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, 2013

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	77056
(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:  None.

Title of each class Name of each exchange on which registered

Securities registered pursuant to Section 12(g) of the Act:  None.

___________________

(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 þ  No o

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, 2013 was approximately $6,170,000.

As of December 15, 2013, 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.

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. Our original corporate plan was 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.

2

In January of 2013, we announced that we were seeking ways to accelerate shareholder value.  In that regard, we have been investigating the possibility of selling our oil and gas properties in Southeast Texas.  We have not received any firm offers for our properties nor have we established a price we would consider for our properties.  If we reach an agreement to sell at a price we consider attractive, the net proceeds, after repayment of convertible debt and other liabilities, would be used to acquire new leases in East Texas with strong potential for value creation.  We emphasize that we are not committed to selling any of our properties and, depending on available capital, will continue with our current operating program.

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 (62% 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 three 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 (74% 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 $650,000. As of November 30, 2013, we had drilled 5 wells on this lease.

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, 2014 Subject to the commencement of drilling the first well by June 14, 2014 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 90% working interest (67.5% 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, 2013, we had not commenced any drilling operations on the lease subject to the farmout agreement.

3

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.  As of November 30, 2013, we had not drilled any wells on this lease.  We will have a 90% working interest (67.5% net revenue interest) in any wells drilled 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, 2013, we had not commenced any drilling operations on the lease subject to the farmout agreement.

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 has 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.

As mentioned above, we acquired two producing and three shut-in oil wells in the Batson Dome Field. As of November 30, 2013, one of the producing wells is off production and the other well was producing approximately one barrel of oil per day, net to our 62% net revenue interest.

4

As of November 30, 2013, we had drilled and completed 14 wells in the Batson Dome Field. Our share of the costs of drilling and completing these wells was approximately $12,900,000. Each of these wells has shown multiple potentially productive zones at depths ranging from 2,600 to 4,400 feet.  Of the 14 wells we drilled and completed, 6 are currently shut in.  We continue to actively study each existing well bore to determine what opportunities we might have to re-enter both producing and shut in wells in order to open potentially producible zones that were previously untapped or enlarge currently producing zones to expand production from the nine currently producing wells.

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, 2014. Subject to the commencement of drilling the first well by January 31, 2014, 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, 2013, 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.  Due to lack of liquidity and inadequate time to assemble the necessary funds to drill this property, it is expected that this lease will expire in January 2014.

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.

Depending upon future available capital, we may drill and, if warranted, complete additional wells in the Batson Dome field. 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 $600,000. We will have a 90% working interest (62%-67.5% net revenue interest) in any wells we drill in the Batson Dome Field.

During the year ended September 30, 2013, we produced 62,245 gross barrels and 45,758 net barrels of oil from our wells.

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.

5

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.

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 three years ended September 30, 2013.

	Years Ended September 30,
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Development Wells:
Productive:
Oil		2		2		6		5.5		4		3.6
Gas		-		-		-		-		-		-
Nonproductive (2)		-		-		2		2		-		-
Exploratory Wells:
Productive		-		-		-		-		-		-
Oil		-		-		-		-		-		-
Gas		-		-		-		-		-		-
Nonproductive		-		-		-		-		-		-

(1) Of the four producing wells we drilled in 2011, one well subsequently become nonproductive. Of the six productive wells we drilled in 2012, one well subsequently became nonproductive.

(2) The two wells we drilled in 2013 were completed and produced oil for a short period until they were shut-in.  We are presently reworking these wells in an effort to increase production from the wells. As of November 30, 2013 one of these wells had been reworked successfully and a workover of the other well was in process.

As of November 30, 2013:

●   we were not drilling, or completing any wells, and

●   we were reworking one of the wells we drilled in fiscal 2013.

The following table shows, as of November 30, 2013, 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

10

9.3

240

217

305

288

(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.

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The following table shows, as of November 30, 2013, the status of our gross acreage:

State	Held by Production		Not Held by Production
Texas		240		305

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.

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
235	2014
70	2015

Proved Reserves

Below are estimates of our net proved reserves as of September 30, 2013, net to our interest. All of our proved reserves are located in Texas.

Estimates of volumes of net proved reserves at September 30, 2013 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		70,220		--
Non-Producing		54,148		--
Proved Undeveloped		--		--

‘‘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, 2013. 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.

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Future cash inflows	$	12,943,629
Deductions (including estimated taxes)	$	4,361,848
Future net cash flow	$	8,581,781
Discounted future net cash flow	$	6,477,771

Pressler Petroleum Consultants, Inc. prepared the estimates of our proved reserves, future production and income attributable to our leasehold interests as of September 30, 2013. The report was prepared by Vivian Salinas, petroleum engineer and Stan S. Valdez, President. Pressler 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 Pressler.

Stan S. Valdez was the technical person primarily responsible for overseeing the preparation of the reserve report. Mr. Valdez earned a Bachelor’s Degree in Petroleum Engineering  from Texas A&M University.  Mr. Valdez has more than 17 years of practical experience in the estimation and evaluation of petroleum reserves.

Warren Dillard, our Chief Executive Officer, oversaw the preparation of the reserve estimates by Pressler.  Mr. Dillard earned a Masters Degree in Business Administration from Harvard University.

Nova Resources prepared the reserve report for fiscal 2012.  Joseph V. Rochefort was the petroleum engineer responsible for overseeing the preparation of the reserve report.

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, reservoir pressures, operating and development costs, regulations, technology or other factors could significantly increase or decrease estimates of proved reserves.

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, 2013 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.

8

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.

The Proved Producing (PDP) reserve estimate of 70,220 net barrels is a material reduction from the 231,859 barrels reported as of October 1, 2012.  Net production of 45,758 barrels accounted for a portion of the reduction, but the balance was due to calculations of reservoir potential that was influenced by further detailed analysis of the producing formations drive systems and the declines in production from certain wells at a greater rate than previously experienced.  The interpretation of 3D seismic this year provided additional input and helped delineate the field more precisely, resulting in  lowering the estimates of remaining recoverable oil.

Non-Producing (PDNP) estimated reserves of 54,148 net barrels are also a material reduction from the 81,758 net barrels reported as of September 30, 2012.  This reduction resulted partially from certain non-producing zones being put on production and the balance from the limitations cited above regarding the proved producing reserves.

Although we reported Proved Undeveloped (PUD) reserves of 412,247 barrels as of September 30, 2012, our engineers determined this year that such classification was not appropriate due to the faulting system identified in the field, and were thus removed from the report. Rather, they have estimated 66,094 barrels of Probable reserves, a change in the category of certain potential future production from our leases.

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.

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Future Operations

Depending upon available capital, our operating strategy will be 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.

Depending upon available capital, 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.

As explained in the forepart of this Item 1, we are investigating the possibility of selling our interest in our oil and gas properties in southeast Texas.

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.

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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.

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, larger companies have the ability to manage their risk by diversification.

11

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 workover 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, 2013, 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.

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, 2013, we had one full-time employee.

Our principal office is located at 1330 Post Oak Blvd., Suite 1600, Houston, Texas 77056. This office is leased month to month at a rate of $125 per month.

We also maintain a satellite office in Los Angeles, California. This office consists of 300 square feet and is rented for $4,300 per month pursuant to a lease which expires on December 31, 2013 and then continues on a month-to-month basis.

ITEM 1A. RISK FACTORS.

Investors should be aware that an 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.

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Our failure to obtain capital may restrict our operations.  We need additional capital to fund our operating losses, repay outstanding debt, and 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.

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 workover 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.

Risks Related to the Estimation of Reserves.  The estimation of oil and gas reserves involves subjective judgments and determinations based on available geological, technical, contractual and economic information.  They are not exact determinations.  In addition, these judgments may change based on new information from production or drilling activities, or changes in economic factors, as well as from developments such as acquisitions and dispositions, new discoveries and extensions of existing fields and the application of improved recovery techniques.  Reserve estimates can also be subject to correction for errors in the application of published rules and guidance.

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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.

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 that of 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.

Not applicable

ITEM 4. MINE SAFETY DISCLOSURE.

Not applicable

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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
December 31, 2013	$	0.95	$	0.59
March 31, 2013	$	0.85	$	0.62
June 30, 2013	$	0.70	$	0.20
September 30, 2013	$	0.33	$	0.14

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, 2013, 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.

Overview

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.

As of November 30, 2013, we had drilled and completed 14 wells in the Batson Dome Field. Our share of the costs of working over, drilling and completing these wells was approximately $12,900,000. Each of these wells has shown multiple potentially productive zones at depths ranging from 2,600 to 4,400 feet.  Of the 14 wells drilled and completed, five are currently shut in.  We continue to actively study each existing well bore to determine what opportunities we might have to re-enter both producing and shut in wells in order to open potentially producible zones that were previously untapped or enlarge currently producing zones to expand production from the nine currently producing wells.

During the year ended September 30, 2013, we produced 62,245 gross barrels and 45,758 net barrels of oil from our wells.

We do not anticipate expending any further funds during fiscal year 2014 for drilling and completing new wells in the Batson Dome Field or for various other projects.  Drilling and completing new wells would require additional financing beyond our available cash.  We will, however, continue to perform workovers as required.

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.

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

As explained in the forepart of Item 1 of this report, we are investigating the possibility of selling our interest our oil and gas properties in southeast Texas.

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.

