from oil and gas operations are recognized when the product is delivered to the purchaser and title transfers to the purchaser. The Company had no natural gas sales imbalance positions at September 30, 2012 or 2011. Charges for gathering and transportation are included in production expenses.

Asset Retirement Obligations

Asset Retirement Obligations—The Company records a liability for asset retirement obligations ("ARO") associated with its oil and gas wells when those assets are placed in service. The corresponding cost is capitalized as an asset and included in the carrying amount of oil and gas properties and is depleted over the useful life of the properties. Subsequently, the ARO liability is accreted to its then-present value.

Inherent in the fair value calculation of an ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Settlements greater than or less than amounts accrued as ARO are recorded as a gain or loss upon settlement.

Capitalized Interest

Capitalized Interest—Interest is capitalized as part of the historical cost of developing and constructing assets for significant projects. Significant oil and gas investments in unproved properties, significant exploration and development projects for which depreciation, depletion and amortization expense is not currently recognized, and exploration or development activities that are in progress qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depletion or impairment, along with other capitalized costs related to that asset.

Debt Issuance Costs

Debt Issuance Costs—Costs incurred in connection with the issuance of long-term debt are capitalized and amortized over the term of the related debt.

Participation Liability

Participation Liability—The participation liability associated with outstanding long-term debt is recorded at fair value as determined utilizing a present value factor of 10 applied to proved developed reserves. Payments made for the participation liability are reported as interest expense. Changes in the fair value of the participation liability are recorded as additions or deductions to the discount on the long-term debt to the extent this debt remains outstanding.  Once the associated debt is repaid, changes in the participation liability are recorded to other expense in the statements of operations.

Conversion Feature Liability and Warrant Liabilities

Conversion Feature Liability and Warrant Liabilities—The conversion feature liability and warrant liabilities are recorded at fair value based upon valuation models utilizing relevant factors such as expected life, estimated volatility, risk-free interest and expected dividend rate. Changes in the fair value of these liabilities are reported in the statements of operations.

Stock-Based Compensation

Stock-Based Compensation—The Company accounts for employee stock-based compensation using the fair value method. The fair value attributable to stock options is calculated based on the Black-Scholes option pricing model and is amortized to expense over the service period which is equivalent to the time required to vest the stock options.

Income Taxes

Income Taxes—Income taxes are provided based on the liability method for financial reporting purposes. Under this method deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount expected to be realized.

Uncertain tax positions are recognized in the financial statements only if that position is more likely than not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense.

The Company is required to file federal income tax returns in the United States and in various state and local jurisdictions. The Company's tax returns filed since inception are subject to examination by taxing authorities in the jurisdictions in which it operates in accordance with the normal statutes of limitations in the applicable jurisdiction.

Earnings (Loss) Per Share

Earnings (Loss) Per Share—Basic earnings (loss) per share have been calculated based upon the weighted-average number of common shares outstanding. The weighted-average number of common shares outstanding used in the computations of earnings (loss) per share was 11,901,830 for 2012 and 7,170,906 for 2011. The calculation of diluted weighted-average shares outstanding for 2012 and 2011 excludes 19,751,560 shares and 8,110,000 shares, respectively, issuable pursuant to outstanding warrants, stock options and debt conversion features because their effect is anti-dilutive.

Concentration of Credit Risk

Concentration of Credit Risk—The Company is subject to credit risk resulting from the concentration of its oil and natural gas receivables with significant purchasers. One purchaser accounted for all of the Company's oil and gas sales revenues for 2012 and 2011. The Company does not require collateral. While the Company believes its recorded receivable will be collected, in the event of default the Company would follow normal collection procedures. The Company does not believe the loss of this purchaser would materially impact its operating results as oil and gas are fungible products with well-established markets and numerous purchasers.

At times, the Company maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits.

Fair Value Measurements

Fair Value Measurements—The carrying value of cash and cash equivalents, accounts receivable, and accounts payable, as reflected in the balance sheets, approximate fair value because of the short-term maturity of these instruments. The estimated fair value of long-term debt was determined by discounting future cash flows using rates currently available to the Company for debt with similar terms and remaining maturities. The Company calculated that the estimated fair value of the long term debt is not significantly different than the carrying value of the debt. The participation liability associated with outstanding long-term debt was determined by utilizing a present value factor of 10 applied to proved developed reserves associated with the wells drilled with the proceeds of the notes.

Fair value is defined as the price that would be received to sell an asset or price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are classified for disclosure purposes according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair-value-measurement hierarchy are as follows:

·   Level 1—Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

·   Level 2—Inputs that reflect quoted prices for identical assets or liabilities in markets that are not active; quoted prices for similar assets or liabilities in active markets; inputs other than quoted prices that are observable for the asset or the liability; or inputs that are derived principally from or corroborated by observable market data by correlation or other means.

·   Level 3—Unobservable inputs reflecting the Company's own assumptions incorporated in valuation techniques used to determine fair value. These assumptions are required to be consistent with market participant assumptions that are reasonably available.

In determining fair value, the Company utilizes observable market data when available, or models that incorporate observable market data. In addition to market information, the Company incorporates transaction-specific details that, in management's judgment, market participants would take into account in measuring fair value. The Company utilizes the most observable inputs available for the valuation technique employed. If a fair value measurement reflects inputs at multiple levels within the hierarchy, the fair-value measurement of both financial and nonfinancial assets and liabilities are characterized based upon the lowest level of input that is significant to the fair value measurement.

Recently Issued Accounting Pronouncements

Recently Issued Accounting Pronouncements – In April 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2010-13. ASU 2010-13 provides amendments to Topic 718, Stock Compensation, to clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity's equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. The amendments in ASU No. 2010-13 are effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2010. The Company’s adoption of the new guidance did not have a material effect on the Company’s consolidated financial statements.

In December 2010, the FASB issued ASU 2010-29, which addresses diversity in practice concerning the interpretation of the pro forma revenue and earnings disclosure requirements for business combinations. This ASU specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. This ASU also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. ASU 2010-29 is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. The adoption of this guidance did not have a material impact on the Company's financial statements.

In May 2011, the FASB issued ASU 2011-04, which clarifies some existing fair value measurement concepts, eliminates wording differences between U.S. GAAP and International Financial Reporting Standards (“IFRS”), and in some limited cases, changes some fair value measurement principles to achieve convergence between U.S. GAAP and IFRS. ASU 2011-04 is effective for the Company beginning after December 15, 2011. The adoption of this guidance did not have a material impact on the Company's financial statements.

Various other accounting standards updates were recently issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, and are not expected to a have a material impact on the Company's financial position, results of operations or cash flows.