VICTORY OILFIELD TECH, INC. - Annual Report: 2010 (Form 10-K)

Unassociated Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

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

	For the fiscal year ended December 31, 2010

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

	For the transition period from ____________ to _____________

Commission file number: 002-76219NY

VICTORY ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Nevada (State or other jurisdiction of incorporation or organization)		87-0564472 (I.R.S. Employer Identification No.)

20341 Irvine Avenue, Newport Beach, California (Address of principal executive offices)		92660 (Zip Code)

Registrant’s telephone number, including area code: (714) 480-0305 Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: Common Stock, $0.001 par value (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. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required 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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ¨ No x

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer ¨		Accelerated Filer ¨

Non-Accelerated Filer (do not check if Smaller Reporting Company) ¨		Smaller Reporting Company x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, computed by reference to the closing price of such stock on May 12, 2011 was approximately $2,171,000 based on the closing price of such stock and such date of $0.0195.

The number of shares outstanding of the Registrant’s common stock, $0.001 par value, as of May 11, 2011 was 136,719,608.

VICTORY ENERGY CORPORATION

ANNUAL REPORT ON

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2010

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business		3
Item 1A.	Risk Factors.		10
Item 1B.	Unresolved Staff Comments.		22
Item 2.	Properties.		22
Item 3.	Legal Proceedings.		27
Item 4.	Removed and Reserved		28

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.		29
Item 6.	Selected Financial Data.		32
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.		32
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.		38
Item 8.	Financial Statements and Supplementary Data.		39
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.		39
Item 9A	Controls and Procedures.		40
Item 9B.	Other Information.		40

PART III
Item 10.	Directors, Executive Officers and Corporate Governance.		41
Item 11.	Executive Compensation.		43
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.		46
Item 13.	Certain Relationships and Related Transactions, and Director Independence.		47
Item 14.	Principal Accounting Fees and Services.		49

PART IV
Item 15.	Exhibits and Financial Statement Schedules		50

Explanatory Note

On March 30, 2011 Victory Energy Corporation filed its 2009 Annual Report on Form 10-K including audited financial statements for the 2007 (restated), 2008 and 2009 fiscal years and unaudited quarterly financial statements for 2008 (restated) and 2009. The 2009 Annual Report on Form 10-K included all material information that would have been available and disclosed in its December 31, 2009, 2008 and 2007 Forms 10-K and interim 2009 and 2008 Forms 10-Q had they been timely filed as well as all material subsequent events through the date of filing. As a consequence, much of this 2010 Annual Report on Form 10-K reiterates much of the same material already presented in the 2009 Annual Report on Form 10-K.

Cautionary Notice Regarding Forward Looking Statements

Victory Energy Corporation desires to take advantage of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. This report contains a number of forward-looking statements that reflect management's current views and expectations with respect to business, strategies, future results and events and financial performance. All statements made in this Annual Report other than statements of historical fact, including statements that address operating performance, events or developments that management expects or anticipates will or may occur in the future, including statements related to revenues, cash flow, profitability, adequacy of funds from operations, statements expressing general optimism about future operating results and non-historical information, are forward looking statements. In particular, the words “believe,” “expect,” “intend,” “anticipate,” “estimate,” “may,” “will,” variations of such words, and similar expressions identify forward-looking statements, but are not the exclusive means of identifying such statements and their absence does not mean that the statement is not forward-looking.

Readers should not place undue reliance on these forward-looking statements, which are based on management’s current expectations and projections about future events, are not guarantees of future performance, are subject to risks, uncertainties and assumptions and apply only as of the date of this report. Victory Energy Corporation’s actual results, performance or achievements could differ materially from the results expressed in, or implied by, these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below in “Risk Factors” as well as those discussed elsewhere in this report, and the risks discussed in press releases and other communications to stockholders issued by Victory Energy Corporation from time to time which attempt to advise interested parties of the risks and factors that may affect the business. Except as may be required under the federal securities laws, Victory Energy Corporation undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Part I

Item 1. Business

General Background

Victory Energy Corporation, formerly known as All Things, Inc. (“Victory,” the “Company” or “We”), was organized under the laws of the State of Nevada on January 7, 1982. We were formed for the purpose of engaging in all lawful businesses. We are currently authorized to issue 490,000,000 shares of $0.001 par value common stock.

On March 21, 1985, we changed our name to New Environmental Technologies Corporation, and on April 28, 2003 we changed our name again to Victory Capital Holdings Corporation. On May 3, 2006, we changed our name to Victory Energy Corporation.

Copies of the initial Articles of Incorporation of our Company and the Certificates of Amendment to the Articles of Incorporation are incorporated by reference. See Part IV Item 15.

From our inception to 2004, we had no material business operations. In 2004, we began the search for the acquisition of assets, property or businesses that could benefit the Company and its shareholders.

Management determined that we should focus on projects in the oil and gas industry. Based upon a belief that this industry is an economically viable sector in which to conduct business operations, we targeted specific prospects and joint venture opportunities engaged in the drilling for oil and natural gas.

Company Overview

We are an oil and natural gas exploration, development and production (E&P) company geographically focused on the onshore United States. We are headquartered in Newport Beach, California. We seek to identify proven development prospects, conduct thorough geological and engineering evaluations and then target suitable farm-in partners for long term development of additional prospects. Our operational focus is the acquisition, through the most cost effective means possible, of production or near production of oil and natural gas field assets. Targeted fields generally have existing wells that are often past primary energy recovery, but whose enhancement through secondary and possibly tertiary recovery methods could revitalize them. Targeted fields also have the availability of additional drilling sites. Our goal is to have an inventory of existing wells to enhance and a number of new drilling sites to maintain growth, while increasing reserves and cash flow.

Depending upon the specific terms and development opportunities of a given oil & gas project, we acquire our interests directly or indirectly through joint ventures, partnerships, or joint operating agreements. We currently serve as managing partner of Aurora Energy Partners, a Texas General Partnership (“Aurora”). We own a fifteen percent (15%) general partnership interest in Aurora and share fifteen percent (15%) in the profits and losses of Aurora. We manage all business operations of Aurora including project analysis, acquisition, finance and accounting, drilling operations, and production management.

During 2009 and 2008, Aurora acquired a one hundred percent (100%) working interest and seventy-four percent (74%) net revenue interest in eleven (11) natural gas wells. Aurora also acquired a fifty percent (50%) working interest and thirty-seven percent (37%) net revenue interest in two (2) gas wells. These gas wells are located in Crockett County, Texas. As of the date of this filing, nine of the wells have been completed and are in production.

On December 31, 2010, we directly acquired a one (1) year option to acquire leases and available oil and gas mineral rights within a 1,000 acre tract on South Padre Island, Texas. Depending on the financing needs to develop this project, we may develop this project directly or indirectly through Aurora or other joint venture partners.

On February 18, 2011, Aurora entered into an agreement to acquire a 2.5% working interest in a producing wildcat well that is producing 300 barrels of oil per day (BOPD) and 100 thousand cubic feet (MCF) of natural gas per day.

Business Strategy

Our business strategy includes the acquisition, financing, improvement, exploration, and development drilling of existing and/or new oil and gas opportunities.

Acquisition and Financing

During our acquisition stage we identify, assess, and evaluate the geological opportunities of low risk, mature fields that have proven and probable reserves. During 2009 and 2008, Aurora secured $11.4 million of funding from one of Aurora’s general partners, James Capital Energy, LLC (“JCE”). JCE is an Alaska limited liability company that is comprised of forty (40) accredited investors. JCE is managed by Dr. Ronald Zamber, a major shareholder of the Company and member of our board of directors. The capital raised through Aurora was earmarked for the Adams-Baggett natural gas project in Crockett County, Texas. A portion of the funds we used to initially acquire interests in six (6) producing wells at a cost of $3.0 million. The remaining $8.1 million of capital was earmarked for a drilling program to develop additional natural gas wells on the Adams-Baggett ranch.

In buying existing oil and natural gas fields, we set out to extensively study the fields, the formations in which oil and natural gas were found, the history of sales from the field and the history of all surrounding fields, and their production. From this information, a better assessment could be made as to the value of the target property.

Improvement of Existing Wells

In collaboration with our business partners, we seek to improve the performance of our fields by investing in low risk work-over programs on existing wells and monetization of significant upside in work-over wells on already proved assets. We also seek to develop proved non-producing wells (PDNP) into proved developed and producing (PDP) assets with no associated exploration risk.

Currently, we have active operations on Aurora’s fields located in Crockett County, Texas and our fields located in South Padre Island, Texas. Aurora has working interests and net revenue interests in nine (9) productive natural gas wells in the Crockett County field in Texas. We began a four (4)-well work over program in the Crockett County project. We recently purchased an option to acquire leases and mineral interest on South Padre Island, Texas. Our management is extensively studying the fields, the formations in which oil and natural gas may be found, the history of sales from the field and the history of all surrounding fields, and their production. From this information, an assessment can be made as to the value of the target property.

Development Drilling on Proved Assets

Another aspect of our business strategy is to execute infill drilling of Aurora’s oil and gas assets and our oil and gas assets. We seek to develop proved undeveloped (PUD’s) assets into PDP assets with no associated exploration risk.

All of the planned development drilling and enhancements assume that we are successful in securing our 2011 funding that will support a drilling and development budget. The actual number of wells drilled will vary depending upon various factors, including the availability and cost of drilling rigs, any working interest partner issues, our ability to raise additional capital, the success of our drilling programs, weather delays and other factors. Our ability to drill the number of wells we have budgeted for 2011 and 2012 is heavily dependent upon the timely access to oilfield services, particularly drilling rigs.

We also seek to expand our oil and natural gas reserves through the acquisition of fields, wells, or working interests in oil and gas assets.

Current Operations

Adams-Baggett Ranch, Crockett County, Texas

In January, 2008, Aurora acquired mineral right leases on the Adams-Baggett Ranch that is located in southwest Texas. Aurora initially acquired a fifty percent (50%) working interest and thirty-seven percent (37%) net revenue interest in six (6) producing gas wells at this location. In October 2008, Aurora acquired the remaining fifty percent (50%) working interest and thirty-seven percent (37%) net revenue interest in three (3) of these producing gas wells. In February 2009, Aurora acquired an additional fifty percent (50%) working interest and thirty-seven percent (37%) net revenue interest in one (1) of these producing gas wells. During 2008, we drilled and brought into production three (3) gas wells at this location. We also drilled four (4) additional wells that have not been completed as of the date of this report.

Aurora currently holds net revenue interests in nine (9) producing natural gas wells within the boundary of our currently held acreage. Four (4) additional wells have been drilled and are awaiting completion plans.

Padre Island Gas Fields, South Padre Island, Texas

On December 20, 2010, we entered into an option agreement to acquire an oil and gas lease in a 1,000 acre tract of South Padre Island, Texas. The option gives us exclusive right to acquire an oil and gas lease at the property for a period of one (1) year. Under the terms of the option, we will have full access to the land and may conduct geophysical or seismic testing of the land to ascertain the potential gas reserves

Padre Island Gas Field is located 15 miles north of Port Isabel, Texas. The field was discovered by Gulf Oil in 1960 and produced approximately 3.8 billion cubic feet (BCF) to October 1, 1980 from two Miocene Sands at 6,000 feet and 6,500 feet. Three (3) wellbores are currently shut-in and will be re-evaluated for activation. These wells were producing 14 million cubic feet (MMCF) per month when they were shut-in in 2002. One of the wells could be recompleted at 6,000 feet, and another could be put on pump to flow gas up the backside. In addition, there is a 4-foot gas sand on water at 1,712 feet indicated by well logs and a gas core that has not been previously produced. A formation test of this sand had immediate pressure of 465 psi.

A successful completion of this sand could have potential of 2 BCF proved undeveloped reserves (PUD) of natural gas. There is an intact pipeline available to transport gas to onshore facilities. Compression facilities could be installed to further recover gas. The wells are located on Padre Island and are accessible by road.

The optioned property contains three (3) previously producing gas wells and the delivery infrastructure to transport the gas to onshore facilities. We will have a one hundred percent (100%) working interest and seventy-five percent (75%) net revenue interest in this project.

Jones County, Texas Oil Well Interest

On February 28, 2011, Aurora acquired a two and a half (2.5) percent working interest in the Young No. 1 well located in Jones County, Texas. This “Glen Thomas” wildcat well was completed and tested January 14, 2011. The well is now on production at a rate of 300 (BOPD) and 100 MCF of natural gas per day. Interest assignment of this production is effective February 1, 2011, with Aurora expecting revenue during the second quarter of 2011. Oil production is from the Caddo formation. The agreement also includes a working interest of no less than 1.5 percent in a sixty-four (64) square mile (40,966 acres) 3-D seismic imaging supported development area. The well operator, C.O. Energy, envisions drilling one to two wells per month until the targeted area is fully developed. Aurora maintains a thirty (30)-day first right of refusal to participate in each development well.

Pecos County, Texas Oil and Gas Well Interest

On April 14, 2011, Aurora acquired a working interest in the University 6 #1 oil and gas prospect (“Tunis Creek”). Aurora acquired the prospect from well known Midland Texas-based V-F Petroleum Inc., who will also be the operator of the well. Aurora acquired a five percent (5%) working interest and a three and three quarters percent (3.75%) net revenue interest and anticipates this well to spud near the end of April. The Tunis Creek prospect is located twenty-five miles due east of Fort Stockton, Texas in eastern Pecos County, and is surrounded by significant hydrocarbon shows in all three targeted horizons. The prospect has been permitted to test the Wichita, Albany, Wolfcamp and Ellenburger formations. The operator plans to drill the Tunis Creek prospect to a total depth of 7,500 feet. The 1,600 acre lease comprises two sections of block 20, University Lands survey.

Just over two thirds of a mile to the east-northeast in the same section, Midwest Oil opened the one-well Renaud & Tunstill field. That Midwest Oil well (1 University) is down dip of the Tunis Creek prospect and was completed in 1960. The 1 University well pumped 248 barrels of 43-degree oil per day from the Ellenburger formation at 6,810-95 feet. Log tops at the 7,004 feet discovery included the Wolfcamp at 4,834 feet, Simpson at 5,940 feet, Connell at 6,439 feet and Ellenburger at 6,795 feet. Production for the 1 University well through 1965 totaled over 20 thousand barrels of oil and 1.65 million cubic feet of casinghead gas.