Results of Operations

Material changes in our Statement of Operations for the year ended September 30, 2013 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
Lease operating expense	I	Operation of new wells.
Production taxes	I	Increased sales of oil.
Depreciation, depletion and amortization	I	More depletion of oil reserves as a result of increased production.
Impairment of oil and gas properties	I	Write down of capitalized cost of oil and gas properties due to reduction of estimated proved reserves.
General and administrative	D	Reduction in certain promotional activities and elimination of paid personal services.
Other income (expense)
Interest expense	I	Convertible debt, with a higher interest rate, was outstanding for the full year.
Change in fair value of warrant and conversion feature liabilities	D	Lower market prices for our common stock.
Change in estimate of participation liability	D	Reduction in our estimated proven reserves lowered the amount we expect to pay to the holders of a net profit interest in some of our wells.

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We recorded an impairment expense of $3,634,312 during the year ended September 30, 2013 as a result of reductions in estimated proved reserves.  Revised calculations of proved reserves were based on detailed analysis of producing formations drive systems and declines in production from certain wells at a greater rate than previously experienced. The interpretation of 3D seismic during the fiscal fourth quarter of 2013 provided additional input and helped delineate the field more precisely, resulting in limiting the estimates of remaining recoverable oil.

Operating expenses requiring cash for the year ended September 30, 2013 consisted primarily of:

●   lease operating expenses;

●   general and administrative expenses; and

●   interest expense.

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.

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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

●   were used to fund further drilling in our fields located in Southeast Texas.

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

	Year Ended			Year Ended
	September 30, 2013			September 30, 2012
Cash provided by operations	$	928,683		$	383,083
Acquisition of oil and gas properties		-			-
Purchases of furniture and equipment		(2,452	)		(22,480	)
Drilling and completion costs		(2,357,368	)		(6,113,295	)
Debt issuance costs		-			(813,780	)
Equity offering costs		-			(199,849	)
Proceeds from issuance of common stock and warrants		-			4,224,000
Repayment of notes		(325,000	)		-
Proceeds from sale of convertible notes		-			5,179,500

As of November 30, 2013, our salaries and other corporate overhead were approximately $50,000 per month.  This significantly reduced operating cost is a result of material reductions in compensation to management, elimination of investor relations services, and other cost cutting efforts.  Many of the reductions were not fully realized until after June, 2013 and as a result will have further beneficial effects during our fiscal year ending September 30, 2014.

See Item 1 of this report for information concerning our farmout agreements with third parties.

Capital expenditures during the fiscal year ended 2013 totaled $2,359,820. We do not currently have any funds for drilling and completing new wells. Any future drilling and completion of new wells would require additional financing beyond our available cash.

Any cash generated by our operations, after payment of general, administrative and lease operating expenses, may be used to drill and, if warranted, rework existing wells to offset declining production, complete oil wells, acquire oil and gas leases covering lands which we believe are favorable for the production of oil, fund working capital reserves and repay the convertible notes we sold in 2012. Our capital expenditure plans are subject to periodic revision based upon the availability of funds and expected return on investment.

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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.

Our overall corporate objective is 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.

Contractual Obligations

Our material future contractual obligations as of September 30, 2013 were as follows:

	Total		2014		2015		Thereafter
2012 Convertible notes	$	8,254,500		-	$	8,254,000		-
Office lease	$	12,900	$	12,900		-		-

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.

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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.

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, 2013, 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, 2013 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, 2013.

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 Dillard	71	President, Chief Executive, Financial and Accounting Officer and a Director
Delton C. Drum	56	Vice President, Field Operations
Steven M. Powers	71	Vice President of Business Development, Secretary and a Director
Rick A. Wilber	66	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.

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.

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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 Steven Powers are the members of our compensation committee. Our Board of Directors serves as our audit committee.

Rick Wilber is an independent director 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, 2013.

						Restricted				Other
	Fiscal	Salary		Bonus		Stock Awards		Option Awards		Annual Compensation
Name and Principal Position	Year	(1)		(2)		(3)		(4)		(5)		Total
Warren Dillard	2013	$	135,000							$	40,000	$	175,000
President,	2012	$	150,000		-		-		-	$	40,000	$	190,000
Principal Executive,
Financial and Accounting Officer
R. Gerald Bailey	2013	$	180,000									$	180,000
Director (6)	2012	$	190,000		-		-		-		-	$	190,000
Michael Fraim	2013	$	10,000									$	10,000
Vice President	2012	$	100,000		-		-		-		-	$	100,000
Technology (7)

(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.

(6)   Mr. Bailey resigned as a director on July 31, 2013.

(7)   Mr. Fraim resigned as an officer on April 30, 2013.

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The following table shows the amount we expect to pay to our officers during the twelve months ending September 30, 2014 and the amount of time these persons expect to devote to us.

	Projected		Percent of Time to be
Name	Compensation		Devoted to our Business
Warren Dillard	$	120,000		90	%
Steven Powers	$	--		10	%

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 remains in effect so long as the oil leases covered by the agreement continue in operation.  During the two years ended September 30, 2013, we paid C.F.O., Inc. $470,000 and $763,600 respectively for services provided to us. These amounts included reimbursements for drilling costs advanced by C.F.O., Inc. of $224,722 and $573,533 respectively.

We have an employment agreement with Warren Dillard which provides that Mr. Dillard is paid a base salary of $10,000 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 do not have any employment or compensation agreements with Rick Wilber or Steven Powers.

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 table shows the options granted pursuant to the Non-Qualified Stock Option Plan to our officers and directors. As of November 30, 2013, none of the options had been exercised. The options are fully vested.

Name	Date		Shares Issuable Upon Exercise of Options (1)		Exercise Price		Date
Warren M. Dillard		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

(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.

Compensation of Directors During Year Ended September 30, 2013. During the year ended September 30, 2013, we did not compensate our directors for acting as such.

Compensation Committee Interlocks and Insider Participation. Rick Wilber and Steven Powers are the members of our compensation committee. During the year ended September 30, 2013, both Mr. Wilber and Mr. Powers participated in deliberations concerning executive officer compensation. During the year ended September 30, 2013, 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.

25

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, 2013, 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
Name and Address of Beneficial Owner	Beneficially Owned			of Class(1)
Warren M. Dillard		1,062,732	(2)(3)		8.2	%
1330 Post Oak Blvd., Suite 1600
Houston, Texas 77056
Delton C. Drum		40,000			*
2626 Royal Trail Dr.
Kingwood, TX 77339
Steven M. Powers		957,732	(2)(4)		7.4	%
1999 Avenue of the Stars, Ste. 1100
Los Angeles, CA 90067
Rick A. Wilber		1,173,332	(5)		9.1	%
10360 Kestrel Street
Plantation, FL 33324
All officers and directors as a group		3,233,796			24.7	%
(4 persons)

______________

* Less than 1%

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

26

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.

See Item 11 of this report for information concerning amounts we have paid to a company controlled by one of our officers.

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, 2013		September 30, 2012
Audit Fees	$	101,073	$	69,849
Audit-Related Fees	$	48,440	$	27,052
Tax Fees	$	21,909	$	15,401
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.

27

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
10.7*	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
31	Rule 13a-14(a) Certifications
32	Section 1350 Certifications
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).

28

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 31st day of December, 2013.

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 Dillard	Principal Executive, Financial  and Accounting Officer and Director	December 31, 2013
Warren Dillard
/s/ Steven M. Powers	Director	December 31, 2013
Steven M. Powers
/s/ Rick A. Wilber	Director	December 31, 2013
Rick A. Wilber

29

CONTENTS

	Page
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 (Deficit)	F-4
Consolidated Statements of Cash Flows	F-5
Notes to the Consolidated Financial Statements	F-6

F-1

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, 2013 and 2012 and the related consolidated statements of operations, changes in stockholders' equity (deficit), 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). 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. Accordingly, we express no such opinion.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe 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, 2013 and 2012, 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.

/s/ Briggs & Veselka Co.

Briggs & Veselka Co.

Houston, Texas

December 30, 2013

F-2

VANGUARD ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

	September 30,			September 30,
ASSETS	2013			2012
Current assets
Cash and cash equivalents	$	1,334,285		$	3,090,422
Accounts receivable		371,765			615,631
Other assets		16,055			6,132
Total current assets		1,722,105			3,712,185
Property and equipment
Oil and gas, on the basis of full cost accounting
Proved properties		12,994,766			9,288,166
Unproved properties and properties under
development, not being amortized		61,470			1,427,294
Furniture and equipment		26,946			24,494
Less: accumulated depreciation, depletion and amortization		(6,594,081	)		(1,108,956	)
Total property and equipment		6,489,101			9,630,998
Debt issuance costs		538,700			857,412
Other assets		10,808			15,570
Total assets	$	8,760,714		$	14,216,165
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities
Accounts payable	$	113,314		$	414,873
Other liabilities		322,194			344,712
Current portion of notes payable, net of discount of $0 and $77,584		-			247,416
Current portion of conversion feature liability		-			564
Total current liabilities		435,508			1,007,565
Notes payable, net of discount of $441,132 and $635,748		7,813,368			7,618,752
Participation liability		465,551			1,573,605
Conversion feature liability		-			583,454
Warrant liabilities		-			68,746
Asset retirement obligations		177,685			96,410
Total liabilities		8,892,112			10,948,532
Commitments and contingencies		-			-
Stockholders' equity (deficit)
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 shares issued and outstanding		127			127
Additional paid-in capital		5,522,204			5,522,204
Accumulated deficit		(5,653,729	)		(2,254,698	)
Total stockholders' equity (deficit)		(131,398	)		3,267,633
Total liabilities and stockholders' equity (deficit)	$	8,760,714		$	14,216,165

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

F-3

VANGUARD ENERGY CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

	Fiscal Year			Fiscal Year
	Ended			Ended
	September 30, 2013			September 30, 2012
Revenues
Oil and gas sales	$	4,644,356		$	3,369,407
Costs and expenses
Lease operating expense		714,669			672,233
Production taxes		214,127			155,616
Depreciation, depletion and amortization		1,850,814			844,299
Impairment of oil and gas properties		3,634,312			-
Asset retirement obligation accretion		23,186			8,922
General and administrative		1,373,122			1,564,475
Total costs and expenses		7,810,230			3,245,545
Income (loss) from operations		(3,165,874	)		123,862
Other income (expense)
Other income		7,386
Interest income		1,340			3,062
Interest expense		(1,864,379	)		(1,171,756	)
Change in fair value of warrant and
conversion feature liabilities		652,765			1,081,371
Change in estimate of participation liability		969,731			(653,057	)
Loss on debt extinguishment		-			(410,639	)
Total other income (expense)		(233,157	)		(1,151,019	)
Loss before income taxes		(3,399,031	)		(1,027,157	)
Provision for income taxes		-			-
Net loss	$	(3,399,031	)	$	(1,027,157	)
Loss per share – Basic	$	(0.27	)	$	(0.09	)
Weighted average number of
common shares		12,741,512			11,901,830
Loss per share – Diluted	$	(0.27	)	$	(0.09	)
Weighted average number of common
and potential common shares		12,741,512			11,901,830

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

F-4

VANGUARD ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES

IN STOCKHOLDERS' EQUITY (DEFICIT)

										Total
	Common Stock				Additional		Accumulated			Stockholders’
	Shares		Amount		Paid In Capital		Deficit			Equity (Deficit)
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
Net loss		-		-		-		(3,399,031	)		(3,399,031	)
Balance at
September 30, 2013		12,741,512	$	127	$	5,522,204	$	(5,653,729	)	$	(131,398	)

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

F-5

VANGUARD ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOW

	Fiscal Year			Fiscal Year
	Ended			Ended
	September 30, 2013			September 30, 2012
Cash flows from operating activities
Net loss	$	(3,399,031	)	$	(1,027,157	)
Adjustments to reconcile net loss
to net cash from operating activities:
Loss on debt extinguishment		-			410,639
Change in estimate of participation liability		(969,731	)		653,057
Impairment of Oil and Gas Properties		3,634,312			-
Depreciation, depletion and amortization		1,850,814			844,299
Amortization of debt issuance costs		318,712			237,809
Asset retirement obligation accretion		81,275			8,922
Amortization of debt discount		272,200			736,446
Accretion of participation liability		(138,323	)		97,535
Stock-based compensation expense		-			59,700
Change in fair value of warrant and conversion
feature liabilities		(652,765	)		(1,081,371	)
Change in operating assets and liabilities:
Accounts receivable		243,866			(358,484	)
Other assets		(5,161	)		(14,680	)
Accounts payable		(284,967	)		(54,291	)
Other liabilities		(22,518	)		(129,341	)
Net cash from operating activities		928,683			383,083
Cash flows from investing activities
Purchase of furniture and equipment		(2,452	)		(22,480	)
Capital expenditures on oil and gas properties		(2,357,368	)		(6,113,295	)
Net cash from investing activities		(2,359,820	)		(6,135,775	)
Cash flows from financing activities
Debt issuance costs		-			(813,780	)
Equity offering costs		-			(199,849	)
Proceeds from issuance of common stock and warrants		-			4,224,000
Proceeds from issuance (repayment) of notes payable		(325,000	)		5,179,500
Net cash from financing activities		(325,000	)		8,389,871
Net change in cash and cash equivalents		(1,756,137	)		2,637,179
Cash and cash equivalents
Beginning of period		3,090,422			453,243
End of period	$	1,334,285		$	3,090,422

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

F-6

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.

In January of 2013, the Company announced that it was seeking ways to accelerate shareholder value.  In that regard, the Company has been investigating the possibility of selling its oil and gas properties in Southeast Texas.  The Company has not received any firm offers for the properties nor have established a price it would consider for them.  If the Company reaches an agreement to sell at a price considered attractive, the net proceeds, after repayment of convertible debt and other liabilities, would be used to acquire new leases in East Texas with strong potential for value creation.  The Company emphasizes that it is not committed to selling any of its properties and, depending on available capital, will continue with its current operating program.

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 used in the ceiling test (Notes 2 and 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.

F-7

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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.

During the fourth quarter of fiscal year 2013 and based on the October 1, 2013 Reserve Report, the cost ceiling analysis established that the Company’s proved properties required the recording of an impairment reduction. The Company recorded an impairment expense of $3,634,312 \as a result of reductions in estimated proved reserves.  Revised calculations of proved reserves were based on detailed analysis of producing formations drive systems and declines in production from certain wells at a greater rate than previously experienced. The interpretation of 3D seismic during the fiscal fourth quarter of 2013 provided additional input and helped delineate the field more precisely, resulting in limiting the estimates of remaining recoverable oil. The production declines resulted in greater DD&A expense of $919,313 during the fourth quarter.  These adjustments were offset somewhat by a reduction in the Participation Liability of $969,731 resulting from lower estimated net cash flows from certain wells in which outside parties have a 20% net profits interest.

F-8

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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, 2013 or 2012. 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.

F-9

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 12,741,512 for 2013 and 11,901,830 for 2012. The calculation of diluted weighted-average shares outstanding for 2013 and 2012 excludes 19,261,860-shares and 19,751,560 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 2013 and 2012. 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.

F-10

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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.

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

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 –OIL AND GAS PROPERTIES

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, 2013, the Company had drilled five 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 $650,000.  As of September 30, 2013, the Company had drilled five 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, 2013. In November 2013, the Company paid $10,000 to extend the agreement, whereby it now has an obligation to commence drilling by June 14, 2014. Subject to the commencement of drilling the first well by June 14, 2014, 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, 2013, the Company had not commenced any drilling operations on the lease subject to the farmout agreement.

F-11

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 had 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.  The original agreement was extended one year providing until January 31, 2014 to commence drilling the first well.  As of September 30, 2013, the Company did not drill any wells on this lease and is not expected to drilling any wells in the foreseeable future.

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.

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, 2013, this amount totaled $12,476 and was repaid in October 2013 from CFO’s production revenues. During the two years ended September 30, 2013, we paid C.F.O., Inc. $470,000 and $763,600 respectively for services provided to us. These amounts included reimbursements for drilling costs advanced by C.F.O., Inc. of $224,722 and $573,533 respectively.

As discussed in Note 2, the Company recorded an impairment expense of $3,634,312 during the year ended September 30, 2013 as a result of reductions in estimated proved reserves.

F-12

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 4 – ASSET RETIREMENT OBLIGATIONS

The Company has asset retirement obligations for any wells that 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, 2013			September 30, 2012
Inflation rate		4	%		4	%
Estimated asset life	3.9 years			9.5 years
Credit adjusted risk free interest rate		30	%		18	%

The assumptions used in calculating ARO as of September 30, 2013 were based on data presented in the October 1, 2013 Reserve Report and using the current costs of plugging and abandoning wells.

The following table shows:

Asset retirement obligations at September 30, 2011	$	24,629
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
Additional retirement obligations incurred		(28,290	)
Change in estimate		111,598
Accretion expense		23,186
Settlements		(25,219	)
Asset retirement obligations at September 30, 2013	$	177,685

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 bore 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.  

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, 2013, 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 were used to fund an accelerated developmental drilling program in the Company's oil fields located in Southeast Texas and to pay the 2010 Convertible Promissory Notes that remained 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.

The Company’s gross outstanding balance of the 2012 Convertible Promissory Notes was $8,254,500 as of September 30, 2013.  As of September 30, 2013, the unamortized discount on the 2012 Convertible Promissory Notes totaled $441,116.  Interest expense for the amortization of debt issuance costs and discount on the notes was $965,748 and $965,748 for the years ended September 30, 2013 and 2012, respectively.  The effective interest rate of the 2012 Convertible Promissory Notes (net of the participation liability discussed below) was 25.1% as of September 30, 2013.

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.

F-14

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 $465,551 as of September 30, 2013 and $1,573,605 as of September 30, 2012. 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, 2013 and 2012 of $123,312 and $97,535, respectively. This amount is reported as interest expense in the statement of operations. The Company also made payments under this arrangement of $261,635 and $375,470 during the years ended September 30, 2013 and 2012, respectively.

NOTE 6 – INCOME TAXES

The provision for income taxes consists of the following:

	Fiscal Year		Fiscal Year
	Ended		Ended
	September 30, 2013		September 30, 2012
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			Fiscal Year
	Ended			Ended
	September 30, 2013			September 30, 2012
Income tax expense computed at statutory rates	$	(1,137,194	)	$	(349,233	)
Non-deductible items		(220,623	)		(366,608	)
Change in valuation allowance		1,357,817			715,841
Total	$	-		$	-

F-15

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

	September 30, 2013			September 30, 2012
Deferred tax assets
Net operating loss carryforwards	$	3,665,319		$	2,987,160
Stock-based compensation		222,936			103,367
Deferred tax liability - oil & gas properties		(1,380,769	)		(2,319,346	)
Participation liability		(273,638	)		102,739
Subtotal		2,233,848			873,920
Valuation allowance		(2,233,848	)		(873,920	)
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 $10,800,000 at September 30, 2013 and begin to expire if not utilized in the year 2030.