Alwan West Natural Gas Prospect

On April 25, 2011, Aurora acquired a working interest in the Alwan West natural gas prospect. The Alwan West prospect will be the largest natural gas well drilled by us to date. This prospect’s potential reservoir covers an area of 175 acres. It has a reserve potential of 8.75 BCF of natural gas and 43.75 thousand barrels of gas condensate. The reserve potential is based on 50 feet of reservoir sand, one million cubic feet per acre-foot of natural gas and five barrels per million cubic feet of gas condensate. These reserve estimates are for the first Yegua sand only, which is the primary objective, and do not include potential in the secondary objectives.

The Alwan West prospect is located in far western Wharton County, Texas, near the Jackson County line. There are two natural gas lines that cross the lease within 1,000 feet of the proposed location. Aurora acquired the prospect, which includes a five percent (5%) working interest and a 3.8% net revenue interest (NRI), from Miramar Petroleum, Inc. of Corpus Christi, Texas, who will be the operator and who also owns a significant working interest in the well. The well is anticipated to spud in early June of this year.

This area produces from the Frio and Yegua (Oligocene) formations. The lease area is surrounded on all sides by gas condensate production. The first Yegua sand is the primary objective. Secondary objectives are the Frio and second Yegua sand. Alwan West lies on strike between two Yegua fields, Lost Fork (one mile west) and AVO Grande (3,000 feet east). Lost Fork has produced over 42 BCF, while AVO Grande has produced 7 BCF of natural gas. Both of these fields are stratigraphic traps, as is the Alwan West prospect.

Distribution Methods

Each of our fields that produce oil distributes all of the oil that it produces through one purchaser for each field. We do not have a written agreement with some of these oil purchasers. These oil purchasers pick up oil from our tanks and pay us according to market prices at the time the oil is picked up at our tanks. There is significant demand for oil and there are several companies in our operating areas that purchase oil from small oil producers.

Each of our fields that produce natural gas distributes all of the natural gas that it produces through one purchaser for each field. We have distribution agreements with these natural gas purchasers that provide us a tap into a distribution line of a natural gas distribution company. We are to be paid for our natural gas at either a market price at the beginning of the month or market price at the time of delivery, less any transportation cost charged by the natural gas distribution company. These charges can range widely from 2 percent to 20 percent or more of the market value of the natural gas depending on the availability of competition and other factors.

Competitive Business Conditions

We encounter competition from other oil and natural gas companies in all areas of our operations. Because of record high prices for oil and natural gas, there are many companies competing for the leasehold rights to good oil and natural gas prospects. And, because so many companies are again exploring for oil and natural gas, there is often a shortage of equipment available to do drilling and work over projects. Many of our competitors are large, well-established companies that have been engaged in the oil and natural gas business for much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. We may not be able to conduct our operations, evaluate and select properties and consummate transactions successfully in this highly competitive environment.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

Source and Availability of Raw Materials

We have no significant raw materials. However, we make use of numerous oil field service companies in the drilling and work over of wells. We currently operate in areas where there are numerous oil field service and drilling companies that are available to us.

Dependence on One or a Few Customers

There is a ready market for the sale of crude oil and natural gas. Each of our fields currently sells all of its oil production to one purchaser for each field and all of its natural gas production to one purchaser for each field. However, because alternate purchasers of oil and natural gas are readily available at similar prices, we believe that the loss of any of our purchasers would not have a material adverse effect on our financial results.

We sold oil and natural gas production representing more than 10% of our oil and natural gas revenues as follows:

	Years Ended December 31:
	2010		2009		2008
Eagle Rock Natural Gas, LLC (1)		100%		100%	100%

(1)	We do not have a formal purchase agreement with this customer, but sell production on a month-to-month basis at spot prices adjusted for field differentials

Government Regulations

Our facilities in the United States are subject to federal, state and local environmental laws and regulations. Compliance with these provisions has not had, and we do not expect such compliance to have, any material adverse effect upon our capital expenditures, net earnings or competitive position.

Regulation of Transportation of Oil

Sales of crude oil, condensate, natural gas and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Regulation of Transportation and Sale of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act. The Decontrol Act removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

The FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued Order No. 636 and a series of related orders to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states on shore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase our costs of getting gas to point of sale locations.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of Production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. Such regulations govern conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental, Health and Safety Regulation

Our operations are subject to stringent and complex federal, state, local and provincial laws and regulations governing environmental protection, health and safety, including the discharge of materials into the environment. These laws and regulations may, among other things:

	·	require the acquisition of various permits before drilling commences;

	·	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production and transportation activities;

	·	limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

	·	require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs.

The following is a summary of the material existing environmental, health and safety laws and regulations to which our business operations are subject.

Waste handling. The Resource Conservation and Recovery Act, or “RCRA”, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or “EPA”, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA”, also known as the Superfund law, imposes joint and several liabilities, without regard to fault or legality of conduct, in connection with the release of a hazardous substance into the environment. Persons potentially liable under CERCLA include the current or former owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance to the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources and the costs of certain health studies. In addition, it is not uncommon for 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.

We own and lease, and may in the future operate, numerous properties that have been used for oil and natural gas exploitation and production for many years. Hazardous substances may have been released on, at or under the properties owned, leased or operated by us, or on, at or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been or are operated by third parties or by previous owners or operators whose handling, treatment and disposal of hazardous substances were not under our control. These properties and the substances disposed or released on, at or under them may be subject to CERCLA, RCRA and analogous state laws. In certain circumstances, we could be responsible for the removal of previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination. In addition, federal and state trustees can also seek substantial compensation for damages to natural resources resulting from spills or releases.

Water discharges. The Federal Water Pollution Control Act, or the “Clean Water Act”, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil and other substances generated by our operations, into waters of the United States or state waters. Under these laws, the discharge of pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The Safe Drinking Water Act, or “SDWA”, and analogous state laws impose requirements relating to underground injection activities. Under these laws, the EPA and state environmental agencies have adopted regulations relating to permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as prohibitions against the migration of injected fluids into underground sources of drinking water.

Air emissions. The Federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, EPA and certain states have developed and continue to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and analogous state laws and regulations.

The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has not acted upon recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and natural gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations.

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or “NEPA”. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All exploration and production activities on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects on federal lands.

Health safety and disclosure regulation. We are subject to the requirements of the federal Occupational Safety and Health Act, or “OSHA” and comparable state statutes. The OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and similar state statutes require that we organize and/or disclose information about hazardous materials stored, used or produced in our operations.

We expect to incur capital and other expenditures related to environmental compliance. Although we believe that our compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial position or results of operation.

Intellectual Property

We do not have any trademarks, patents or other intellectual property.

Employees

As of December 31, 2010, we had no employees. During 2010, we contracted for the services of our CFO and CEO through Miranda & Associates, A Professional Accountancy Corporation. During 2010, we contracted for gas well operator services from Remuda Operating Company and Cambrian Management, LTD. At December 31, 2010, we were contracting for gas well operator services only with Cambrian Management, LTD

In January, 2011, the Company hired two executive officers reporting to the CEO and opened an office in Austin, Texas.

Item 1A. Risk Factors

We have incurred operating losses, expect continued losses and may never achieve profitability.

We have operated at a loss each year since inception. Net losses for the fiscal years ended December 31, 2010 and 2009, were $432,713 and $385,139, respectively. We have a history of modest revenues, have not been profitable and expect continued near term losses. Historically, we have relied upon cash from financing activities to fund substantially all of the cash requirements of our activities and have incurred significant losses and experienced negative cash flow. We cannot predict when we will become profitable or if we ever will become profitable, we may continue to incur losses for an indeterminate period of time and may never achieve or sustain profitability. An extended period of losses and negative cash flow may prevent us from successfully producing gas or developing additional gas wells and operating or expanding our business. As a result of our financial condition, our independent auditors have issued a report questioning our ability to continue as a going concern.

Our losses have resulted largely from the negligence and/or financial malfeasance of our former drilling contractor and other related parties, and from costs associated with our administrative activities. We expect our operating expenses to increase as a result of our planned operational activities. Since we have no significant operating history, we cannot assure you that our business will ever become profitable or that we will ever generate sufficient revenues to meet our expenses and support our planned activities. Even if we are able to achieve profitability, we may be unable to sustain or increase our profitability on a quarterly or annual basis.

Our ability to generate net income will be strongly affected by, among other factors, our ability to successfully drill undeveloped reserves as well as the market price of crude oil and natural gas. If we are unsuccessful in drilling productive wells or the market price of crude oil and natural gas declines, we may report additional losses in the future. Consequently, future losses may adversely affect our business, prospects, financial condition, results of operations and cash flows.

Our independent auditors have issued a report questioning our ability to continue as a going concern.

The report of our independent auditors contained in our financial statements for the years ended December 31, 2010 and 2009, includes a paragraph that explains that we have incurred substantial losses. These reports will raise substantial doubt about our ability to continue as a going concern. Reports of independent auditors questioning a company’s ability to continue as a going concern are generally viewed unfavorably by analysts and investors. This report may make it difficult for us to raise additional debt or equity financing necessary to continue the development of our oil and gas projects.

A decline in the price of our common stock could affect our ability to raise further working capital and adversely impact our operations.

A prolonged decline in the price of our common stock could result in a reduction in the liquidity of our common stock and a reduction in our ability to raise capital. Because our operations have been primarily financed through the sale of equity securities, a decline in the price of our common stock could be especially detrimental to our liquidity and our continued operations. Any reduction in our ability to raise equity capital in the future would force us to reallocate funds from other planned uses and would have a significant negative effect on our business plans and operations, including our ability to develop new projects and continue our current operations. If our stock price declines, we may not be able to raise additional capital or generate funds from operations sufficient to meet our obligations.

If we are not successful in continuing to grow our business, then we may have to scale back or even cease our ongoing business operations.

Our success is significantly dependent on a successful acquisition, drilling, completion and production program. We may be unable to locate recoverable reserves or operate on a profitable basis. If our business plan is not successful, and we are not able to operate profitably, investors may lose some or all of their investment in us.

Trading of our stock may be restricted by the SEC's "Penny Stock" regulations which may limit a stockholder's ability to buy and sell our stock.

The U.S. Securities and Exchange Commission has adopted regulations that generally define "penny stock" to be any equity security that has a market price (as defined) less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities are covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers or "accredited investors." The term "accredited investor" refers generally to institutions with assets in excess of $5,000,000 or individuals with a net worth in excess of $1,000,000 or annual income exceeding $200,000 or $300,000 jointly with his or her spouse. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC that provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer's account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer's confirmation. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from these rules; the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser's written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability of broker-dealers to trade our securities. We believe that the penny stock rules discourage investor interest in and limit the marketability of, our common stock.

NASD sales practice requirements may also limit a stockholder’s ability to buy and sell our stock.

In addition to the “penny stock” rules described above, the NASD has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, the NASD believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. The NASD requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.

Trading in our common shares has been volatile, making it more difficult for our stockholders to sell their shares or liquidate their investments with predictability.

Our common shares are currently quoted on the OTC Markets. The trading price of our common shares has been subject to wide fluctuations. Trading prices of our common shares may fluctuate in response to a number of factors, many of which will be beyond our control. The stock market has generally experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of companies with no current business operation. There can be no assurance that trading prices and price earnings ratios previously experienced by our common shares will be matched or maintained. These broad market and industry factors may adversely affect the market price of our common shares, regardless of our operating performance. In the past, following periods of volatility in the market price of a company's securities, securities class-action litigation has often been instituted. Such litigation, if instituted, could result in substantial costs for us and a diversion of management's attention and resources.

Our securities are considered highly speculative.

Our securities must be considered highly speculative, generally because of the nature of our business and the early stage of our exploration and development operations. We are engaged in the business of exploring and, if warranted, developing commercial reserves of oil and gas. Our properties are in the exploration stage only and are without known reserves of oil and gas. Accordingly, we have neither generated any material revenues nor realized a profit from our operations to date and there is little likelihood that we will generate any material revenues or realize any profits in the short term. Any profitability in the future from our business will be dependent upon locating and developing economic reserves of oil and gas, which itself is subject to numerous risk factors as set forth herein. Since we have not generated any material revenues, we expect that we will need to raise additional monies through the sale of our equity securities or debt in order to continue our business operations.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

On December 15, 2009, the U.S. Environmental Protection Agency, or EPA, published its findings that emissions of carbon dioxide, or CO2, methane, and other greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the Federal Clean Air Act. The EPA has adopted two sets of regulations under the existing Clean Air Act that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. In addition, in April 2010, the EPA proposed to expand its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. If the proposed rule is finalized as proposed, reporting of GHG emissions from such facilities would be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. The adoptions of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirement also could adversely affect demand for the oil and natural gas that we produce.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is a process used by oil and natural gas exploration and production operators in the completion or re-working of certain oil and natural gas wells, whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate natural gas and, to a lesser extent, oil production. This process is typically regulated by state oil and natural gas agencies and has not been subject to Federal regulation. However, due to concerns that hydraulic fracturing may adversely affect drinking water supplies, the EPA has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, and a committee of the U.S. House of Representatives has commenced its own investigation into hydraulic fracturing practices. Additionally, legislation has been introduced in Congress to amend the Federal Safe Drinking Water Act to subject hydraulic fracturing processes to regulation under that Act and to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. If enacted, such a provision could require hydraulic fracturing activities to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping requirement, and meet plugging and abandonment requirements. In unrelated oil spill legislation being considered by the U.S. Senate in the aftermath of the April 2010 Macondo well release in the Gulf of Mexico, Senate Majority Leader Harry Reid has added a requirement that natural gas drillers disclose the chemicals that are pumped into the ground as part of the hydraulic fracturing process. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. Adoption of legislation or of any implementing regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on our exploration and production activities, which could make it more difficult to perform hydraulic fracturing, resulting in reduced amounts of oil and natural gas being produced, as well as increase our costs of compliance and doing business.

The current global financial crisis and uncertainty in global economic conditions may have significant negative effects on our liquidity and financial condition.

The global financial and credit crisis has and may continue to impact our liquidity and financial condition. The continued credit crisis and related turmoil in the global financial system may have a material impact on our liquidity and our financial condition, and we may ultimately face major challenges if conditions in the financial markets do not improve. Our ability to access the capital markets or borrow money may be restricted at a time when we would like, or need, to raise capital, which could have an adverse impact on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. Additionally, the current economic situation could lead to reduced demand for natural gas and oil, or further reductions in the prices of natural gas and oil, or both, which could have a negative impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of the current financial crisis cannot be predicted, it may have a material adverse effect on our future liquidity, results of operations and financial condition.

We have substantial capital requirements that, if not met, may hinder operations.