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, 2013.

F-16

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Warrants—The following table summarizes certain information regarding outstanding warrants as of September 30, 2013 and 2012:

			Exercise		Shares Issuable Upon Exercise of Warrants
Series	Issuance Date	Expiration Date	Price		2013		2012
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		4,800,000
Series E	June 29, 2012	June 15, 2017	$	1.55		296,300		296,300
Series E	July 6, 2012	June 15, 2017	$	1.55		72,500		72,500
Series E	July 31, 2012	June 15, 2017	$	1.55		57,160		57,160
Series E	September 5, 2012	June 15, 2017	$	1.55		111,400		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.

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 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.  In May 2013 the consulting arrangement were set at $10,000 for the CEO and $-0- for the Chairman.  The Chairman resigned following the May 2013 modification.

F-17

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Office Lease – The Company leases office space under an operating lease. Rent expense for 2013 and 2012 totaled $72,474 and $81,641, 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, 2013 were as follows:

	Total		2014		2015		Thereafter
Convertible notes	$	8,254,500	$	-0-	$	8,254,500		-
Office leases	$	12,900	$	12,900		-		-

The Company has no contractual capital commitments outstanding at September 30, 2013.  Management estimates the Company will spend approximately $150,000 during fiscal year 2014 for workover of 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, 2013 and 2012:

			September 30,		September 30,
	Level		2013		2012
Participation liability		3	$	465,551	$	1,573,605
Conversion feature liability		3		-		584,018
Warrant liabilities		3		-		68,746
Total liabilities			$	465,551	$	2,226,369

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, 2012	$	1,573,605		$	584,018		$	68,746		$	2,226,369
Purchases, issuances and settlements		(138,323	)		-			-			(138,323	)
(Gains) losses included in earnings		(969,731	)		(584,018	)		(68,746	)		(1,622,495	)
Balance at September 30, 2013	$	465,551		$	-		$	-		$	465,551

F-18

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 11 – SUPPLEMENTAL CASH FLOW INFORMATION

	Fiscal Year		Fiscal Year
	Ended		Ended
	September 30, 2013		September 30, 2012
Interest paid	$	1,435,660	$	250,734
Interest capitalized (non-cash)		63,040		350,142
Exchange of 2010 Notes for 2012 Notes		-		3,075,000
Noncash investing and financing activities:
Capital expenditures included in accounts payable		16,591		289,133
Issuance of Series E Warrants to placement agent		-		97,583
Recognition of conversion feature liability		-		670,893
Asset retirement obligations incurred		-		86,386

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, 2013			Fiscal Year Ended September 30, 2012
Net revenues from production
Third-party sales	$	4,644,356		$	3,369,407
Production costs
Lease operating expense		714,669			672,233
Production taxes		214,127			155,616
Asset retirement obligation accretion		23,186			8,922
		951,982			836,771
Impairment of O&G Properties		3,634,312			-
Depreciation, depletion and amortization		1,846,583			842,571
		(1,788,521	)		1,690,065
Income tax expense		-			573,270
Results of operations from producing activities	$	(1,788,521	)	$	1,116,795

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-19

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

	Fiscal Year Ended September 30, 2013		Fiscal Year Ended September 30, 2012
Property acquisitions
Unproved	$	19,206	$	59,784
Proved		-		-
Exploration		373,731		170,857
Development		1,947,841		6,258,174
Total Costs Incurred	$	2,340,778	$	6,488,815

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.

	September 30, 2013		September 30, 2012
Capitalized costs
Unproved properties	$	61,470	$	1,427,294
Proved properties		12,994,766		9,288,166
		13,056,236		10,715,460
Less: Accumulated DD&A		6,587,955		1,107,060
Net capitalized costs	$	6,468,281	$	9,608,400

Costs Not Being Amortized. The following table sets forth a summary of oil and gas property costs not being amortized at September 30, 2013, 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 to ten years .

	Total		Fiscal Year Ended September 30, 2013			Fiscal Year Ended September 30, 2012
Property acquisition costs	$	-	$	-	$	-
Exploration and development		61,470		-		61,470
Total	$	61,470	$	-	$	61,470

Oil and Gas Reserve Information.    Pressler Consultants, 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, 2013 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.

F-20

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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, 2011		535,810
Revisions of prior estimates		192,386
Purchases of reserves in place		46,557
Production		(48,889	)
September 30, 2012		725,864
Revisions of prior estimates		(555,738	)
Purchases of reserves in place		-
Production		(45,758	)
September 30, 2013		124,368

	September 30, 2013		September 30, 2012
Estimated Quantities of Proved Developed Reserves		124,368		313,617
Estimated Quantities of Proved Undeveloped Reserves		-		412,247

The proved developed reserves estimate of 124,368 net barrels as of September 30, 2013 is a material reduction from that estimated as of last fiscal year end.  Net production of 45,758 barrels accounted for a portion of the reduction, but the balance was due to calculations of reservoir potential that was influenced by further detailed analysis of the producing formations drive systems and the declines in production from certain wells at a greater rate than previously experienced.  The interpretation of 3D seismic during the fourth quarter of fiscal year 2013 provided additional input and helped delineate the field more precisely, resulting in  lowering the estimates of remaining recoverable oil.

Although the Company reported proved undeveloped reserves of 412,247 barrels as of September 30, 2012, the reserve engineers determined this year that such classification was not appropriate due to the faulting system identified in the field, and were thus removed from the report.

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 adjusted for differentials 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-21

VANGUARD ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Standardized Measure of Oil and Gas

	September 30, 2013			September 30, 2012			September 30, 2011
Future cash inflows	$	12,943,629		$	74,669,619		$	50,622,329
Future production costs		(3,557,348	)		(9,364,444	)		(6,273,765	)
Future development costs		(804,500	)		(6,175,000	)		(5,557,500	)
Future income taxes		-			(13,639,715	)		(10,992,652	)
Future net cash flows		8,581,781			45,490,460			27,798,412
Discount of future net cash flows at 10% per annum		(2,104,010	)		(8,509,198	)		(5,107,917	)
Standardized measure of discounted future net cash flows	$	6,477,771		$	36,981,262		$	22,690,495

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, 2013			Fiscal Year Ended September 30, 2012			Fiscal Year Ended September 30, 2011
Sales of oil and gas produced, net of production costs	$	(3,692,374	)	$	(2,532,636	)	$	(1,608,365	)
Purchases of minerals in place		-			-			11,457,772
Net change due to revisions in quantity estimates		(28,337,652	)		17,466,030			-
Net changes in prices and production costs		(11,151,435	)		3,134,171			4,459,237
Accretion of discount before income taxes		3,698,126			2,269,050			454,748
Changes in timing and other		8,979,844			(6,045,848	)		3,379,621
Net change	$	(30,503,491	)	$	14,290,767		$	18,143,013

F-22

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 31, 2013	/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 31, 2013	/s/ Warren Dillard
	Warren Dillard,
	Principal Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATIONS

In connection with the Annual Report of Vanguard Energy Corporation (the "Company") on Form 10-K for the period ending September 30, 2013 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 31, 2013	By:	/s/ Warren Dillard
		Warren Dillard, Principal Executive and Financial Officer

EX-99

Exhibit 99

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11. SUPPLEMENTAL CASH FLOW INFORMATION

12 Months Ended

Sep. 30, 2013

Notes to Financial Statements

11. SUPPLEMENTAL CASH FLOW INFORMATION

	Fiscal Year		Fiscal Year
	Ended		Ended
	September 30, 2013		September 30, 2012
Interest paid	$	1,435,660	$	250,734
Interest capitalized (non-cash)		63,040		350,142
Exchange of 2010 Notes for 2012 Notes		-		3,075,000
Noncash investing and financing activities:
Capital expenditures included in accounts payable		16,591		289,133
Issuance of Series E Warrants to placement agent		-		97,583
Recognition of conversion feature liability		-		670,893
Asset retirement obligations incurred		-		86,386

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CONSOLIDATED STATEMENT OF OPERATIONS (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Revenues
Oil and gas sales	$ 4,644,356	$ 3,369,407
Costs and expenses
Lease operating expense	714,669	672,233
Production taxes	214,127	155,616
Depreciation, depletion and amortization	1,850,814	844,299
Impairment of oil and gas properties	3,634,312	0
Asset retirement obligation accretion	23,186	8,922
General and administrative	1,373,122	1,564,475
Total costs and expenses	7,810,230	3,245,545
Income (loss) from operations	(3,165,874)	123,862
Other income (expense)
Other income	7,386
Interest income	1,340	3,062
Interest expense	(1,864,379)	(1,171,756)
Change in fair value of warrant and conversion feature liabilities	652,765	1,081,371
Change in estimate of participation liability	969,731	(653,057)
Loss on debt extinguishment	0	(410,639)
Total other income (expense)	(233,157)	(1,151,019)
Loss before income taxes	(3,399,031)	(1,027,157)
Provision for income taxes	0	0
Net loss	$ (3,399,031)	$ (1,027,157)
Loss per share – Basic	$ (0.27)	$ (0.09)
Weighted average number of common shares	12,741,512	11,901,830
Loss per share – Diluted	$ (0.27)	$ (0.09)
Weighted average number of common and potential common shares	12,741,512	11,901,830

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4. ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

4. ASSET RETIREMENT OBLIGATIONS

The Company has asset retirement obligations for any wells that 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, 2013			September 30, 2012
Inflation rate		4	%		4	%
Estimated asset life	3.9 years			9.5 years
Credit adjusted risk free interest rate		30	%		18	%

The assumptions used in calculating ARO as of September 30, 2013 were based on data presented in the October 1, 2013 Reserve Report and using the current costs of plugging and abandoning wells.