We have and expect to continue to have substantial capital needs as a result of our active exploration, development, and acquisition programs. We expect that additional external financing will be required in the future to fund our growth. We may not be able to obtain additional financing, and we have no financing under existing or new credit facilities and these may not be available in the future. Without additional capital resources, we may be forced to limit or defer our planned natural gas and oil exploration and development program and this will adversely affect the recoverability and ultimate value of our natural gas and oil properties, in turn negatively affecting our business, financial condition, and results of operations.

Natural gas and oil prices are highly volatile, and lower prices will negatively affect our financial results.

Our revenue, profitability, cash flow, oil and natural gas reserves value, future growth, and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of natural gas and oil. Historically, the markets for natural gas and oil have been volatile, and those markets are likely to continue to be volatile in the future. It is impossible to predict future natural gas and oil price movements with certainty. Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty, and a variety of additional factors beyond our control. These factors include:

the level of consumer product demand;

the domestic and foreign supply of oil and natural gas;

overall economic conditions;

weather conditions;

domestic and foreign governmental regulations and taxes;

the price and availability of alternative fuels;

political conditions in or affecting oil and natural gas producing regions;

the level and price of foreign imports of oil and liquefied natural gas; and

the ability of the members of the Organization of Petroleum Exporting Countries and other state controlled oil

companies to agree upon and maintain oil price and production controls.

Declines in natural gas and oil prices may materially adversely affect our financial condition, liquidity, and ability to finance planned capital expenditures and results of operations and may reduce the amount of oil and natural gas that we can produce economically.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our success largely depends on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control; including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are a common risk that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling operations, including the following:

delays imposed by or resulting from compliance with regulatory requirements;

pressure or irregularities in geological formations;

	·	shortages of or delays in obtaining equipment and qualified personnel;

	·	equipment failures or accidents;

adverse weather conditions;

reductions in oil and natural gas prices; and

oil and natural gas property title problems.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reported reserves. In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires that economic assumptions be made about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices received, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reported reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Our drilling prospects are in various stages of evaluation. There is no way to predict in advance of drilling and testing whether any particular drilling prospect will yield oil or natural gas in sufficient quantities to recover drilling and completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

The near-term focus of our development activities will be concentrated in three core asset areas, which exposes us to risks associated with prospect concentration. The relative concentration of our near-term activities in three core asset areas means that any impairments or material reductions in the expected size of the reserves attributable to our wells, any material harm to the producing reservoirs or associated surface facilities from which these wells produce or any significant governmental regulation with respect to any of these fields, including curtailment of production or interruption of transportation of production, could have a material adverse effect on our financial condition and results of operations.

Seismic studies do not guarantee that hydrocarbons are present or, if present, will produce in economic quantities.

We may rely on seismic studies to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or if present will produce in economic quantities.

We depend on successful exploration, development and acquisitions to maintain revenue in the future.

In general, the volume of production from natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent that we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. Additionally, the business of exploring for, developing, or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired. In addition, we may be required to find partners for any future exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we will be adversely affected.

Our future acquisitions may yield revenues and/or production that vary significantly from our projections.

In acquiring producing properties we assess the recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities and other factors relating to such properties. Our assessments are necessarily inexact and their accuracy is inherently uncertain. Our review of a subject property in connection with our acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities.

We may not inspect every well, and we may not be able to identify structural and environmental problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial condition and future results of operations.

We cannot assure you that:

we will be able to identify desirable natural gas and oil prospects and acquire leasehold or other

ownership interests in such prospects at a desirable price;

any completed, currently planned, or future acquisitions of ownership interests in natural gas and oil

prospects will include prospects that contain proved natural gas or oil reserves;

we will have the ability to develop prospects which contain proven natural gas or oil reserves;

we will have the financial ability to consummate additional acquisitions of ownership interests in

natural gas and oil prospects or to develop the prospects which we acquire to the point of production; or

we will be able to consummate such additional acquisitions on terms favorable to us.

Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has specifically identified and preliminarily scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These scheduled drilling locations represent a significant component of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

We may experience difficulty in achieving and managing future growth.

Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:

our ability to obtain leases or options on properties;

our ability to acquire geological & geophysical data;

our ability to identify and acquire new development prospects;

	·	our ability to develop existing prospects;

	·	our ability to continue to retain and attract skilled personnel;

our ability to maintain or enter into new relationships with project partners and independent contractors;

the results of our drilling program;

hydrocarbon prices; and

our access to capital.

We may not be successful in upgrading our technical, operations, and administrative resources or in increasing our ability to internally provide certain of the services currently provided by outside sources, and we may not be able to maintain or enter into new relationships with project partners and independent contractors. Our inability to achieve or manage growth may adversely affect our financial condition and results of operations.

We face strong competition from other natural gas and oil companies.

We encounter competition from other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proved properties. Our competitors include major integrated natural gas and oil companies and numerous independent natural gas and oil companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies that have been engaged in the natural gas and oil business much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. These companies may be able to pay more for productive natural gas and oil properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. We may not be able to conduct our operations, evaluate, and select suitable properties and consummate transactions successfully in this highly competitive environment.

Our business may suffer if we lose our Chairman, CEO, and CFO.

Our success will be dependent on our ability to continue to employ and retain experienced skilled personnel. We depend to a large extent on the services of Robert J. Miranda, our Chairman, Chief Executive Officer and Chief Financial Officer. Mr. Miranda has been managing the turnaround of the Company and is extremely valuable to the overall management of the Company. Although we have entered into an engagement agreement with Mr. Miranda’s firm, Miranda & Associates, the agreement does not guarantee the service of Mr. Miranda for a specified period of time. The loss of Mr. Miranda could significantly delay or prevent the achievement of our business objectives and adversely affect our business, financial condition and results of operations.

The unavailability or high cost of drilling rigs, equipment, supplies or personnel could affect adversely our ability to execute on a timely basis our exploration and development plans within budget, which could have a material adverse effect on our financial condition and results of operations.

Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or affect adversely our exploration and development operations, which could have a material adverse effect on our financial condition and results of operations. Demand for drilling rigs, equipment, supplies, and personnel are currently very high in the areas in which we operate. An increase in drilling activity in the areas in which we operate could further increase the cost and decrease the availability of necessary drilling rigs, equipment, supplies and personnel.

We cannot control activities on properties that we do not operate and are unable to ensure their proper operation and profitability.

We may not operate certain of the properties in the future in which we obtain an interest. As a result, we would have a limited ability to exercise influence over, and control the risks associated with, the operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator’s:

timing and amount of capital expenditures;

expertise and financial resources;

inclusion of other participants in drilling wells; and

use of technology.

The marketability of our natural gas production depends on facilities that we typically do not own or control, which could result in a curtailment of production and revenues.

The marketability of our natural gas production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. We generally deliver natural gas through gas gathering systems and gas pipelines that we may not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our gas may be interrupted due to capacity constraints on the applicable system, due to maintenance or repair of the system, or for other reasons as dictated by the particular agreements. Our ability to produce and market natural gas on a commercial basis could be harmed by any significant change in the cost or availability of such markets, systems or pipelines.

We may not be able to keep pace with technological developments in our industry.

The natural gas and oil industry is characterized by rapid and significant technological advancements and introduction of new products and services which utilize new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other natural gas and oil companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we are able to. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, and results of operations could be materially adversely affected.

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting the trading value of our securities.

Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. Because our properties serve as collateral for advances under our existing credit facility, a write down in the carrying values of our properties could require us to repay debt earlier than would otherwise be required. A write-down would also constitute a non-cash charge to earnings. It is likely that the effect of such a write-down could also negatively impact the trading price of our securities.

We account for our oil and gas properties using the successful efforts method of accounting. Under this method, all development costs and acquisition costs of proved properties are capitalized and amortized on a units-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively. Costs of drilling exploratory wells are initially capitalized, but charged to expenses if and when a well is determined to be unsuccessful. We evaluate impairment of our proved oil and gas properties whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and gas prices are low or volatile. In addition, write-downs would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

The exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with such governmental regulations. Matters subject to regulation include:

natural disasters;

permits for drilling operations;

drilling and plugging bonds;

reports concerning operations;

the spacing and density of wells;

unitization and pooling of properties;

environmental maintenance and cleanup of drill sites and surface facilities; and

Protection of human health.

From time to time, regulatory agencies have also imposed price controls and limitations on production by restricting the rate of flow of natural gas and oil wells below actual production capacity in order to conserve supplies of natural gas and oil.

Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.

Our operations may cause us to incur substantial liabilities for failure to comply with environmental laws and regulations.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit or other authorizations before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, require permitting or authorization for release of pollutants into the environment, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, areas inhabited by endangered or threatened species, and other protected areas, and impose substantial liabilities for pollution resulting from historical and current operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition as well as on the industry in general. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities, some of which may be owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business.

Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas may have several adverse affects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

The financial condition of our operators could negatively impact our ability to collect revenues from operations.

We may not operate all of the properties in the future in which we have working interests. In the event that an operator of our properties experiences financial difficulties, this may negatively impact our ability to receive payments for our share of net production that we are entitled to under our contractual arrangements with such operator. While we seek to minimize such risk by structuring our contractual arrangements to provide for production payments to be made directly to us by first purchasers of the hydrocarbons, there can be no assurances that we can do so in all situations covering our non-operated properties.

We may not have enough insurance to cover all of the risks that we face and operations of prospects in which we participate may not maintain or may fail to obtain adequate insurance.

In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. The impacts of Hurricanes Katrina, Rita and Ike have resulted in escalating insurance costs and less favorable coverage terms.

Oil and natural gas operations are subject to particular hazards incident to the drilling and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. We do not operate all of the properties in which we have an interest. In the projects in which we own a non-operating interest directly or own an equity interest in a limited partnership which in turn owns a non- operating interest, the operator for the prospect maintains insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event that is not fully covered by insurance could result in the loss of our total investment in a particular prospect which could have a material adverse effect on our financial condition and results of operations.

Terrorist attacks aimed at our energy operations could adversely affect our business.

The continued threat of terrorism and the impact of military and other government action have led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or the financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected our oil and natural gas operations to increased risks. Any future terrorist attack on our facilities, those of our customers, the infrastructure we depend on for transportation of our products, and, in some cases, those of other energy companies, could have a material adverse effect on our business.

Any failure to meet our debt obligations could harm our business, financial condition, results of operations or cash flows.

We face significant interest expenses as a result of our outstanding notes and we are in default on an unsecured note payable to Wells Fargo Bank that has an unpaid balance of $68,667 as of December 31, 2010. We have arranged an informal payment agreement with the lender to continue paying $2,200 monthly toward the balance owed on this loan. However, the lender has called the loan and may not extend credit terms beyond an additional six months. Our ability to generate cash flows from operations and to make scheduled payments on our indebtedness, including the notes, will depend on our future financial performance. Our future performance will be affected by a range of economic, competitive, legislative, operating and other business factors, many of which we cannot control, such as general economic and financial conditions in our industry or the economy at large. A significant reduction in operating cash flows resulting from changes in economic conditions, increased competition, or other events could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations and prospects and our ability to service our debt, including the notes, and other obligations.

If we are unable to service our indebtedness, we will be forced to adopt an alternative strategy that may include actions such as reducing or delaying acquisitions and capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking equity capital. We cannot assure you that any of these alternative strategies could be effected on satisfactory terms, if at all, or that they would yield sufficient funds to make required payments of interest on and principal of our debt in the future, including payments on the notes, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and impair our liquidity. Failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms.

We may issue additional shares of capital stock that could adversely affect holders of shares of our common stock and, as a result, holders of our notes convertible into shares of common stock.

Our board of directors is authorized to issue additional classes or series of shares of our capital stock without any action on the part of our stockholders. Our board of directors also has the power, without stockholder approval, to set the terms of any such classes or series of shares of our capital stock that may be issued, including voting rights, dividend rights, conversion features, preferences over shares of our existing class of common stock with respect to dividends or if we liquidate, dissolve or wind up our business and other terms. If we issue shares of our capital stock in the future that have preference over shares of our existing class of common stock with respect to the payment of dividends or upon our liquidation, dissolution or winding up, or if we issue shares of capital stock with voting rights that dilute the voting power of shares of our existing class of common stock, the rights of holders of shares of our common stock or the trading price of shares of our common stock and, as a result, the market value of the notes convertible into shares of common stock could be adversely affected.

The market price of our common stock may be volatile.

As we are in the early stages of being a publicly traded stock, the trading price of our common stock and the price at which we may sell common stock in the future are subject to large fluctuations in response to any of the following:

limited trading volume in our common stock;

quarterly variations in operating results;

our involvement in litigation;

general financial market conditions;

the prices of natural gas and oil;

announcements by us and our competitors;

our liquidity;

our ability to raise additional funds;

changes in government regulations; and

other events.

Moreover, our common stock does not have substantial trading volume. As a result, relatively small trades of our common stock may have a significant impact on the price of our common stock and, therefore, may contribute to the price volatility of our common stock.

Because of the possibility of limited trading volume of our common stock and the price volatility of our common stock, you may be unable to sell your shares of our common stock when you desire or at the price you desire. The inability to sell your shares of our common stock in a declining market because of such illiquidity or at a price you desire may substantially increase your risk of loss.

We have not previously paid cash dividends on the shares of our common stock and do not anticipate doing so in the foreseeable future.

We have not in the past paid any cash dividends on the shares of our common stock and do not anticipate that we will pay any cash dividends on our common stock in the foreseeable future. Any future decision to pay a dividend on our common stock and the amount of any dividend paid, if permitted, will be made at the discretion of our board of directors.

If we fail to meet our payment obligations under our secured indebtedness, the note holders could foreclose on and acquire control of our assets.

The lenders under the 10% Senior Secured Convertible Debentures have a lien on substantially all our assets. As a result of this lien, if we fail to meet our payments or other obligations under this secured indebtedness, the note holders will be entitled to foreclose on our assets and liquidate those assets. As a result, you may lose a portion of or the entire value of your investment.

Our results of operations could be adversely affected as a result of impairments of drilling costs and other intangible assets.

In connection with the acquisition of producing gas wells and the drilling of additional gas wells, Aurora has approximately $11.4 million of investments in gas leases, tangible and intangible drilling costs. While we provide that our drilling costs be depleted over the estimated productive reserves of the gas wells, these assets must also be tested at least annually for impairment. Management makes certain estimates and assumptions when determining the fair value of net assets and liabilities, including, among other things, an assessment of market conditions, projected cash flows, investment rates, cost of capital and growth rates, which could significantly impact the reported value of drilling costs and other intangible assets. Fair value is determined using a combination of the discounted cash flow, market multiple and market capitalization valuation approaches. Absent any impairment indicators, we perform our impairment tests annually during the fourth quarter. Any future impairment, including impairments of the carrying values of drilling costs and other intangible assets, would negatively impact our results of operations for the period in which the impairment is recognized.