The following table shows:

Asset retirement obligations at September 30, 2011	$	24,629
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
Additional retirement obligations incurred		(28,290	)
Change in estimate		111,598
Accretion expense		23,186
Settlements		(25,219	)
Asset retirement obligations at September 30, 2013	$	177,685

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10. FAIR VALUE OF FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Sep. 30, 2013

Notes to Financial Statements

Financial Liabilities

			September 30,		September 30,
	Level		2013		2012
Participation liability		3	$	465,551	$	1,573,605
Conversion feature liability		3		-		584,018
Warrant liabilities		3		-		68,746
Total liabilities			$	465,551	$	2,226,369

Liabilities Using Signigicant Unobservable Inputs

	Participation Liability			Conversion Feature Liability			Warrant Liabilities			Total
Balance at September 30, 2012	$	1,573,605		$	584,018		$	68,746		$	2,226,369
Purchases, issuances and settlements		(138,323	)		-			-			(138,323	)
(Gains) losses included in earnings		(969,731	)		(584,018	)		(68,746	)		(1,622,495	)
Balance at September 30, 2013	$	465,551		$	-		$	-		$	465,551

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

12 Months Ended

Sep. 30, 2013

Notes to Financial Statements

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, 2013			Fiscal Year Ended September 30, 2012
Net revenues from production
Third-party sales	$	4,644,356		$	3,369,407
Production costs
Lease operating expense		714,669			672,233
Production taxes		214,127			155,616
Asset retirement obligation accretion		23,186			8,922
		951,982			836,771
Impairment of O&G Properties		3,634,312			-
Depreciation, depletion and amortization		1,846,583			842,571
		(1,788,521)			1,690,065
Income tax expense		-			573,270
Results of operations from producing activities	$	(1,788,521	)	$	1,116,795

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, 2013		Fiscal Year Ended September 30, 2012
Property acquisitions
Unproved	$	19,206	$	59,784
Proved		-		-
Exploration		373,731		170,857
Development		1,947,841		6,258,174
Total Costs Incurred	$	2,340,778	$	6,488,815

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.

	September 30, 2013		September 30, 2012
Capitalized costs
Unproved properties	$	61,470	$	1,427,294
Proved properties		12,994,766		9,288,166
		13,056,236		10,715,460
Less: Accumulated DD&A		6,587,955		1,107,060
Net capitalized costs	$	6,468,281	$	9,608,400

Costs Not Being Amortized. The following table sets forth a summary of oil and gas property costs not being amortized at September 30, 2013, 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 to ten years .

	Total		Fiscal Year Ended September 30, 2013			Fiscal Year Ended September 30, 2012
Property acquisition costs	$	-	$	-	$	-
Exploration and development		61,470		-		61,470
Total	$	61,470	$	-	$	61,470

Oil and Gas Reserve Information.    Pressler Consultants, 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, 2013 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, 2011		535,810
Revisions of prior estimates		192,386
Purchases of reserves in place		46,557
Production		(48,889	)
September 30, 2012		725,864
Revisions of prior estimates		(555,738	)
Purchases of reserves in place		-
Production		(45,758	)
September 30, 2013		124,368

	September 30, 2013		September 30, 2012
Estimated Quantities of Proved Developed Reserves		124,368		313,617
Estimated Quantities of Proved Undeveloped Reserves		-		412,247

The proved developed reserves estimate of 124,368 net barrels as of September 30, 2013 is a material reduction from that estimated as of last fiscal year end.  Net production of 45,758 barrels accounted for a portion of the reduction, but the balance was due to calculations of reservoir potential that was influenced by further detailed analysis of the producing formations drive systems and the declines in production from certain wells at a greater rate than previously experienced.  The interpretation of 3D seismic during the fourth quarter of fiscal year 2013 provided additional input and helped delineate the field more precisely, resulting in  lowering the estimates of remaining recoverable oil.

Although the Company reported proved undeveloped reserves of 412,247 barrels as of September 30, 2012, the reserve engineers determined this year that such classification was not appropriate due to the faulting system identified in the field, and were thus removed from the report.

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 adjusted for differentials 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, 2013			September 30, 2012			September 30, 2011
Future cash inflows	$	12,943,629		$	74,669,619		$	50,622,329
Future production costs		(3,557,348	)		(9,364,444	)		(6,273,765	)
Future development costs		(804,500	)		(6,175,000	)		(5,557,500	)
Future income taxes		-			(13,639,715	)		(10,992,652	)
Future net cash flows		8,581,781			45,490,460			27,798,412
Discount of future net cash flows at 10% per annum		(2,104,010	)		(8,509,198	)		(5,107,917	)
Standardized measure of discounted future net cash flows	$	6,477,771		$	36,981,262		$	22,690,495

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, 2013			Fiscal Year Ended September 30, 2012			Fiscal Year Ended September 30, 2011
Sales of oil and gas produced, net of production costs	$	(3,692,374	)	$	(2,532,636	)	$	(1,608,365	)
Purchases of minerals in place		-			-			11,457,772
Net change due to revisions in quantity estimates		(28,337,652	)		17,466,030			-
Net changes in prices and production costs		(11,151,435	)		3,134,171			4,459,237
Accretion of discount before income taxes		3,698,126			2,269,050			454,748
Changes in timing and other		8,979,844			(6,045,848	)		3,379,621
Net change	$	(30,503,491	)	$	14,290,767		$	18,143,013

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10. FAIR VALUE OF FINANCIAL INSTRUMENTS (Details 1) (USD $)	12 Months Ended
	Sep. 30, 2013
Balance at September 30,2012	$ 2,226,369
Purchases, issuances and settlements	(138,323)
(Gains) losses included in earnings	(1,622,495)
Balance at September 31, 2013	465,551
Participation Liability
Balance at September 30,2012	1,573,605
Purchases, issuances and settlements	(138,323)
(Gains) losses included in earnings	(969,731)
Balance at September 31, 2013	465,551
Conversion Feature Liabilities
Balance at September 30,2012	584,018
Purchases, issuances and settlements	0
(Gains) losses included in earnings	(584,018)
Balance at September 31, 2013	0
Warrant Liabilities
Balance at September 30,2012	68,746
Purchases, issuances and settlements	0
(Gains) losses included in earnings	(68,746)
Balance at September 31, 2013	$ 0

XML

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details Narrative)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Summary Of Significant Accounting Policies Details Narrative
Anti-dilutive shares	19,261,860	19,751,560

XML

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

12 Months Ended

Sep. 30, 2013

Supplemental Information Relating To Oil And Gas Producing Activities Tables

Schedule of operations

	Fiscal Year Ended September 30, 2013			Fiscal Year Ended September 30, 2012
Net revenues from production
Third-party sales	$	4,644,356		$	3,369,407
Production costs
Lease operating expense		714,669			672,233
Production taxes		214,127			155,616
Asset retirement obligation accretion		23,186			8,922
		951,982			836,771
Impairment of O&G Properties		3,634,312			-
Depreciation, depletion and amortization		1,846,583			842,571
		(1,788,521)			1,690,065
Income tax expense		-			573,270
Results of operations from producing activities	$	(1,788,521	)	$	1,116,795

Schedule of development costs

	Fiscal Year Ended September 30, 2013		Fiscal Year Ended September 30, 2012
Property acquisitions
Unproved	$	19,206	$	59,784
Proved		-		-
Exploration		373,731		170,857
Development		1,947,841		6,258,174
Total Costs Incurred	$	2,340,778	$	6,488,815

Schedule of capitalized costs

	September 30, 2013		September 30, 2012
Capitalized costs
Unproved properties	$	61,470	$	1,427,294
Proved properties		12,994,766		9,288,166
		13,056,236		10,715,460
Less: Accumulated DD&A		6,587,955		1,107,060
Net capitalized costs	$	6,468,281	$	9,608,400

Schedule of costs not being amortized

	Total		Fiscal Year Ended September 30, 2013			Fiscal Year Ended September 30, 2012
Property acquisition costs	$	-	$	-	$	-
Exploration and development		61,470		-		61,470
Total	$	61,470	$	-	$	61,470

Schedule of proved oil and gas reserves

Estimated Quantities of Proved Reserves

	Oil
	(Bbls)
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
Revisions of prior estimates		(555,738	)
Purchases of reserves in place		-
Production		(45,758	)
September 30, 2013		124,368

	September 30, 2013		September 30, 2012
Estimated Quantities of Proved Developed Reserves		124,368		313,617
Estimated Quantities of Proved Undeveloped Reserves		-		412,247

Schedule of standardized measure of discounted future net cash flows

Standardized Measure of Oil and Gas

	September 30, 2013			September 30, 2012			September 30, 2011
Future cash inflows	$	12,943,629		$	74,669,619		$	50,622,329
Future production costs		(3,557,348	)		(9,364,444	)		(6,273,765	)
Future development costs		(804,500	)		(6,175,000	)		(5,557,500	)
Future income taxes		-			(13,639,715	)		(10,992,652	)
Future net cash flows		8,581,781			45,490,460			27,798,412
Discount of future net cash flows at 10% per annum		(2,104,010	)		(8,509,198	)		(5,107,917	)
Standardized measure of discounted future net cash flows	$	6,477,771		$	36,981,262		$	22,690,495