Pending litigation may place a severe financial burden on our resources and the outcome of the litigation may not be favorable to the Company.

We are currently defending two lawsuits filed against us by landowners for trespass. We are prosecuting a lawsuit against our former drilling contractor former operator, and other related parties. We are also prosecuting a lawsuit against our former independent auditor. The outcome of this pending litigation is uncertain and we may incur substantial legal fees to defend and prosecute these lawsuits.

Our plan to recover a substantial portion of our assets is dependent on our ability to obtain additional drilling sites from the Adams-Baggett Ranch landowners at favorable option prices.

Aurora is currently negotiating with the landowner to secure proper title to its gas leases and obtain fifty (50) to one hundred (100) future drilling sites at favorable pricing to the Company. These negotiations are based on allegations made by us against the landowners that title to our leases was defective and, thus, the landowner owes us restitution. There is no assurance that these negotiations will be successful thereby potentially impeding our ability to execute on our business turnaround plan.

The absence of current, publicly-available information about our Company can affect the market for our common stock.

On March 30, 2011 Victory Energy Corporation filed its 2009 Annual Report on Form 10-K including audited financial statements for the 2007 (restated), 2008 and 2009 fiscal years and unaudited quarterly financial statements for 2008 (restated) and 2009. In addition, we provide very limited information about our Company to the public through other sources. The absence of current, publicly-available information makes it difficult for the marketplace to make an informed investment decision about our common stock. As a result, market makers, brokers, analysts and investors cannot adequately evaluate our Company which leads to a less active trading market in our common stock. Additionally, the absence of current, publicly-available information concerning our Company can affect the ability of certain restricted shareholders to trade their shares further limiting the market activity of our common stock. These factors can also contribute to a depressed price for our common stock.

Item 1B. Unresolved Staff Comments

None

Item 2. Properties

Office Space Leases.

On January 25, 2011, we entered into a one (1)-year lease of approximately 1,200 square feet of executive office space located in Austin, Texas. The lease commenced on January 25, 2011, and expires on January 31, 2012. The monthly lease cost is $1,750.

Adams-Baggett Ranch, Crockett County, Texas.

Aurora currently holds net revenue interest in nine (9) producing natural gas wells within the boundary of our currently held acreage. Four (4) additional wells have been drilled and are awaiting completion plans. Current interest and first production dates for these wells are as follows:

Well Name	Working Interest			Revenue Interest			Net Revenue Interest (NRI)			Beginning Production Date	Date(s) Interests Acquired by Aurora
Adams #127-11		100	%		74	%		74	%	April 1, 2007	January 1 and October 3, 2008
Adams #127-12		100	%		74	%		74	%	April 1, 2007	January 1 and October 3, 2008
Adams #127-13		100	%		74	%		74	%	August 1, 2007	January 1 and October 3, 2008
Adams #127-14		100	%		74	%		74	%	October 1, 2007	January 1, 2008 and February 28, 2009
Adams #127-15		50	%		37	%		37	%	December 1, 2007	January 1, 2008
Adams #155-2		50	%		37	%		37	%	December 1, 2007	January 1, 2008
Adams #166-8		100	%		74	%		74	%	May 1, 2008	May 1, 2008
Adams #166-9		100	%		74	%		74	%	May 1, 2008	May 1, 2008
Adams #115-8		100	%		74	%		74	%	September 1, 2008	September 1, 2008

Canyon sandstones are the primary hydrocarbon target within this prospect and they form a prolific low-permeability gas play located in the famous Val Verde Basin of Southwest Texas.

Natural gas from the Canyon Sandstone generally receives a twenty percent (20%) or more premiums in price above the standard market price for natural gas due to its higher BTU content per cubic foot.

The Canyon Sandstone gas play is part of the large prolific Adams-Baggett Canyon Sandstone gas field. The Canyon Sandstone formation is found at a depth of 4,300 feet to 4,900 feet. Initial flow test for these wells is approximately 250,000 cubic feet of gas per day per well. The average life span of a Canyon Sandstone gas well is approximately 30 years, the decline production curve starting during the second year.

These Canyon intervals are composed of thinly interbedded sandstone and mudstone, which formed in slope and basin depositional systems. The more tabular Ozona interval occupies a basin-floor position adjacent to the south margins of the Ozona Arch and the Central Basin Platform.

Padre Island Gas Fields, South Padre Island, Texas.

Padre Island Gas Field is located 15 miles north of Port Isabel, Texas. The field was discovered by Gulf Oil in 1960 and produced approximately 3.8 BCF to October 1, 1980 from two Miocene Sands at 6,000 feet and 6,500 feet. Three (3) wellbores are currently shut-in and will be re-evaluated for activation. These wells were producing 14 MCF per month when they were shut-in in 2002. One of the wells could be recompleted at 6,000 feet, and another could be put on pump to flow gas up the backside. In addition, there is a 4-foot gas sand on water at 1,712 feet indicated by well logs and a gas core that has not been previously produced. A formation test of this sand had immediate pressure of 465 psi.

A successful completion of this sand could have potential of 2 BCF PUD of natural gas. There is an intact pipeline available to transport gas to onshore facilities. Compression facilities could be installed to further recover gas. The wells are located on Padre Island and are accessible by road.

The optioned property contains three (3) previously producing gas wells and the delivery infrastructure to transport the gas to onshore facilities. The Company will have a one hundred percent (100%) working interest and seventy-five percent (75%) net revenue interest in this project.

Jones County, Texas Oil Well Interest

On February 28, 2011, Aurora acquired a 2.5 percent working interest in the Young No. 1 well located in Jones County, Texas. This "Glen Thomas" wildcat well was completed and tested January 14, 2011. The well is now on production at a rate of 300 barrels of oil per day (BOPD) and 100 MCF of natural gas per day. Interest assignment of this production is effective February 1, 2011, with Aurora expecting revenue during the second quarter of 2011. Oil production is from the Caddo formation. The agreement also includes a working interest of no less than 1.5 percent in a sixty-four (64) square mile (40,966 acres) 3-D seismic imaging supported development area. The well operator, C.O. Energy, envisions drilling one to two wells per month until the targeted area is fully developed. Aurora maintains a thirty (30) day first right of refusal to participate in each development well.

Pecos County, Texas Oil and Gas Well Interest

Alwan West Natural Gas Prospect

Developed and Undeveloped Lease Acreage

The following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31, 2010. “Developed Acreage” refers to acreage on which wells have been drilled or completed to a point that would permit production of oil and natural gas in commercial quantities. “Undeveloped Acreage” refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and natural gas in commercial quantities whether or not the acreage contains proved reserves.

As of December 31, 2010	Average Working		Developed Acreage				Undeveloped Acreage				Total Acreage
	Interest		Gross		Net		Gross		Net		Gross		Net
Adams-Baggett Ranch, TX		100%		180		160		80		80		260		240
South Padre Island, TX		100%		—		—		100		100		—		—
Total				180		160		180		180		260		240

Summary of Oil and Gas Reserves as of Year-End 2010 and 2009

The reserves as of December 31, 2010 were derived from reserve estimates prepared by an independent reserve engineer, Mr. James Nicolson. James A. Nicholson is an engineering consultant who specializes in preparing reservoir studies, reserve estimates, and property evaluations. Mr. Nicolson, a Registered Professional Engineer, is a member of the Society of Petroleum Engineers. He is former chairman of the Permian Basin Oil & Gas Recovery Conference. He holds a PhD ME from the University of Texas at Austin, an MSME from the University of Texas at Austin, and a BSME from Lamar University.

The reserve reports prepared by Mr. Nicolson were reviewed and approved by our independent consultants, including a geologist and an oil & gas operations professional. The PV-10 value was derived using average prices throughout the calendar year, discounted at 10% per annum on a pretax basis, and is not intended to represent the current market value of the estimated oil and natural gas reserves owned by us.

Proved Developed Reserves

The following table sets forth our estimated net proved oil and natural gas reserves and the PV-10 value of such reserves as of December 31, 2010.

	2010
Oil and condensate (Bbls)	$	—
Natural gas (MMcf)		709.7
PV-10 Value	$	981,080

(1) The PV 10% Value as of December 31, is pre-tax and was determined by using the average of the preceding, 12-month-first-of-month product prices, which were $6.08 per MCF for gas pursuant to SEC guidelines. Management believes that the presentation of PV-10 value may be considered a non-GAAP financial measure. Therefore, we have included a reconciliation of the most directly comparable GAAP financial measure (standard measure of discounted net cash flows in Note 2 below). Management believes that the presentation of PV-10 value provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because many factors that are unique to each individual company may impact the amount of future income taxes to be paid, the use of the pre-tax measure provides greater comparability when evaluating companies. It is relevant and useful to investors for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies.

(2) Management also uses this pre-tax measure when assessing the potential return on investment related to its oil and natural gas properties and in evaluating acquisition candidates. The PV-10 value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of the estimated oil and natural gas reserves owned by us. The PV-10 value should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

Productive Wells

Productive wells are producing wells or wells capable of production. This does not include water source wells, water injection wells or water disposal wells. Productive wells do not include any wells in the process of being drilled and completed that are not yet capable of production, but does include old productive wells that are currently shut-in, because they are still capable of production. The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2010.

	2010
	Gross		Net
Natural Gas		9		8
Oil		-		-
Totals		9		8

Technologies Used in Establishing Proved Reserves in 2010

Our proved reserves in 2010 were based on estimates generated through the integration of available and appropriate data, utilizing well established technologies that have been demonstrated in the field to yield repeatable and consistent results.

Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements, including high-quality 2-D and 3-D seismic data, calibrated with available well control. Where applicable, surface geological information was also utilized. The tools used to interpret the data included proprietary seismic processing software, proprietary reservoir modeling and simulation software, and commercially available data analysis packages.

Proved Undeveloped Reserves

At December 31, 2010, our proved undeveloped reserves were none.

Oil and Gas Production, Production Prices and Production Costs

A. Oil and Gas Production

The table below summarizes production by final product sold and by geographic area as of December 31, 2010, 2009 and 2008.

	2010		2009		2008
Crude oil and natural gas production
United States (natural gas only, thousand cubic feet)		90,971,000		106,469,000		139,949,000

Total crude oil and natural gas liquids production		90,971,000		106,469,000		139,949,000

Natural gas production available for sale

United States (natural gas only, thousand cubic feet)		709,700,000		748,700,000		824,460,000

Total natural gas production available for sale		709,700,000		748,700,000		824,460,000

Sales Prices and Production Costs

The table below summarizes average sales prices and average production costs by geographic area and by product type for the years ended December 31, 2010, 2009 and 2008.

	United
	States		Total
During 2010
Average Sales Prices
Crude Oil and NGL, per barrel	none		none
Natural gas, per thousand cubic feet	$	0.0067	$	0.0067
Average Production Costs
Crude Oil and NGL, per barrel	none		none
Natural gas, per thousand cubic feet	$	0.0039	$	0.0039

During 2009
Average Sales Prices
Crude Oil and NGL, per barrel	none		none
Natural gas, per thousand cubic feet	$	0.0047	$	0.0047
Average Production Costs
Crude Oil and NGL, per barrel	none		none
Natural gas, per thousand cubic feet	$	0.0016	$	0.0016

During 2008
Average Sales Prices
Crude Oil and NGL, per barrel		none		none
Natural gas, per thousand cubic feet	$	0.0100	$	0.0100
Average Production Costs		none		none
Crude Oil and NGL, per barrel
Natural gas, per thousand cubic feet	$	0.0067	$	0.0067

Drilling and Other Exploratory and Development Activities

The table below summarizes the number of net productive and dry exploratory wells and net productive and dry development wells drilled by geographic area as of December 31, 2010, 2009 and 2008.

	2010	2009	2008
Net Productive Exploratory Wells Drilled
United States	none	none	none

Total productive exploratory wells drilled	none	none	none
Net Dry Exploratory Wells Drilled
United States	none	none	none

Total dry exploratory wells drilled	none	none	none
Net Productive Development Wells Drilled
United States	none	none	3

Total productive development wells drilled	none	none	3
Net Dry Development Wells Drilled
United States	none	0.5	10

Total dry development wells drilled (1)	none	0.5	10

(1)

During 2009, we incurred drilling costs on development wells of $290,665 and $4,942,579, respectively. We subsequently discovered that these drilling funds had been misappropriated. These funds were expensed as “Loss from Malfeasance” during 2009 and 2008. Based upon the contract drilling cost of $500,000 per well, we have estimated the number of dry productive wells that were supposed to have been drilled for the amount of funds incurred.

Present Activities

The table below summarizes the number of wells in the process of being drilled by geographic area as of December 31, 2010.

Wells Drilling	December 31, 2010
	Gross	Net
United States	none	None

Total gross and net wells drilling	none	None

Item 3. Legal Proceedings

We are subject to litigation and claims that have arisen in the ordinary course of business, the majority of which have resulted from our thorough restructuring and turnaround efforts. Many of these claims have been resolved. Management believes individually such litigation and claims will not have a material adverse impact on our financial position or our results of operations but these matters are subject to inherent uncertainties and management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position and the results of operations for the period in which the effect becomes reasonably estimable.

The following describes the material legal action by and against the Company.

Victory Energy Corporation vs. Jim Dial, Remuda Operating Company, and Jon Fullenkamp

Victory Energy Corporation and James Capital Energy, LLC filed a lawsuit in Midland County, Texas, under Case No. CV-47230, against Jim Dial, Jon Fullenkamp, Remuda Operating Company and other parties related to Jim Dial. Defendant Jon Fullenkamp is our former CEO and a former member of our board of directors. The lawsuit alleges fraud, breach of fiduciary duty, and other claims that Victory and JCE allege against these parties. This lawsuit seeks to recover damages in excess of $10.0 million, plus punitive damages.

On December 9, 2010, the Superior Court for the State of Texas entered a final judgment against the following defendants: Jim Dial; 1st Texas Natural Gas Company, Inc.; Universal Energy Resources, Inc.; Grifco International, Inc.; and Precision Drilling & Exploration, Inc. The court held that each of these defendants knowingly and intentionally perpetuated a fraud on the plaintiffs. Additionally, the court found that each defendant breached their contract with the plaintiffs, breached their fiduciary duty to the plaintiffs, and committed acts in violation of the Texas Oil and Gas Proceeds Payment Act.

The final judgment awards us and James Capital Energy, LLC, the plaintiffs, compensatory damages against five of the defendants in the amount of $5.6 million, jointly. The court also awarded punitive damages against each of these defendants in the amount of $2.2 million per defendant, for a total punitive damage award of $11.2 million. Additionally, the court awarded the plaintiffs pre-judgment interest and attorney fees.

Since the entering of the final judgment, we have not recovered any monies from the defendants. We intend to pursue available collection efforts to recover under the judgment in the event the defendants do not voluntary make payment as awarded.

On March 24, 2011 the Company, James Capital Energy, LLC and other related parties entered into a comprehensive Settlement Agreement with Jon Fullenkamp. Under the Settlement Agreement, Victory agreed to i) dismiss Jon Fullenkamp from the Texas lawsuit with prejudice, ii) provide him with a general release from all acts related thereto, and iii) pay him $30,000 over 70 days. In turn, Jon Fullenkamp agreed to i) dismiss with prejudice the lawsuit he filed against the Company and others in California; ii) transfer to Victory 2,000,000 shares of Victory preferred stock; iii) transfer to Victory 400,000 warrants for Victory common stock; iv) transfer to James Capital Energy, LLC 16,144,563 shares of Victory common stock; v) voluntarily appear for his deposition to discuss events that occurred at the Adams-Baggett Ranch; vi) waive the claim he had to the $430,000 severance payment under the May 15, 2009 Separation Agreement; and vii) provide Victory James Capital Energy, LLC and other related parties with a general release.

We intend to continue to pursue our claims against the remaining defendants, Remuda Operating Company, Ozona Natural Gas, LLC, Taylor Drilling, and Ronnie Taylor.

Oz Gas Corporation vs. Universal Energy Resources, Inc., et al

We are an Intervener in a case pending in Crockett County, Texas under Case No. 08-04-07047-CV, and styled Oz Gas Corporation vs. Universal Energy Resources, Inc., et al, in which the plaintiff is seeking to establish ownership of the 155-2 well on the grounds that the well was illegally drilled on property belonging to the plaintiff. We intervened in this action to protect our interests in the 155-2 well and to recover our share of suspended money now being held in the court’s registry. On information and belief the court is holding funds in excess of $100,000 from the 155-2 well pending the outcome of this action.

Jon Fullenkamp vs. Victory Energy Corporation, et. al.

On November 25, 2009, Jon Fullenkamp filed a lawsuit in California against us, James Capital Energy, LLC, Bob Miranda, Ron Zamber, Tom Konz and other parties alleging fraud, breach of contract, libel, slander and other claims. The plaintiff, Jon Fullenkamp, is our former CEO and a former member of our board of directors. On August 11, 2010, Mr. Fullenkamp filed an amended complaint, which alleged additional causes of action. After several successful challenges to the complaint based on procedural grounds, on February 17, 2011, the Court finally accepted Jon Fullenkamp’s third amended complaint. . Subsequent thereto, and before any of the defendants in the action had to file a responsive pleading, the Company and other related parties entered into a comprehensive Settlement Agreement that resolved this matter. Under the Settlement Agreement, Victory agreed to i) dismiss Jon Fullenkamp from the Texas lawsuit with prejudice, ii) provide him with a general release from all acts related thereto, and iii) pay him $30,000 over 70 days. In turn, Jon Fullenkamp agreed to i) dismiss with prejudice the California lawsuit; ii) transfer to Victory 2,000,000 shares of Victory preferred stock; iii) transfer to Victory 400,000 warrants for Victory common stock; iv) transfer to James Capital Energy, LLC 16,144,563 shares of Victory common stock; v) voluntarily appear for his deposition to discuss events that occurred at the Adams-Baggett Ranch; vi) waive the claim he had to the $430,000 severance payment under the May 15, 2009 Separation Agreement; and vii) provide Victory James Capital Energy, LLC and other related parties with a general release.

Perry Howell, et. al. vs. Victory Energy Corporation, et.al.

On September 6, 2010, we were named in a lawsuit, together with our operator, Cambrian Management, Ltd. (“Cambrian”), pending in Midland, Texas under Case No. 10-09-07213. The plaintiffs allege that we, along with other defendants, were trespassers on their land and drilled a well (#115-8) on land belonging to the plaintiffs. The plaintiffs are claiming trespass and unjust enrichment because of the drilling of the well #115-8.

Discovery is ongoing in this matter and a trial date has not been set at this time. We, along with Cambrian, are in the process of completing some title work to decide how to proceed in this case. If we are not victorious in this case, we risk losing our investment in the well #115-8.

Victory Energy Corporation vs. John Kinross-Kennedy, CPA

On March 18, 2011, we filed a lawsuit against our former independent auditor, John Kinross-Kennedy, CPA, for professional negligence in the audits of our 2006 through 2007 financial statements, and the preparation of our 2008 Quarterly Reports on Forms 10-Q. The lawsuit seeks compensatory damages, costs of suit, and other relief as may be deemed just and proper by the Court.

Item 4. (Removed and Reserved).

Part II

Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer

Our common stock is currently quoted on the OTC Markets under the symbol “VYEY.” The following table sets forth the high and low bid information for each quarter for the years ended December 31, 2010 and 2009. The information reflects prices between dealers, and does not include retail markup, markdown, or commission, and may not represent actual transactions.

		Bid Prices
Fiscal Year Ended December 31,	Period	High		Low
2009	First Quarter	$	0.01	$	0.004
	Second Quarter	$	0.009	$	0.003
	Third Quarter	$	0.006	$	0.003
	Fourth Quarter	$	0.005	$	0.003

2010	First Quarter	$	0.005	$	0.002
	Second Quarter	$	0.005	$	0.001
	Third Quarter	$	0.005	$	0.002
	Fourth Quarter	$	0.008	$	0.002

Holders

The following table shows the number of holders of record and the number of common shares outstanding as of December 31, 2010 and 2009 as determined from the records of our transfer agent and does not include beneficial owners of common stock whose shares are held in the names of various security brokers, dealers, and registered clearing agencies.

	December 31,
	2010		2009
Holders of Record		1,295		1,016
Common Shares Outstanding		136,719,608		136,719,608

The transfer agent for our common stock is Transfer Online, Inc., 512 SE Salmon Street, Portland, Oregon 97214.

Dividend Policy

We have not paid any cash dividends on our common stock and do not expect to do so in the foreseeable future. We intend to apply our earnings, if any, in expanding our operations and related activities. The payment of cash dividends in the future will be at the discretion of the board of directors and will depend upon such factors as earnings levels, capital requirements, our financial condition and other factors deemed relevant by the board of directors.

Recent Sales of Unregistered Securities

On January 29, 2010, we agreed to issue warrants to purchase a total of 300,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services. Of these warrants, each board member is to receive warrants to purchase 100,000 shares. These warrants were issued by us to the individuals on December 31, 2010.

On February 26, 2010, we agreed to issue warrants to purchase a total of 300,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services. Of these warrants, each board member is to receive warrants to purchase 100,000 shares. These warrants were issued by us to the individuals on December 31, 2010.

On March 31, 2010, we agreed to issue warrants to purchase a total of 300,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services. Of these warrants, each board member is to receive warrants to purchase 100,000 shares. These warrants were issued by us to the individuals on December 31, 2010.

On April 30, 2010, we agreed to issue warrants to purchase a total of 300,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services. Of these warrants, each board member is to receive warrants to purchase 100,000 shares. These warrants were issued by us to the individuals on December 31, 2010.

On May 28, 2010, we agreed to issue warrants to purchase a total of 300,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services. Of these warrants, each board member is to receive warrants to purchase 100,000 shares. These warrants were issued by us to the individuals on December 31, 2010.

On June 30, 2010, we agreed to issue warrants to purchase a total of 300,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services. Of these warrants, each board member is to receive warrants to purchase 100,000 shares. These warrants were issued by us to the individuals on December 31, 2010.

On July 30, 2010, we agreed to issue warrants to purchase a total of 300,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services. Of these warrants, each board member is to receive warrants to purchase 100,000 shares. These warrants were issued by us to the individuals on December 31, 2010.

On August 31, 2010, we agreed to issue warrants to purchase a total of 300,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services. Of these warrants, each board member is to receive warrants to purchase 100,000 shares. These warrants were issued by us to the individuals on December 31, 2010.

On September 30, 2010, we agreed to issue warrants to purchase a total of 300,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services. Of these warrants, each board member is to receive warrants to purchase 100,000 shares. These warrants were issued by us to the individuals on December 31, 2010.

On October 15, 2010, we issued 10% Senior Secured Convertible Debentures with the face amount of $10,000 to an individual which are convertible into shares of common stock at a conversion price of $0.005 per share in exchange for an aggregate of $10,000.

On October 15, 2010, we issued warrants to purchase a total of 10,000 shares of common stock a purchaser of the Company’s 10% Senior Secured Convertible Debentures at an exercise price of $0.005 as part of the terms of the sale of the debentures.

On October 29, 2010, we agreed to issue warrants to purchase a total of 300,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services. Of these warrants, each board member is to receive warrants to purchase 100,000 shares. These warrants were issued by us to the individuals on December 31, 2010.

On November 11, 2010, we issued 10% Senior Secured Convertible Debentures with the face amount of $40,000 to an individual which are convertible into shares of common stock at a conversion price of $0.005 per share in exchange for an aggregate of $40,000.

On November 11, 2010, we issued warrants to purchase a total of 40,000 shares of common stock a purchaser of the Company’s 10% Senior Secured Convertible Debentures at an exercise price of $0.005 as part of the terms of the sale of the debentures.

On November 30, 2010, we agreed to issue warrants to purchase a total of 300,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services. Of these warrants, each board member is to receive warrants to purchase 100,000 shares. These warrants were issued by us to the individuals on December 31, 2010.

On December 7, 2010, we issued 10% Senior Secured Convertible Debentures with the face amount of $50,000 to an individual which are convertible into shares of common stock at a conversion price of $0.005 per share in exchange for an aggregate of $50,000.

On December 7, 2010, we issued warrants to purchase a total of 50,000 shares of common stock a purchaser of the Company’s 10% Senior Secured Convertible Debentures at an exercise price of $0.005 as part of the terms of the sale of the debentures.

On December 25, 2010, we issued 10% Senior Secured Convertible Debentures with the face amount of $100,000 to an individual which are convertible into shares of common stock at a conversion price of $0.005 per share in exchange for an aggregate of $100,000.

On December 25, 2010, we issued warrants to purchase a total of 100,000 shares of common stock a purchaser of the Company’s 10% Senior Secured Convertible Debentures at an exercise price of $0.005 as part of the terms of the sale of the debentures.

On December 25, 2010, we issued 10% Senior Secured Convertible Debentures with the face amount of $25,000 to an individual which are convertible into shares of common stock at a conversion price of $0.005 per share in exchange for an aggregate of $25,000.

On December 25, 2010, we issued warrants to purchase a total of 25,000 shares of common stock a purchaser of the Company’s 10% Senior Secured Convertible Debentures at an exercise price of $0.005 as part of the terms of the sale of the debentures.

On December 25, 2010, we issued 10% Senior Secured Convertible Debentures with the face amount of $50,000 to an individual which are convertible into shares of common stock at a conversion price of $0.005 per share in exchange for an aggregate of $50,000.

On December 25, 2010, we issued warrants to purchase a total of 50,000 shares of common stock a purchaser of the Company’s 10% Senior Secured Convertible Debentures at an exercise price of $0.005 as part of the terms of the sale of the debentures.

On December 31, 2010, we agreed to issue warrants to purchase a total of 300,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services. Of these warrants, each board member is to receive warrants to purchase 100,000 shares. These warrants were issued by us to the individuals on December 31, 2010.

Unless otherwise indicated, we relied on the exemption from registration relating to offerings that do not involve any public offering pursuant to Section 4(2) under the Securities Act of 1933 (the “Act”) and/or Rule 506 of Regulation D of the Act. We believe that each investor had adequate access to information about us through the investor’s relationship with us.

Item 6. Selected Financial Data

Not applicable

Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our consolidated financial statements and the accompanying notes included elsewhere in this report. Statements in our discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations.

The following is management’s discussion and analysis of certain significant factors that have affected certain aspects of our financial position and results of operations during the periods included in the accompanying audited consolidated financial statements. You should read this in conjunction with the discussion under “Financial Information” and the audited consolidated financial statements included in our Annual Report on Form 10-K for the years ended December 31, 2010 and 2009.

Forward Looking Statements

This Annual Report on Form 10-K contains forward-looking statements concerning our beliefs, plans, objectives, goals, expectations, anticipations, estimates, intentions, operations, future results and prospects, including statements that include the words “may,” “could,” “should,” “would,” “believe,” “expect,” “will,” “shall,” “anticipate,” “estimate,” “intend,” “plan” and similar expressions. These forward-looking statements are based upon current expectations and are subject to risk, uncertainties and assumptions. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated, estimated, expected, projected, intended, committed or believed. We provide the following cautionary statement identifying important factors (some of which are beyond our control) which could cause the actual results or events to differ materially from those set forth in or implied by the forward-looking statements and related assumptions.

General Overview

We are an independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties geographically focused on the onshore United States. Our operational focus is the acquisition, through the most cost effective means possible, of production or near production oil and natural gas field assets. Our areas of operation include Crockett County and South Padre Island, Texas.

Going Concern

As presented in the consolidated financial statements, we have incurred a net loss of $432,713 during the twelve months ended December 31, 2010, and losses are expected to continue in the near term. Current liabilities exceeded current assets by $419,897 and the accumulated deficit is $32,137,592 at December 31, 2010. Amounts outstanding and payable to creditors are in arrears and we are in negotiations with certain creditors to obtain extensions and settlements of outstanding amounts. We are currently in default on one of our debt obligations and we have no future borrowings or funding sources available under existing financing arrangements. Management anticipates that significant additional capital expenditures will be necessary to develop our oil and natural gas properties, which consist primarily of proved reserves that are non-producing, before significant positive operating cash flows will be achieved.

Management's plans to alleviate these conditions include the renegotiation of certain trade payables, settlements of debt amounts with stock, deferral of certain scheduled payments, as considered necessary. In addition, management is pursuing business partnering arrangements for the acquisition and development of its properties as well as debt and equity funding through private placements. Without outside investment from the sale of equity securities, debt financing or partnering with other oil and natural gas companies, operating activities and overhead expenses will be reduced to a pace that available operating cash flows can support.

The accompanying consolidated financial statements are prepared as if we will continue as a going concern. The consolidated financial statements do not contain adjustments, including adjustments to recorded assets and liabilities, which might be necessary if we were unable to continue as a going concern.