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, 2013			Fiscal Year Ended September 30, 2012			Fiscal Year Ended September 30, 2011
Sales of oil and gas produced, net of production costs	$	(3,692,374	)	$	(2,532,636	)	$	(1,608,365	)
Purchases of minerals in place		-			-			11,457,772
Net change due to revisions in quantity estimates		(28,337,652	)		17,466,030			-
Net changes in prices and production costs		(11,151,435	)		3,134,171			4,459,237
Accretion of discount before income taxes		3,698,126			2,269,050			454,748
Changes in timing and other		8,979,844			(6,045,848	)		3,379,621
Net change	$	(30,503,491	)	$	14,290,767		$	18,143,013

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12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES - Standardized Measure (UNAUDITED) (Details 6) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Supplemental Information Relating To Oil And Gas Producing Activities - Standardized Measure Details 6
Sales of oil and gas produced, net of production costs	$ (3,692,374)	$ (2,532,636)	$ (1,608,365)
Purchases of minerals in place	0	0	11,457,772
Net change due to revisions in quantity estimates	(28,337,652)	17,466,030	0
Net changes in prices and production costs	(11,151,435)	3,134,171	4,459,237
Accretion of discount before income taxes	3,698,126	2,269,050	454,748
Changes in timing and other	8,979,844	(6,045,848)	3,379,621
Net change	$ (30,503,491)	$ 14,290,767	$ 18,143,013

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6. INCOME TAXES (Details 2) (USD $)	Sep. 30, 2013	Sep. 30, 2012
Deferred tax assets
Net operating loss carryforwards	$ 3,665,319	$ 2,987,160
Stock-based compensation	222,936	103,367
Deferred tax liability - oil & gas properties	(1,380,769)	(2,319,346)
Participation liability	(273,638)	102,739
Subtotal	2,233,848	873,920
Valuation allowance	(2,233,848)	(873,920)
Net deferred tax asset	$ 0	$ 0

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12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES - Results of operations (UNAUDITED) (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Supplemental Information Relating To Oil And Gas Producing Activities - Results Of Operations Details
Third-party sales	$ 4,644,356	$ 3,369,407
Production costs
Lease operating expense	714,669	672,233
Production taxes	214,127	155,616
Asset retirement obligation accretion	23,186	8,922
Subtotal production costs	951,982	836,771
Impairment of O&G Properties	3,634,312
Depreciation, depletion and amortization	1,846,583	842,571
Total production costs	1,788,521	1,690,065
Income tax expense	0	573,270
Results of operations from producing activities	$ (1,788,521)	$ 1,116,795

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5. LONG-TERM DEBT (Details Narrative) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Long-Term Debt Details Narrative
Warrants exercised	453,322
Convertible Notes Payable	$ 8,254,500
Unamortized Discount on notes	441,116
Interest expense of debt issuance costs and discount	965,748	965,748
Combined effective interest rate	25.10%
Participation Liability Fair Value	465,551	1,573,605
Net profits interest granted expenses	123,312	97,535
Payments under participation arrangement	$ 261,635	$ 375,470

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12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES - Costs Not Being Amortized (UNAUDITED) (Details 3) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Supplemental Information Relating To Oil And Gas Producing Activities - Costs Not Being Amortized Details 3
Property acquisition costs	$ 0
Exploration and development	61,470
Total	61,470
Costs incurred for which costs are not being amortized
Property acquisition costs	0	0
Exploration and development	0	61,470
Total	$ 0	$ 61,470

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11. SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

12 Months Ended

Sep. 30, 2013

Notes to Financial Statements

Supplemental Cash Flow Information

	Fiscal Year		Fiscal Year
	Ended		Ended
	September 30, 2013		September 30, 2012
Interest paid	$	1,435,660	$	250,734
Interest capitalized (non-cash)		63,040		350,142
Exchange of 2010 Notes for 2012 Notes		-		3,075,000
Noncash investing and financing activities:
Capital expenditures included in accounts payable		16,591		289,133
Issuance of Series E Warrants to placement agent		-		97,583
Recognition of conversion feature liability		-		670,893
Asset retirement obligations incurred		-		86,386

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CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT) (USD $)	Common Stock	Additional Paid-In Capital	Accumulated Deficit	Total
Beginning Balance, Amount at Sep. 30, 2011	$ 79	$ 1,866,110	$ (1,227,541)	$ 638,648
Beginning Balance, Shares at Sep. 30, 2011	7,880,822
Stock-based compensation, Shares	60,690
Stock-based compensation		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	48	5,522,204	(2,254,698)	3,267,633
Ending Balance, Shares at Sep. 30, 2012	12,741,512
Stock-based compensation				0
Net loss			(3,399,031)	(3,399,031)
Ending Balance, Amount at Sep. 30, 2013	$ 127	$ 5,522,204	$ (5,653,729)	$ (131,398)
Ending Balance, Shares at Sep. 30, 2013	12,741,512

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2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Sep. 30, 2013

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 used in the ceiling test (Notes 2 and 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.

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.

During the fourth quarter of fiscal year 2013 and based on the October 1, 2013 Reserve Report, the cost ceiling analysis established that the Company’s proved properties required the recording of an impairment reduction. The Company recorded an impairment expense of $3,634,312 \as a result of reductions in estimated proved reserves.  Revised calculations of proved reserves were based on detailed analysis of producing formations drive systems and declines in production from certain wells at a greater rate than previously experienced. The interpretation of 3D seismic during the fiscal fourth quarter of 2013 provided additional input and helped delineate the field more precisely, resulting in limiting the estimates of remaining recoverable oil. The production declines resulted in greater DD&A expense of $919,313 during the fourth quarter.  These adjustments were offset somewhat by a reduction in the Participation Liability of $969,731 resulting from lower estimated net cash flows from certain wells in which outside parties have a 20% net profits interest.

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, 2013 or 2012. 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 12,741,512 for 2013 and 11,901,830 for 2012. The calculation of diluted weighted-average shares outstanding for 2013 and 2012 excludes 19,261,860-shares and 19,751,560 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 2013 and 2012. 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 May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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.

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

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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5. LONG-TERM DEBT

12 Months Ended

Sep. 30, 2013

Notes to Financial Statements

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 bore 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.  

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, 2013, 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 were used to fund an accelerated developmental drilling program in the Company's oil fields located in Southeast Texas and to pay the 2010 Convertible Promissory Notes that remained 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.

The Company’s gross outstanding balance of the 2012 Convertible Promissory Notes was $8,254,500 as of September 30, 2013.  As of September 30, 2013, the unamortized discount on the 2012 Convertible Promissory Notes totaled $441,116.  Interest expense for the amortization of debt issuance costs and discount on the notes was $965,748 and $965,748 for the years ended September 30, 2013 and 2012, respectively.  The effective interest rate of the 2012 Convertible Promissory Notes (net of the participation liability discussed below) was 25.1% as of September 30, 2013.

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 $465,551 as of September 30, 2013 and $1,573,605 as of September 30, 2012. 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, 2013 and 2012 of $123,312 and $97,535, respectively. This amount is reported as interest expense in the statement of operations. The Company also made payments under this arrangement of $261,635 and $375,470 during the years ended September 30, 2013 and 2012, respectively.

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3. OIL AND GAS PROPERTIES

12 Months Ended

Sep. 30, 2013

Notes to Financial Statements

3. OIL AND GAS PROPERTIES

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, 2013, the Company had drilled five 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 $650,000.  As of September 30, 2013, the Company had drilled five 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, 2013. In November 2013, the Company paid $10,000 to extend the agreement, whereby it now has an obligation to commence drilling by June 14, 2014. Subject to the commencement of drilling the first well by June 14, 2014, 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, 2013, 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 had 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.  The original agreement was extended one year providing until January 31, 2014 to commence drilling the first well.  As of September 30, 2013, the Company did not drill any wells on this lease and is not expected to drilling any wells in the foreseeable future.

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.

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, 2013, this amount totaled $12,476 and was repaid in October 2013 from CFO’s production revenues. During the two years ended September 30, 2013, we paid C.F.O., Inc. $470,000 and $763,600 respectively for services provided to us. These amounts included reimbursements for drilling costs advanced by C.F.O., Inc. of $224,722 and $573,533 respectively.

As discussed in Note 2, the Company recorded an impairment expense of $3,634,312 during the year ended September 30, 2013 as a result of reductions in estimated proved reserves.