Twelve Months Ended December 31, 2010 Compared to the Twelve Months Ended December 31, 2009

Our revenue, operating expenses, and net loss from operations for the year ended December 31, 2010 as compared to the year ended December 31, 2009 were as follows:

										Percentage
	Year Ended December 31,									Change
	2010			2009			Change			Inc (Dec)
REVENUES	$	491,558		$	512,607		$	(21,049	)		(4.1	%)

COSTS AND EXPENSES
Costs of production		202,750			196,520		$	6,230			3.2	%
General and administrative expense		788,140			935,983		$	(147,843	)		(15.8	%)
Depletion and accretion		102,484			291,867		$	(189,383	)		(64.9	%)
Loss on malfeasance		-			280,647			n/m			n/m
Loss from asset impairment		183,473			342,366		$	(158,893	)		n/m
Loss (gain) on settlements		(404,623	)		(1,199,748	)		n/m			n/m
Total expenses		872,224			847,635

LOSS FROM OPERATIONS		(380,666	)		(335,028	)

OTHER EXPENSE
Interest expense		52,047			50,111		$	1,936			3.9	%
Total other expense		52,047			50,111

NET LOSS	$	(432,713	)	$	(385,139	)	$	(47,574	)		(12.4	%)

Weighted average shares, basic and diluted		136,719,608			136,719,608
Net loss per share, basic and diluted	$	(0.00	)	$	(0.00	)

Revenues: All of our revenue was derived from the sale of natural gas. Our revenues declined $21,049 or 4.1% to $491,558 for the twelve months ended December 31, 2010 from $512,607 for the twelve months ended December 31, 2009. The decrease is reflects the decline in volume of gas sold to 73,588 MCF (thousand cubic feet) in the twelve months ended December 31, 2010 compared to 110,048 MCF for the twelve month period ended December 31, 2009. At the same time, the average natural gas price received rose to $6.75 per MCF for the twelve months ended December 31, 2010 compared to $4.66 for the twelve months ended December 31, 2009.

Costs of Production: Our cost of production, including royalties, lease, operations, production taxes and expenses increased $6,230 or 3.2% to $202,750 for the twelve months ended December 31, 2010 from $196,520 for the twelve months ended December 31, 2009. This change reflects the full year of operations under a new independent contract operator and thus gives a better picture of the cost of production. We have a lawsuit pending against the prior contract operator.

General and Administrative Expense: General and administrative expenses declined $147,843 or 15.8% to $788,140 for the twelve months ended December 31, 2010 from $935,983 for the twelve months ending December 31, 2009. The decrease reflects the stronger management role played by the largest investors following the resignation of our then chief executive officer of the Company in May, 2010.

Depletion and Accretion: Depletion and accretion expenses declined $189,383 or 64.9% to $102,484 for the twelve months ended December 31, 2010 from $291,867 for the twelve months ended December 31, 2009. The decrease was due to the lower amount of asset cost basis available to deplete following the impairment adjustment of 2009 and the lower gas volumes in 2010 through on which the depletion expense is modulated.

Malfeasance Losses: There were no malfeasance losses for the twelve months ended December 31, 2010 compared to $280,647 that were traceable to the twelve months ended December 31, 2009. Our previous management of the Company has now been entirely replaced.

Impairment of Oil and Natural Gas Properties: Impairment of oil and natural gas properties declined $158,893 to $183,473 from $342,366 for the twelve months ended December 31, 2009. This reduction reflects the revised estimates of the projected reserves and the gas production rates of the wells as determined by outside consultants during the respective periods.

Interest Expense: Interest expense increased $1,936 or 3.9% to $52,047 for the twelve months ended December 31, 2010 from $50,111 for the twelve months ended December 31, 2009. The increase reflects an increase in note payable to a related party during the 2010 period.

Income Taxes: There is no provision for income tax recorded for either the 2010 or 2009 periods due to operating losses in both periods. We have available Federal income tax net operating loss (“NOL”) carry forwards of approximately $5,487,900 at December 31, 2010. Our NOL generally begins to expire in 2025. We recognize the tax benefit of NOL carry forwards as assets to the extent that management believes that the realization of the NOL carry forward is more likely than not. The realization of future tax benefits is dependent on our ability to generate taxable income within the carry forward period.

Net Loss: Our net loss increased $47,574 or 12.4% to $432,713 for the twelve months ended December 31, 2010 from $385,139 for the twelve months ended December 31, 2009. This loss should be viewed in light of the cash flow from operations discussed below.

During the year ended December 31, 2010, as with the year ended December 31, 2009, after adjusting for one-time gains, we did not generate positive cash flow from on-going operations. As a result, we funded our operations through the private sale of equity and debt securities, the issuance of our securities in exchange for services, and loans.

Liquidity and Capital Resources

The global financial and credit crisis may have impacts on our liquidity and financial condition that we currently cannot predict.

The continued credit crisis and related turmoil in the global financial system may have a material impact on our liquidity and our financial condition, and we may ultimately face major challenges if conditions in the financial markets do not improve. Our ability to access the capital markets or borrow money may be restricted at a time when we would like, or need, to raise capital, which could have an adverse impact on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. Additionally, the current economic situation could lead to reduced demand for natural gas and oil, or further reductions in the prices of natural gas and oil, or both, which could have a negative impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of the current financial crisis cannot be predicted, it may have a material adverse effect on our future liquidity, results of operations and financial condition.

Our cash and cash equivalents, total current assets, total assets, total current liabilities, and total liabilities as of December 31, 2010 as compared to December 31, 2009, are as follows:

	December 31,
	2010		2009
Cash	$	111,572	$	22,076
Total current assets		211,298		169,213
Total assets		763,033		989,600
Total current liabilities		631,195		1,259,510
Total liabilities		785,815		1,294,487

At December 31, 2010, we had a working capital deficit of $419,897compared to a working capital deficit of $1,090,297 at December 31, 2009. Current liabilities decreased to $631,195 at December 31, 2010 from $1,259,510 at December 31, 2009 primarily due to a decrease of $404,623 in amounts due to a former officer of the Company and the conversion of $497,000 in notes payable and $55,275 accrued interest all due to a related party to a senior convertible debenture.

Net cash used by operating activities for the twelve months ended December 31, 2010 totaled $335,727 after the cash used in the net loss of $432,713 was increased by $103,785 in non-cash charges and offset by $200,771 in increases in the working capital accounts. This compares to cash used by operating activities for the twelve months ended December 31, 2009 of $757,339 after the net loss for the period of $385,139 was increased by $528,727 in non-cash charges and offset by $156,527 in changes to the working capital accounts.

Net cash used in investing activities for the twelve months ended December 31, 2010 totaled $25,000 to purchase an option on several Padre Island wells. This compares to $408,334 used in investing activities for the twelve months ended December 31, 2009 for continued operations of completed wells.

Net cash provided by financing activities for the twelve months ended December 31, 2010 totaled $450,223 of which $275,000 came from the sale of senior convertible debentures and $192,000 came from loans from related parties. At the same time, $16,777 was used to pay down the line of credit. This compares to a net of $1,021,560 provided by financing activities for the twelve months ended December 31, 2009. Aurora provided a net of $1,046,809 in financing while $28,673 was used to pay down notes payable to related parties and $41,166 was used for payments to a former officer of the Company

Recently Issued Accounting Pronouncements

Recent Accounting Pronouncements

In April 2010, the FASB issued Accounting Standards Update (“ASU”) No. 2010-14, “Accounting for Extractive Activities – Oil & Gas, Amendments to Paragraph 932-10-S99-1” due to SEC Release No. 33-8995 (FR 78), “Modernization of Oil and Gas Reporting”. This amendment was effective January 1, 2010.

In January 2010, the FASB issued ASU No. 2010-16, “Fair Value Measurements and Disclosures (Topic 820) – Improving Disclosures about Fair Value Measurements”. ASU 2010-16 will require the reporting entity to 1) disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers and 2) present separately information about purchases, sales, issuances, and settlements in the reconciliation for fair value measurements using significant unobservable inputs (Level 3), This ASU also clarifies existing disclosures about levels of disaggregation and about inputs and valuation techniques. This ASU is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements which are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal periods. The Company has adopted the provisions of the ASU that were effective for reporting periods beginning after December 15, 2009 and it is current assessing the impact of the Level 3 disclosures. This standard will not have a significant impact on the Company’s financial statements.

In January 2010, the FASB issued ASU No. 2010-03, “Extractive Activities – Oil and Gas (Topic 932) – Oil and Gas Reserve Estimation and Disclosures”. The ASU expands and amends certain definition of terms used in the Topic, requires an entity to disclosure separately information about reserve quantities and financial statements amounts for geographic areas that represent 15 percent or more of proved reserves, clarifies that an entity’s equity method investments must be considered in determining whether it has significant oil – and gas- producing activities, required that an entity continue to disclosure separately the amounts and quantities for consolidated and equity method investments and requires that disclosures about equity method investments be in the same level of detail as is required for consolidated investments. Amendments to this Topic are effective to annual reporting periods ending on or after December 31, 2009. This standard will not have a significant impact on the Company’s financial statements.

In August 2009, the FASB issued an amendment to the accounting standards related to the measurement of liabilities that are recognized or disclosed at fair value on a recurring basis. This standard clarifies how a company should measure the fair value of liabilities and that restrictions preventing the transfer of a liability should not be considered as a factor in the measurement of liabilities within the scope of this standard. This standard was effective for the Company on October 1, 2009. This standard will not have a significant impact on the Company’s financial statements.

In October 2009, the FASB issued an amendment to the accounting standards related to the accounting for revenue in arrangements with multiple deliverables including how the arrangement consideration is allocated among delivered and undelivered items of the arrangement. Among the amendments, this standard eliminates the use of the residual method for allocating arrangement consideration and requires an entity to allocate the overall consideration to each deliverable based on an estimated selling price of each individual deliverable in the arrangement in the absence of having vendor-specific objective evidence or other third party evidence of fair value of the undelivered items. This standard also provides further guidance on how to determine a separate unit of accounting in a multiple-deliverable revenue arrangement and expands the disclosure requirements about the judgments made in applying the estimated selling price method and how those judgments affect the timing or amount of revenue recognition. This standard, for which the Company is currently assessing the impact, will become effective for the Company on January 1, 2011.

Summary of Critical Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.

Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of proved and unproved properties, future income taxes and related assets and liabilities, the fair value of various common stock, warrants and option transactions, and contingencies. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the calculation of impairment, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data, the engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

These significant estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates, the fair value of the Company’s common stock and corresponding volatility, and the Company’s ability to generate future taxable income. Future changes to these assumptions may affect these significant estimates materially in the near term.

Oil and Natural Gas Properties

We account for investments in natural gas and oil properties using the successful efforts method of accounting. Under this method of accounting, only successful exploration costs that directly result in the discovery of proved reserves are capitalized. Unsuccessful exploration costs that do not result in an asset with future economic benefit are expensed. All development costs are capitalized because the purpose of development activities is considered to be building a producing system of wells, and related equipment facilities, rather than searching for oil and gas. Items charged to expense generally include geological and geophysical costs. Capitalized costs of proved properties are depleted on a field-by-field (Common Reservoir) basis using the units-of-production method based upon proved, producing oil and natural gas reserves.

The net capitalized costs of proved oil and natural gas properties are subject to an impairment test based on the undiscounted future net reserves from proved oil and natural gas reserves based on current economic and operating conditions. Impairment of an individual producing oil and natural gas field is first determined by comparing the undiscounted future net cash flows associated with the proved property to the carrying value of the underlying property. If the cost of the underlying property is in excess of the undiscounted future net cash flows the carrying cost of the impaired property is compared to the estimated fair value and the difference is recorded as an impairment loss. Management’s estimate of fair value takes into account many factors such as the present value discount rate, pricing, and when appropriate, possible and probable reserves when activities justified by economic conditions and actual or planned drilling or other development.

Under the successful efforts method of accounting, the depletion rate is the current period production as a percentage of the total proved producing reserves. The depletion rate is applied to the net book value of property costs to calculate the depletion expense. Proved reserves materially impact depletion expense. If the proved reserves decline, then the depletion rate (the rate at which we record depletion expense) increases, reducing net income.

We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to 10 years.

Long-lived Assets and Intangible Assets

The Company accounts for intangible assets in accordance with the provisions of the applicable FASB standard. Intangible assets that have defined lives are subject to amortization over the useful life of the assets. Intangible assets held having no contractual factors or other factors limiting the useful life of the asset are not subject to amortization but are reviewed at least annually for impairment or when indicators suggest that impairment may be needed. Intangible assets are subject to impairment review at least annually or when there is an indication that an asset has been impaired. As of December 31, 2008, the Company determined that due to the worsened financial markets and oil and gas industry, full impairment of its patented lateral drilling technology was necessary. While there are prospects for possible capital funding (either debt or equity), much is left to the market and outside instability. As such, at this time, management cannot anticipate with a comfortable degree of certainty if the appropriate amount of funding will be achieved and any funding will be diverted fully to its E&P activities. This will further postpone the Company’s ability to dedicate financial as well as human resources to its technology division in the short term future. As such, the Company has eliminated the division entirely.

For unproved property costs, management reviews these investments for impairment on a property-by-property basis if a triggering event should occur that may suggest that impairment may be required.

The Company reviews its long-lived assets and proved oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable in accordance with the applicable FASB standard. Proved oil and gas assets are evaluated for impairment at least annually. If the carrying amount of the asset, including any intangible assets associated with that asset, exceeds its estimated future undiscounted net cash flows, the Company will recognize an impairment loss equal to the difference between its carrying amount and its estimated fair value. The fair value used to calculate the impairment for producing oil and natural gas field that produces from a common reservoir is first determined by comparing the undiscounted future net cash flows associated with total proved properties to the carrying value of the underlying evaluated property. If the cost of the underlying evaluated property is in excess of the undiscounted future net cash flows, the future net cash flows discounted at 10%, which the Company believes approximates fair value, to determine the amount of impairment.

Stock Based Compensation

The Company adopted the FASB standard related to stock compensation to account for its warrants issued to key partners, directors and officers. The fair value of common warrants granted is estimated at the date of grant using the Black-Scholes option pricing model by using the historical volatility of comparable public companies. The calculation also takes into account the common stock fair market value at the grant date, the exercise price, the expected life of the common stock option or warrant, the dividend yield and the risk-free interest rate.

The Company from time to time may issue warrants and restricted stock to acquire goods or services from third parties. Restricted stock, options or warrants issued are recorded on the basis of their fair value, which is measured as of the date issued. In accordance with the standard, the options or warrants are valued using the Black-Scholes option pricing model on the basis of the market price of the underlying equity instrument on the “valuation date,” which for warrants related to contracts that have substantial disincentives to non-performance, is the date of the contract, and for all other contracts is the vesting date. Expense related to the options and warrants is recognized on a straight-line basis over the shorter of the period over which services are to be received or the vesting period.

Earnings per Share

Income Taxes

Under the applicable FASB standard, deferred income taxes are recognized at each year end for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. We routinely assess the reliability of our deferred tax assets. We consider future taxable income in making such assessments. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, it is reduced by a valuation allowance. However, despite our attempt to make an accurate estimate, the ultimate utilization of our deferred tax assets is highly dependent upon our actual production and the realization of taxable income in future periods.

Contingencies

Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable.

Volatility of Oil and Natural Gas Prices

Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas.

Off-Balance Sheet Arrangements

For the years ended December 31, 2010 and 2009, we had no off-balance sheet arrangements that were reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is deemed by our management to be material to investors.

Contractual Obligations

The following table summarizes our contractual obligations and commercial commitments as of December 31, 2010:

	2011		2012		2013		2014		2015		Total
Long-Term Debt	$	—	$	—	$	827,275	$		$	—	$	827,275
Capital Leases	$	—	$	—	$	—	$	—	$	—	$	—
Operating Leases	$	19,250	$	1,750	$	—	$	—	$	—	$	21,000
Purchase Obligations	$	—	$	—	$	—	$	—	$	—	$	—
Other Long-Term Liabilities	$	—	$	—	$	—	$	—	$	—	$	—
Total	$	19,250	$	1,750	$	827,275	$	---	$	—	$	848,275

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk

Volatility of Oil and Natural Gas Prices

As an indication of the dramatic way in which the price of natural gas can change, the following table provides the average price per million cubic feet (MMCF) of gas which the Company received for the periods indicated:

Three Months Ending	Average Price per MMCF
March 31, 2009	$	4.12
June 30, 2009	$	4.05
September 30, 3009	$	4.20
December 31, 2009	$	4.66
March 31, 2010	$	7.16
June 30, 2010	$	5.73
September 30, 2010	$	5.91
December 31, 2010	$	8.91

Item 8. Financial Statements and Supplementary Data

The information required by this Item 8 is incorporated by reference to the Index to Consolidated Financial Statements beginning at page F-1 of this Annual Report.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

On March 18, 2009, our board of directors approved the dismissal of John Kinross-Kennedy (“Mr. Kinross-Kennedy”) as our independent auditor. Mr. Kinross-Kennedy served as our independent auditor for the Company’s fiscal years ended December 31, 2007, December 31, 2006, and December 31, 2005. Mr. Kinross-Kennedy was also responsible for the review of our interim financial statements for the quarterly periods ending March 31, 2008, June 30, 2008, and September 30, 2008.

On March 23, 2009, we filed an 8-K with the Commission announcing our dismissal of Mr. Kinross-Kennedy as our independent auditor and disclosing that during the fiscal years ended December 31, 2007, December 31, 2006, and December 31, 2005, and until Mr. Kinross-Kennedy’s termination, there were no disagreements with Mr. Kinross-Kennedy on any matter of accounting principles or practices, financial disclosure, or auditing scope or procedure. Subsequent to Mr. Kinross-Kennedy’s departure from the Company, we endeavored to determine the adequacy of his professional work undertaken for the Company. However, because of the disarray created by the lack of proper financial record-keeping, it was not possible to discover the nature of financial improprieties set in place by Mr. Kinross-Kennedy until an independent audit of the Company’s books and records was undertaken in late 2010. Through this independent audit process, we have now determined that the accounting for the financial statements for the fiscal years ended December 31, 2007, and the interim periods ended March 31, June 30, and September 30, 2008, were not prepared in accordance with GAAP. As a result, we restated our financial statements for the following periods: year ended December 31, 2007 and quarterly periods ended March 31, June 30, and September 30, 2008. In addition, we have filed a lawsuit against Mr. Kinross-Kennedy for professional negligence as disclosed under Item 3.

On March 18, 2009, concurrent with our dismissal of Mr. Kinross-Kennedy, we engaged Hein & Associates, LLP (“Hein”) as our outside independent accounting firm. Although Hein served as our independent auditor for our fiscal years ended December 31, 2008, December 31, 2009, and December 31, 2010, at no time did Hein commence any audit or review procedures of the Company’s financial statements for any period. For the last two (2) fiscal years, there were no reports or other communications from Hein in connection with our financial statements that contained an adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope, or accounting principles. For the last two (2) fiscal years, and any subsequent interim period preceding the dismissal, there were no disagreements with Hein on any matter of accounting principles or practices, financial statement disclosure, or auditing scope of procedure which, if not resolved to the satisfaction of Hein, would have caused Hein to make reference to the subject matter of such disagreements in connection with any reports or other communications us.

On January 17, 2011, our board approved the dismisal of Hein. Concurrent with the decision to dismiss Hein as our independent registered public accounting firm, our board of directors approved the appointment of Wilson Morgan, LLP (“Wilson”) as our registered independent public accounting firm.

We, during the last two (2) fiscal years and any subsequent interim period to the date hereof, did not have discussions nor have we consulted with Wilson regarding the following: (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on our financial statements, and neither a written report or oral advice was provided to us that Wilson concluded was an important factor considered by us in reaching a decision as to the accounting, auditing, or financial reporting issue, or (ii) any matter that was the subject of a disagreement or reportable event as defined in Regulation S-K, Item 304(a)(1)(iv) and Item 304(a)(1)(v), respectively.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures, as defined in Rule 13a-1 5(e) promulgated under the Securities Exchange Act of 1934 (the “Exchange Act”), that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2010 and 2009. Based on the evaluation of these disclosure controls and procedures, and in light of the material weaknesses found in our internal controls over financial reporting, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective.

This Annual Report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this Annual Report.

Management’s Report on Internal Control over Financial Reporting

Material Weaknesses in Internal Control Over Financial Reporting

Management’s assessment of the effectiveness of the registrant’s internal control over financial reporting is as of the year December 31, 2010. Based on that evaluation, our management concluded that a material weakness existed over our control over financial reporting and related disclosure controls and procedures were not effective because we were unable to complete the financial statements for the year ended December 31, 2010, in a timely manner to enable us to file the Quarterly Reports on Forms 10-Q and the Annual Report on Form 10-K by the respective due dates.

Management has taken steps to remediate the material weakness over our control over financial reporting and related disclosure controls and procedures by implementing the following controls:

During November, 2008, we hired a CFO who possesses the needed GAAP accounting and SEC reporting skills necessary to improve our internal controls over financial reporting.

During January, 2009, we appointed our CFO to the board of directors. While the CFO is qualified as an audit committee financial expert as defined in Item 407(d)(5)(ii) of Regulation S-K, he is not independent and, as such, his role on the board of directors does not meet the independence requirements of Item 407(d)(5)(ii) of Regulation S-K.

During February, 2011, we engaged a corporate accountant who has significant SEC financial reporting and accounting experience. This individual assisted with the accounting update for the year ended December 31, 2010, including preparation of the delinquent quarterly Forms 10-Q for the quarterly periods ended March 31, 2010, June 30, 2010, and September 30, 2010. This individual also is assisting in preparing the quarterly report for the quarterly period ended March 31, 2011

Item 9B. Other Information

There are no events required to be disclosed by this Item.

Part III

Item 10. Directors, Executive Officers and Corporate Governance

Business Experience and Background of Directors and Executive Officers as of December 31, 2010.

Name	Age		Positions Held
Robert J. Miranda (1)		58	Current Director, Chairman, CEO, and Chief Financial Officer
Ronald Zamber (1)		51	Current Director
Robert Grenley (1)		54	Current Director (2)
Edgar Trotter (1)		67	Former Director (3)
Perry Mansell (1)		64	Former Director (4)

(1)	There are no family relationships among our executive officers and directors.

(2)	Mr. Grenley was elected to the Board on June 1, 2010.

(3)	Mr. Trotter resigned from the board effective May 31, 2010.

(4)	Mr. Mansell resigned from the board effective November 11, 2010.

Robert J. Miranda, CPA – Was appointed as our Chief Financial Officer on November 16, 2008. On April 28, 2009, he was appointed Chairman and interim President and CEO upon the resignation of our former President and CEO, Jon Fullenkamp. On March 28, 2011, he was appointed President and CEO. Since October 2007, Mr. Miranda has been managing director of Miranda & Associates, a professional accountancy corporation. From March 2003 through October 2007, Mr. Miranda was a Global Operations Director at Jefferson Wells, where he specialized in providing Sarbanes-Oxley compliance reviews for public companies. Mr. Miranda was a national director at Deloitte & Touche where he participated in numerous audits, corporate finance transactions, mergers, and acquisitions. Mr. Miranda is a licensed Certified Public Accountant and has over 35 years of experience in accounting, including experience in Sarbanes-Oxley compliance, auditing, business consulting, strategic planning and advisory services. Mr. Miranda holds a B.S. degree in Business Administration from the University of Southern California, a certificate from the Owner/President Management Program from the Harvard Business School and membership in the American Institute of Certified Public Accountants.

Ronald W. Zamber, M.D. Director – Was appointed director on January 24, 2009. Dr. Zamber brings more than 15 years of experience in corporate management and business development extending across public and private companies and non-profit organizations. Since 2000, Dr. Zamber has been president and CEO of The Eye Clinic of Fairbanks (ECF), a private, full service eye care practice based in Fairbanks, Alaska and serving the entire Alaska interior. Dr. Zamber received his bachelor's degree with high honors from the University of Notre Dame and his medical degree with honors from the University of Washington.

Robert Grenley - Was appointed director on June 1, 2010. Since May, 2007, Mr. Grenley has served as Chief Financial Officer of Ambient, Inc. a private subsidiary of IDM Technologies, LLC, and a private company based in Gig Harbor, Washington. From 1996 through April, 2007, Mr. Grenley was President of ID Micro, a private company located in Tacoma, Washington. Mr. Grenley has over 25 years experience in financial management, business development and entrepreneurial experience, including nine years in Radio Frequency Identification (RFID) corporate development and investor relations. Mr. Grenley holds a BA in Economics from Duke University.

Edgar P. Trotter, Ph.D. – Was appointed director on January 24, 2009 and resigned as director on May 31, 2010. Mr. Trotter is Acting Associate Vice President, Undergraduate Programs and Professor, Department of Communications for California State University, Fullerton (CSUF), where he has been a professor since 1975. He has held prior posts as the Chairman of the Department of Communications and as Director of the CSUF Learning Technology Center. Mr. Trotter holds a Ph.D. in Journalism from Southern Illinois University, a Master of Science in Journalism from Ohio University and a Bachelor of Science in Mathematics from Murray State University. He is a former U.S. Navy officer and Vietnam War veteran.

Perry Mansell – Was appointed to the board on February 28, 2007 and resigned on November 11, 2010. Mr. Mansell has owned and operated Mansell Consulting and General Construction since 1970.

Jon Fullenkamp – Was appointed to the board Chairman, President and CEO in January 2005. He resigned from the board and as President and CEO on April 28, 2009.

Involvement in Certain Legal Proceedings

The foregoing directors or executive officers have not been involved during the last five years in any of the following events:

Bankruptcy petitions filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time;

Conviction in a criminal proceeding or being subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);

Being subject to any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring or suspending or otherwise limiting his involvement in any type of business, securities or banking activities; or

Being found by a court of competition jurisdiction (in a civil action), the Securities and Exchange Commission or the Commodities Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended or vacated.

Board Composition

Our business and affairs are organized under the direction of our board of directors, which currently consists of three (3) members. The primary responsibilities of our board of directors are to provide oversight, strategic guidance, counseling and direction to our management. Our board of directors meets on a regular basis and additionally as required. Written board materials are distributed in advance as a general rule, and our board of directors schedules meetings with and presentations from members of our senior management on a regular basis and as required.

Our board of directors set schedules to meet throughout the year and also can hold special meetings and act by written consent under certain circumstances.

Limitation of Liability and Indemnification

We intend to enter into indemnification agreements with each of our directors and executive officers and certain other key employees. The form of agreement provides that we will indemnify each of our directors, executive officers, and such other key employees against any and all expenses incurred by that director, executive officer or key employee because of his or her status as one of our directors, executive officers or key employees, to the fullest extent permitted by law and our bylaws (except in a proceeding initiated by such person without board approval). In addition, the form agreement provides that, to the fullest extent permitted by law, we will advance all expenses incurred by our directors, executive officers, and such key employees in connection with a legal proceeding.

The Nevada Revised Statutes and our bylaws contain provisions relating to the limitation of liability and indemnification of directors and officers.

Our bylaws provide that we will indemnify our directors and officers to the fullest extent permitted by law, as it now exists or may in the future be amended, against all expenses and liabilities reasonably incurred in connection with their service for or on our behalf. Our bylaws provide that we shall advance the expenses incurred by a director or officer in advance of the final disposition of an action or proceeding. Our bylaws also authorize us to indemnify any of our employees or agents and permit us to secure insurance on behalf of any officer, director, employee or agent for any liability arising out of their action in that capacity, whether or not the law would otherwise permit indemnification.

Shareholder Communications

Any shareholder of the Company wishing to communicate to the board of directors may do so by sending written communication to the board of directors to the attention of Mr. Robert J. Miranda, Chief Executive Officer, at the principal executive offices of the Company. The board of directors will consider any such written communication at its next regularly scheduled meeting.

Compliance with Section 16(a) of the Exchange Act:

Under the securities laws of the United States, our directors, its executive officers and any persons holding more than 10% of our common stock are required to report their ownership of our common stock and any changes in that ownership to the Securities and Exchange Commission. Specific due dates for these reports have been established by rules adopted by the SEC and we are required to report in this Annual Report any failure to file by those deadlines.

Based solely upon a review of Forms 3, 4, and 5, and amendments to these forms furnished to us, except as provided below, all parties subject to the reporting requirements of Section 16(a) of the Exchange Act filed on a timely basis all such required reports during and with respect to our 2010 fiscal year.

To the best of our knowledge, the number of late reports for Ron Zamber was 1, the number of transactions that were not reported on a timely basis was 1, and the number of failures to file a required Form was 2.

To the best of our knowledge, the number of late reports for Edgar Trotter was 1, the number of transactions that were not reported on a timely basis was 1, and the number of failures to file a required Form was 1.

To the best of our knowledge, the number of late reports for Robert Miranda was 1, the number of transactions that were not reported on a timely basis was 1, and the number of failures to file a required Form was 1.

To the best of our knowledge, the number of late reports for Robert Grenley was 2, the number of transactions that were not reported on a timely basis was 1, and the number of failures to file a required Form was 1.