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12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES - Costs Incurred (UNAUDITED) (Details 1) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Property acquisitions
Unproved	$ 19,206	$ 59,784
Proved	0	0
Exploration	373,731	170,857
Development	1,947,841	6,258,174
Total Costs Incurred	$ 2,340,778	$ 6,488,815

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3. OIL AND GAS PROPERTIES (Details Narrative) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Oil And Gas Properties Details Narrative
Receivable from CFO, Inc. 10% share of capital expenditures	$ 12,476
Amount paid to related party CFO, Inc. for services provided	$ 470,000	$ 763,600

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6. INCOME TAXES (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Income Taxes Details
Current	$ 0	$ 0
Deferred	0	0
Total	$ 0	$ 0

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10. FAIR VALUE OF FINANCIAL INSTRUMENTS (Details) (USD $)	Sep. 30, 2013	Sep. 30, 2012
Notes to Financial Statements
Participation liability (Level 3)	$ 465,551	$ 1,573,605
Conversion feature liability (Level 3)	0	584,018
Warrant liabilities (Level 3)	0	68,746
Total liabilities (Level 3)	$ 465,551	$ 2,226,369

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12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES - Net Cash Flows (UNAUDITED) (Details 5) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Supplemental Information Relating To Oil And Gas Producing Activities - Net Cash Flows Details 5
Future cash inflows	$ 12,943,629	$ 74,669,619	$ 50,622,329
Future production costs	(3,557,348)	(9,364,444)	(6,273,765)
Future development costs	(804,500)	(6,175,000)	(5,557,500)
Future income taxes	0	(13,639,715)	(10,992,652)
Future net cash flows	8,581,781	45,490,460	27,798,412
Discount of future net cash flows at 10% per annum	(2,104,010)	(8,509,198)	(5,107,917)
Standardized measure of discounted future net cash flows	$ 6,477,771	$ 36,981,262	$ 22,690,495

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Sep. 30, 2013	Sep. 30, 2012
Statement of Financial Position [Abstract]
Discount on Note Payable Current portion	$ 0	$ 77,584
Discount on Note Payable	$ 441,132	$ 635,748
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	12,741,512
Common stock, outstanding shares	12,741,512	12,741,512

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8. STOCK-BASED COMPENSATION

12 Months Ended

Sep. 30, 2013

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 Company recognized stock-based compensation expense of $243,731 during 2011 related to the issuance of these options.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Cash flows from operating activities:
Net income	$ (3,399,031)	$ (1,027,157)
Adjustments to reconcile net loss to net cash from operating activities:
Loss on debt extinguishment	0	(410,639)
Change in estimate of participation liability	(969,731)	653,057
Impairment of Oil and Gas Properties	3,634,312	0
Depreciation, depletion and amortization	1,850,814	844,299
Amortization of debt issuance costs	318,712	237,809
Asset retirement obligation accretion	81,275	8,922
Amortization of debt discount	272,200	736,446
Accretion of participation liability	(138,323)	97,535
Stock-based compensation expense	0	59,700
Change in fair value of warrant and conversion feature liabilities	(652,765)	(1,081,371)
Change in operating assets and liabilities:
Accounts receivable	243,866	(358,484)
Other assets	(5,161)	(14,680)
Accounts payable	(284,967)	(54,291)
Other liabilities	(22,518)	(129,341)
Net cash from operating activities	928,683	383,083
Cash flows from investing activities
Purchase of furniture and equipment	(2,452)	(22,480)
Capital expenditures on oil and gas properties	(2,357,368)	(6,113,295)
Net cash from investing activities	(2,359,820)	(6,135,775)
Cash flows from financing activities
Debt issuance costs	0	(813,780)
Equity offering costs	0	(199,849)
Proceeds from issuance of common stock and warrants	0	4,224,000
Proceeds from issuance (repayment) of notes payable	(325,000)	5,179,500
Net cash from financing activities	(325,000)	8,389,871
Net change in cash and cash equivalents	(1,756,137)	2,637,179
Cash and cash equivalents Beginning of period	3,090,422	453,243
Cash and cash equivalents End of period	$ 1,334,285	$ 3,090,422

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CONSOLIDATED BALANCE SHEETS (USD $)	Sep. 30, 2013	Sep. 30, 2012
Statement of Financial Position [Abstract]
Cash and cash equivalents	$ 1,334,285	$ 3,090,422
Accounts receivable	371,765	615,631
Other assets	16,055	6,132
Total current assets	1,722,105	3,712,185
Property and equipment - Oil and gas, on the basis of full cost accounting
Proved properties	12,994,766	9,288,166
Unproved properties and properties under development, not being amortized	61,470	1,427,294
Furniture and equipment	26,946	24,494
Less: accumulated depreciation, depletion and amortization	(6,594,081)	(1,108,956)
Total property and equipment	6,489,101	9,630,998
Debt issuance costs	538,700	857,412
Other assets	10,808	15,570
Total assets	8,760,714	14,216,165
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Accounts payable	113,314	414,873
Other liabilities	322,194	344,712
Current portion of notes payable, net of discount of $0 and $77,584	0	247,416
Current portion of conversion feature liability	0	564
Total current liabilities	435,508	1,007,565
Notes payable, net of discount of $441,132 and $635,748	7,813,368	7,618,752
Participation liability	465,551	1,573,605
Conversion feature liability	0	583,454
Warrant liabilities	0	68,746
Asset retirement obligations	177,685	96,410
Total liabilities	8,892,112	10,948,532
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 shares issued and outstanding	127	127
Additional paid-in capital	5,522,204	5,522,204
Accumulated deficit	(5,653,729)	(2,254,698)
Total stockholders' equity (deficit)	(131,398)	3,267,633
Total liabilities and stockholders' equity (deficit)	$ 8,760,714	$ 14,216,165

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4. ASSET RETIREMENT OBLIGATIONS (Details)	Sep. 30, 2013	Sep. 30, 2012
Asset Retirement Obligations Details
Inflation rate	4.00%	4.00%
Estimated asset life	3 years 10 months 24 days	9 years 6 months
Credit adjusted risk free interest rate	30.00%	18.00%

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9. COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Sep. 30, 2013

Notes to Financial Statements

Schedule of Contractual Obligations

	Total		2014		2015		Thereafter
Convertible notes	$	8,254,500	$	-0-	$	8,254,500		-
Office leases	$	12,900	$	12,900		-		-

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12. INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES - Estimated Quantities of Proved Reserves (UNAUDITED) (Details 4)	12 Months Ended
	Sep. 30, 2013 bbl	Sep. 30, 2012 bbl
Information Relating To Oil And Gas Producing Activities - Estimated Quantities Of Proved Reserves Details 4
Oil Estimated Quantities of Proved Reserves, beginning balance	725,864	535,810
Revisions of prior estimates	(555,738)	192,386
Purchases of reserves in place	0	46,557
Production	(45,758)	(48,889)
Oil Estimated Quantities of Proved Reserves, ending balance	124,368	725,864
Estimated Quantities of Proved Developed Reserves	124,368	313,617
Estimated Quantities of Proved Undeveloped Reserves	0	412,247

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11. SUPPLEMENTAL CASH FLOW INFORMATION (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Supplemental cash flow information:
Interest paid	$ 1,435,660	$ 250,734
Interest capitalized (non-cash)	63,040	350,142
Exchange of 2010 Notes for 2012 Notes	0	3,075,000
Noncash investing and financing activities:
Capital expenditures included in accounts payable	16,591	289,133
Issuance of Series E Warrants to placement agent	0	97,583
Recognition of conversion feature liability	0	670,893
Asset retirement obligations incurred	$ 0	$ 86,386

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7. STOCKHOLDERS EQUITY (Details) (USD $)	Sep. 30, 2013
Series A1
Issuance Date	DECEMBER 1, 2010
Expiration Date	OCTOBER 31, 2014
Exercise Price	$ 4.00
Warrants Outstanding-2013	1,700,000
Warrants Outstanding-2012	1,700,000
Series B1
Issuance Date	DECEMBER 1, 2010
Expiration Date	OCTOBER 31, 2014
Exercise Price	$ 1.20
Warrants Outstanding-2013	340,000
Warrants Outstanding-2012	340,000
Series B2
Issuance Date	DECEMBER 1, 2010
Expiration Date	OCTOBER 31, 2014
Exercise Price	$ 4.00
Warrants Outstanding-2013	170,000
Warrants Outstanding-2012	170,000
Series B3
Issuance Date	DECEMBER 1, 2010
Expiration Date	MARCH 31, 2011
Exercise Price	$ 0.10
Warrants Outstanding-2013	0
Warrants Outstanding-2012	0
Series C
Issuance Date	FEBRUARY 28, 2011
Expiration Date	FEBRUARY 28, 2016
Exercise Price	$ 2.00
Warrants Outstanding-2013	1,500,000
Warrants Outstanding-2012	1,500,000
Series D
Issuance Date	FEBRUARY 28, 2011
Expiration Date	FEBRUARY 28, 2016
Exercise Price	$ 1.20
Warrants Outstanding-2013	150,000
Warrants Outstanding-2012	150,000
Class A
Issuance Date	DECEMBER 2, 2011
Expiration Date	NOVEMBER 29, 2016
Exercise Price	$ 1.50
Warrants Outstanding-2013	4,800,000
Warrants Outstanding-2012	4,800,000
Series E1
Issuance Date	JUNE 29, 2012
Expiration Date	JUNE 15, 2017
Exercise Price	$ 1.55
Warrants Outstanding-2013	296,300
Warrants Outstanding-2012	296,300
Series E2
Issuance Date	JULY 6, 2012
Expiration Date	JUNE 15, 2017
Exercise Price	$ 1.55
Warrants Outstanding-2013	72,500
Warrants Outstanding-2012	72,500
Series E3
Issuance Date	JULY 31, 2012
Expiration Date	JUNE 15, 2017
Exercise Price	$ 1.55
Warrants Outstanding-2013	57,160
Warrants Outstanding-2012	57,160
Series E4
Issuance Date	SEPTEMBER 5, 2012
Expiration Date	JUNE 15, 2017
Exercise Price	$ 1.55
Warrants Outstanding-2013	111,400
Warrants Outstanding-2012	111,400

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9. COMMITMENTS AND CONTINGENCIES (Details) (USD $)	Sep. 30, 2013
Notes to Financial Statements
Convertible notes, 2014	$ 0
Convertible notes, 2015	8,254,500
Convertible notes, thereafter	0
Total convertible notes due	8,254,500
Office leases, 2014	12,900
Office leases, 2015	0
Office leases, thereafter	0
Total office leases payment due	$ 12,900

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7. STOCKHOLDERS EQUITY

12 Months Ended

Sep. 30, 2013

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, 2013.

Warrants—The following table summarizes certain information regarding outstanding warrants as of September 30, 2013 and 2012:

			Exercise		Shares Issuable Upon Exercise of Warrants
Series	Issuance Date	Expiration Date	Price		2013		2012
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		4,800,000
Series E	June 29, 2012	June 15, 2017	$	1.55		296,300		296,300
Series E	July 6, 2012	June 15, 2017	$	1.55		72,500		72,500
Series E	July 31, 2012	June 15, 2017	$	1.55		57,160		57,160
Series E	September 5, 2012	June 15, 2017	$	1.55		111,400		111,400

(1)    Exercised in March 2011.

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4. ASSET RETIREMENT OBLIGATIONS (Details 1) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Asset Retirement Obligations Details 1
Asset retirement obligations at beginning of year	$ 96,410	$ 24,629
Additional retirement obligations incurred	(28,290)	36,959
Changes in estimate	111,598	49,428
Accretion expense	23,186	8,922
Settlements	(25,219)	(23,528)
Asset retirement obligations at ending of year	$ 177,685	$ 96,410

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12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES - Capitalized costs (UNAUDITED) (Details 2) (USD $)	Sep. 30, 2013	Sep. 30, 2012
Capitalized costs
Unproved properties	$ 61,470	$ 1,427,294
Proved properties	12,994,766	9,288,166
Gross	13,056,236	10,715,460
Less: Accumulated DD&A	6,587,955	1,107,060
Net capitalized costs	$ 6,468,281	$ 9,608,400

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10. FAIR VALUE OF FINANCIAL INSTRUMENTS

12 Months Ended

Sep. 30, 2013

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, 2013 and 2012:

			September 30,		September 30,
	Level		2013		2012
Participation liability		3	$	465,551	$	1,573,605
Conversion feature liability		3		-		584,018
Warrant liabilities		3		-		68,746
Total liabilities			$	465,551	$	2,226,369

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, 2012	$	1,573,605		$	584,018		$	68,746		$	2,226,369
Purchases, issuances and settlements		(138,323	)		-			-			(138,323	)
(Gains) losses included in earnings		(969,731	)		(584,018	)		(68,746	)		(1,622,495	)
Balance at September 30, 2013	$	465,551		$	-		$	-		$	465,551

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6. INCOME TAXES

12 Months Ended

Sep. 30, 2013

Notes to Financial Statements

6. INCOME TAXES

The provision for income taxes consists of the following:

	Fiscal Year		Fiscal Year
	Ended		Ended
	September 30, 2013		September 30, 2012
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			Fiscal Year
	Ended			Ended
	September 30, 2013			September 30, 2012
Income tax expense computed at statutory rates	$	(1,137,194	)	$	(349,233	)
Non-deductible items		(220,623	)		(366,608	)
Change in valuation allowance		1,357,817			715,841
Total	$	-		$	-

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

	September 30, 2013			September 30, 2012
Deferred tax assets
Net operating loss carryforwards	$	3,665,319		$	2,987,160
Stock-based compensation		222,936			103,367
Deferred tax liability - oil & gas properties		(1,380,769	)		(2,319,346	)
Participation liability		(273,638	)		102,739
Subtotal	$	2,233,848			873,920
Valuation allowance		(2,233,848	)		(873,920	)
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 $10,800,000 at September 30, 2013 and begin to expire if not utilized in the year 2030.

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1. ORGANIZATION

12 Months Ended

Sep. 30, 2013

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.

In January of 2013, the Company announced that it was seeking ways to accelerate shareholder value.  In that regard, the Company has been investigating the possibility of selling its oil and gas properties in Southeast Texas.  The Company has not received any firm offers for the properties nor have established a price it would consider for them.  If the Company reaches an agreement to sell at a price considered attractive, the net proceeds, after repayment of convertible debt and other liabilities, would be used to acquire new leases in East Texas with strong potential for value creation.  The Company emphasizes that it is not committed to selling any of its properties and, depending on available capital, will continue with its current operating program.

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6. INCOME TAXES (Details 1) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Income Taxes Details 1
Income tax expense computed at statutory rates	$ (1,137,194)	$ (349,233)
Non-deductible items	(220,623)	(366,608)
Change in valuation allowance	1,357,817	715,841
Total	$ 0	$ 0

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2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Sep. 30, 2013

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 used in the ceiling test (Notes 2 and 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.

During the fourth quarter of fiscal year 2013 and based on the October 1, 2013 Reserve Report, the cost ceiling analysis established that the Company’s proved properties required the recording of an impairment reduction. The Company recorded an impairment expense of $3,634,312 \as a result of reductions in estimated proved reserves.  Revised calculations of proved reserves were based on detailed analysis of producing formations drive systems and declines in production from certain wells at a greater rate than previously experienced. The interpretation of 3D seismic during the fiscal fourth quarter of 2013 provided additional input and helped delineate the field more precisely, resulting in limiting the estimates of remaining recoverable oil. The production declines resulted in greater DD&A expense of $919,313 during the fourth quarter.  These adjustments were offset somewhat by a reduction in the Participation Liability of $969,731 resulting from lower estimated net cash flows from certain wells in which outside parties have a 20% net profits interest.

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, 2013 or 2012. 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 12,741,512 for 2013 and 11,901,830 for 2012. The calculation of diluted weighted-average shares outstanding for 2013 and 2012 excludes 19,261,860-shares and 19,751,560 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 2013 and 2012. 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 May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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.

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

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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9. COMMITMENTS AND CONTINGENCIES

12 Months Ended

Sep. 30, 2013

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.  In May 2013 the consulting arrangement were set at $10,000 for the CEO and $-0- for the Chairman.  The Chairman resigned following the May 2013 modification.

Office Lease – The Company leases office space under an operating lease. Rent expense for 2013 and 2012 totaled $72,474 and $81,641, 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, 2013 were as follows:

	Total		2014		2015		Thereafter
Convertible notes	$	8,254,500	$	-0-	$	8,254,500		-
Office leases	$	12,900	$	12,900		-		-

The Company has no contractual capital commitments outstanding at September 30, 2013.  Management estimates the Company will spend approximately $150,000 during fiscal year 2014 for workover of wells in the Batson Dome Field and various other projects.

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7. STOCKHOLDERS EQUITY (Tables)

12 Months Ended

Sep. 30, 2013

Stockholders' equity

Schedule of Warrants

			Exercise		Shares Issuable Upon Exercise of Warrants
Series	Issuance Date	Expiration Date	Price		2013		2012
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		4,800,000
Series E	June 29, 2012	June 15, 2017	$	1.55		296,300		296,300
Series E	July 6, 2012	June 15, 2017	$	1.55		72,500		72,500
Series E	July 31, 2012	June 15, 2017	$	1.55		57,160		57,160
Series E	September 5, 2012	June 15, 2017	$	1.55		111,400		111,400

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4. ASSET RETIREMENT OBLIGATIONS (Tables)

12 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Assumptions for fair value of ARO

	September 30, 2013			September 30, 2012
Inflation rate		4	%		4	%
Estimated asset life	3.9 years			9.5 years
Credit adjusted risk free interest rate		30	%		18	%

SCHEDULE OF ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations at September 30, 2011	$	24,629
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
Additional retirement obligations incurred		(28,290	)
Change in estimate		111,598
Accretion expense		23,186
Settlements		(25,219	)
Asset retirement obligations at September 30, 2013	$	177,685

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Document and Entity Information (USD $)	12 Months Ended
	Sep. 30, 2013	Dec. 15, 2013	Mar. 31, 2013
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, 2013
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			$ 6,170,000
Entity Common Stock, Shares Outstanding		12,741,512
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2013

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6. INCOME TAXES (Tables)

12 Months Ended

Sep. 30, 2013

Income Taxes Tables

Schedule for the provision for income taxes

	Fiscal Year		Fiscal Year
	Ended		Ended
	September 30, 2013		September 30, 2012
Current	$	-	$	-
Deferred		-		-
Total	$	-	$	-

Schedule of income tax reconciliation

	Fiscal Year			Fiscal Year
	Ended			Ended
	September 30, 2013			September 30, 2012
Income tax expense computed at statutory rates	$	(1,137,194	)	$	(349,233	)
Non-deductible items		(220,623	)		(366,608	)
Change in valuation allowance		1,357,817			715,841
Total	$	-		$	-

Schedule of components of the net deferred tax asset

	September 30, 2013			September 30, 2012
Deferred tax assets
Net operating loss carryforwards	$	3,665,319		$	2,987,160
Stock-based compensation		222,936			103,367
Deferred tax liability - oil & gas properties		(1,380,769	)		(2,319,346	)
Participation liability		(273,638	)		102,739
Subtotal	$	2,233,848			873,920
Valuation allowance		(2,233,848	)		(873,920	)
Net deferred tax asset	$	-		$	-