Code of Ethics

We have not adopted a code of ethics to apply to our principal executive officer, principal financial officer, principal accounting officer and controller, or persons performing similar functions. We expect to prepare a Code of Ethics in the near future.

Item 11. Executive Compensation

The following table sets forth the total compensation awarded to, earned by, or paid to our “principal executive officer,” and our other named executive officers for all services rendered in all capacities to us in 2010 and 2009.

Name and Principal Position	Year	Salary ($)			Bonus ($)		Stock Awards ($)		Option Awards ($)		Non-Equity Incentive Plan Compensation ($)		Nonqualified Deferred Compensation ($)		All Other Compensation ($)		Total ($)
Robert J. Miranda	2010		180,000	(2)		-		-		4,690		-		-		-		184,690
Chairman, CEO, and CEO	2009		180,000	(2)		-		-		5,795		-		-		-		185,795
(1) (2)	2008		10,000	(2)		-		-		-		-		-		-		10,000

Jon Fullenkamp	2010					-		-				-		-		-
former Chairman, CEO, and CFO (3)	2009		104,167							1,392								105,559
	2008		250,000			-		-		-		-		-		-		250,000

(1)	Appointed CFO on November 16, 2008; director on January 24, 2009; and Chairman, President & interim CEO on April 28, 2009; CEO on March 28, 2011.

(2)	Represents the portion of the total consulting fees paid to Miranda & Associates, A Professional Accountancy Corporation, that is wholly-owned by Mr. Miranda, in consideration of services, attributable to the services provided by Mr. Miranda as an executive officer of Victory Energy Corporation.

(3)	Jon Fullenkamp resigned effective April 28, 2009.

Director Compensation

The following table sets forth the total compensation awarded to, earned by, or paid to each person who served as a director during the years ended December 31, 2010 and 2009, other than a director who also served as a named executive officer. Our directors who are not executive officers did not receive any cash compensation for serving on our board of directors. We have a policy of reimbursing our directors for their reasonable out-of-pocket expenses incurred in attending Board and committee meetings. Each director is paid for his or her director services in the form of 100,000 warrants earned monthly for each month of service which was issued at the end of the fiscal year. These five (5) year warrants are exercisable into common stock at an exercise price $0.01, and vest immediately upon issuance.

Name	Year	Fees Earned or Paid in Cash ($)		Stock Awards ($)		Option Awards ($)		Non-Equity Incentive Compensation ($)		Nonqualified Deferred Compensation Earnings ($)		All Other Compensation ($)		Total ($)

Edgar Trotter, Former Director (1)	2010		-		-		1,660		-		-		-		1,660

Perry Mansell, Former Director (2)	2010		-		-		-		-		-		-		-

Ronald Zamber, Current Director	2010		-		-		4,690		-		-		-		4,690

Robert Grenley, Current Director (3)	2010		-		-		3,030		-		-		-		3,030

1) Edgar Trotter resigned effective May 31, 2010

2) Perry Mansell resigned effective November 11, 2010

3) Robert Grenley was elected on June 1, 2010

Outstanding Equity Awards at Fiscal Year-End

The following table sets forth certain information concerning outstanding stock awards held by the named executive officers as of December 31, 2010.

		Option Awards							Stock Awards
Name	Year	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	Option Exercise Price ($)		Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)	Market Value of Shares or Units of Stock That Have Not Vested ($)	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)

Robert J. Miranda Chairman, CEO, and CEO
	2010		1,200,000	-	-	$	0.01	12/31/ 2015	-	-	-	-

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Securities Authorized for Issuance under Equity Compensation Plans

The following table sets forth information concerning the Company’s equity compensation plans as of December 31, 2010, 2009, and 2008.

Equity Compensation Plan Information
	Year	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance
Plan category

Equity compensation plans approved by security holders	2010		-		-		-

Equity compensation plans not approved by shareholders	2010		13,362,226	$	0.13		8,400,000

Total	2010		13,362,226		-		8,400,000

Security Ownership of Certain Beneficial Owners and Management

Beneficial ownership is determined in accordance with the rules of the SEC, and generally includes voting power and/or investment power with respect to the securities held. Shares of common stock subject to options or warrants currently exercisable or exercisable within 60 days of December 31, 2010 and 2009, are deemed outstanding and beneficially owned by the person holding such options for purposes of computing the number of shares and percentage beneficially owned by such person, but are not deemed outstanding for purposes of computing the percentage beneficially owned by any other person. Except as indicated in the footnotes to these tables, and subject to applicable community property laws, the persons or entities named have sole voting and investment power with respect to all shares of our common stock shown as beneficially owned by them.

The following is the schedule of beneficial ownership as of December 31, 2010:

Name and Position	Business Address	Common Stock			Warrants (3)			Total			Percent of Class (1)
John Fullenkamp, Former CEO and Director	27762 Antonio Parkway Ladera Ranch, CA 92694		16,144,563	(4)		400,000	(4)		16,544,563	(4)		12.1	%

Ronald Zamber, Director (2)	1919 Lathrop Suite 103 Fairbanks, AK 99701		8,312,578			5,242,226			13,554,804			9.5	%

Robert Grenley, Director (5)	40 Loch Lane SW Lakewood, WA 98499		—			700,000			700,000			.05	%


Perry Mansell, Former Director (6)	20341 Irvine Avenue, #D6 Newport Beach, CA 92660		925,000			1,100,000			2,025,000			1.5	%

Robert Miranda, Chairman, CEO, CFO, and Director	20341 Irvine Avenue, #D6 Newport Beach, CA 92660		—			2,400,000			2,400,000			1.7	%

Edgar Trotter, Former Director (7)	20341 Irvine Avenue, #D6 Newport Beach, CA 92660		—			1,700,000			1,700,000			1.2	%

All Officers and Directors As a Group (6 Persons)			25,382,141			11,542,226			36,924,367			24.9	%

(1)	Based on 136,719,608 shares outstanding.

(2)	Includes 4,042,226 of warrants of James Capital Consulting, LLC; Ron Zamber is the managing member of this entity.

(3)	All warrants were exercisable immediately

(4)	John Fullenkamp surrendered 16,144,563 shares of common stock and 400,000 warrants as part of his settlement with the Company on March 24, 2011. According to the records of the Company’s stock transfer agent, Fullenkamp had no other beneficial ownership of common shares of the Company at December 31, 2010

(5)	Robert Grenley was appointed to the Board of Directors on June 1, 2010

(6)	Perry Mansell resigned effective November 11, 2010

(7)	Edgar Trotter resigned effective May 31, 2010

Item 13. Certain Relationships and Related Transactions, and Director Independence

Related Party Transactions

During the year ended December 31, 2010, we incurred a total of $259,590 of accounting, internal audit, CEO & CFO management, and tax, and business turnaround consulting fees with Miranda & Associates, A Professional Accountancy Corporation (“Miranda”). Of these fees, $180,000 is attributable to the services of Robert Miranda as an executive officer of the Company pursuant to the consulting services agreement discussed below. The balance of $79,590 incurred with Miranda relates to internal audit, tax, and advisory services provided by other members of the Miranda firm. As of December 31, 2010, Miranda & Associates was owed $132,835 for these professional services.

During 2010, we entered into unsecured notes payable totaling $302,000 with Visionary Investments, LLC. (“Visionary”) Ronald Zamber, a director and major stockholder of the Company, is the sole member of Visionary. These notes bear interest at a fixed rate of 10% and mature on December 31, 2010.

On December 31, 2010, the Company entered into a Loan Extension Agreement with Visionary Investments, LLC (“Visionary”) to convert various unsecured promissory notes held by Visionary (the “Notes”) into a 10% Senior Secured Convertible Debenture (the “Debenture”). The sole member of Visionary is Ronald Zamber, a director and major stockholder of the Company.

The Notes have a total principal amount of $497,000 and have accumulated interest in the amount of $55,275. In consideration of the Loan Extension Agreement, the Notes and all accumulated interest were cancelled and the Company issued the Debenture to Visionary with a total face value of $552,275. The Debenture bears interest at the rate of 10% per year payable at maturity. The maturity date of the Debenture is September 30, 2013, but may be extended at the sole discretion of the Company to December 31, 2013. The Debenture is immediately convertible by the holder into shares of the Company’s common stock at a conversion price of $0.005 per share, subject to customary adjustments for stock splits, stock dividends, recapitalizations and the like. The Company has the right to force conversion of the Debenture if, among other things, the closing sales price of the Company’s common stock is equal to or exceeds $0.025 for twenty (20) consecutive trading days. The total number of shares of common stock issuable upon conversion of the Debenture is 110,455,000.

On May 15, 2009, the Company entered into a “Separation Agreement and General Release of Claims” with Jon Fullenkamp (“Fullenkamp”) and the Virgin Family Trust. The terms of the Agreement include (a) termination of an employment agreement between the Company and Fullenkamp; (b) payment of all accrued salaries, unreimbursed expenses, and shareholder advances previously made by Fullenkamp; (c) reduction of shareholder advances from estimated balance owed at the time of settlement of $1,665,375 to a balance of $500,000 (the “Separation Settlement”); (d) Payment terms of the Separation Settlement of $10,000 monthly commencing June 1, 2009, and payable over a fifty (50) month period, including imputed interest at the rate of 3.52% per annum; (e) cancellation of 2,000,000 shares of preferred stock, convertible at the rate of 100 shares of common, (d) lockup agreement with respect to all shares owned directly or indirectly by Fullenkamp for a period of five years, (e) Fullenkamp was to cooperate with the Company to recover misappropriated funds and agreed to bring litigation or induce others to bring litigation against the Company.

At the time of the agreement, Fullenkamp was owed the sum of approximately $1,665,375 in shareholder advances which were settled for $500,000, resulting in a gain on the settlement of this debt of $1,199,748. After the first payment of $10,000 the company recorded a discount of 3.25% on $490,000, the minimum federal rate in the amount of $34,373 against the note. The discount is amortized to interest expense over the period of estimated maturity. During the year ended December 31, 2009, the Company recorded interest expense of $8,997 and the note had an unamortized discount of $24,476. During the year ended December 31, 2009, the Company paid $51,004 of the principal of the Separation Settlement, reducing the outstanding balance as of December 31, 2009 to $404,623.

During 2009, we entered into unsecured notes payable totaling $195,000 with Visionary. Ronald Zamber, a director and major stockholder of the Company, is the sole member of Visionary. These notes bear interest at a fixed rate of 10% and mature on December 31, 2010. The unpaid balance of unsecured notes payable was $355,000 as of December 31, 2009.

Director Independence

We are quoted on the OTC Markets. While the OTC Markets does not maintain director independence standards, we are taking the necessary steps to qualify as having independent directors under the guidelines of FINRA.

Item 14. Principal Accounting Fees and Services

Audit Fees

We did not file when due our Annual Report on Form 10-K for the fiscal years ended December 31, 2010 and 2009, or Quarterly Reports on Forms 10-Q for the interim 2010 and 2009 periods. Accordingly, the aggregate fees billed for the fiscal year ended December 31, 2010 for professional services rendered by the principal accountant for the audit of our annual financial statements and review of the financial statements or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements for that fiscal year was $0.

Audit - Related Fees

The aggregate fees billed in the fiscal year ended December 31, 2010 and 2009 for professional services rendered by the principal accountant for the review of the financial statements included in our Forms 10-Q for the quarterly periods applicable to these years were included in the audit fees above.

Tax Fees

For the fiscal years ended December 31, 2010 and 2009 our principal accountants did not render any services for tax compliance, tax advice, and tax planning work.

All Other Fees

None.

Of the fees described above for the years ended December 31, 2010 and 2009, 100% were approved by the entire board of directors.

Part IV

Item 15. Exhibits, Financial Statement Schedules

(a)(1) and (2) Financial Statements and Schedules

INDEX TO FINANCIAL STATEMENTS

		Page
Report of Independent Registered Public Accounting Firm		F-1

Consolidated Balance Sheets as of December 31, 2010 and 2009		F-2

Consolidated Statements of Operations for the Years Ended December 31, 2010 and 2009		F-3

Consolidated Statements of Cash Flows for the Years Ended December 31, 2010 and 2009		F-4

Consolidated Statement of Shareholders’ Deficit for the Years Ended December 31, 2010 and 2009		F-5

Notes to Financial Statements for the Years Ended December 31, 2010 and 2009		F-6

a)(3) Exhibits

Refer to (b) below.

(b)		Exhibits

3.1		Articles of Incorporation of All Things, Inc., filed on January 7, 1982 incorporated by reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.

3.2		Certificate of Amendment of Articles of Incorporation, filed on January 7, 1982 incorporated by reference to Exhibit 3.2 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.

3.3		Certificate of Amendment of Articles of Incorporation, filed on March 21, 1985 incorporated by reference to Exhibit 3.3 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.

3.4		Certificate of Amendment of Articles of Incorporation, filed on November 1, 1995 incorporated by reference to Exhibit 3.4 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.

3.5		Certificate of Amendment of Articles of Incorporation, filed on April 28, 2003 incorporated by reference to Exhibit 3.5 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.

3.6		Certificate of Amendment of Articles of Incorporation, filed on May 3, 2006 incorporated by reference to Exhibit 3.6 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.

3.7		Certificate of Amendment of Articles of Incorporation, filed on May 10, 2006 incorporated by reference to Exhibit 3.7 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.

3.8		Certificate of Amendment of Articles of Incorporation, filed on August 22, 2006 incorporated by reference to Exhibit 3.8 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.

3.9		Certificate of Amendment of Articles of Incorporation, filed on October 3, 2008 incorporated by reference to Exhibit 3.9 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.

3.10		Bylaws of Victory Energy Corporation incorporated by reference to Exhibit 3.10 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.

10.1		Unsecured Promissory Notes (Zamber) incorporated by reference to Exhibit 10.1 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.

10.2		The Victory Energy Corporation/James Capital Energy, LLC, Joint Venture Partnership Agreement by and between Victory Energy Corporation, James Capital Energy, LLC and James Capital Consulting dated December 31, 2009 incorporated by reference to Exhibit 10.2 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.

10.3		First Amendment to The Victory Energy Corporation/James Capital Energy, LLC, Joint Venture Partnership Agreement, changing the name of the Partnership to “Aurora Energy Partners, A Texas General Partnership, dated March 31, 2010

10.4		Separation Agreement by and between Victory Energy Corporation and Jon Fullenkamp dated May 15, 2009 incorporated by reference to Exhibit 10.3 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.

10.5		Settlement Agreement and Mutual General Release by and between Jon Fullenkamp and Xploration, on the one hand; and Victory Energy Corporation, James Capital Energy, LLC, James Capital Consulting, LLC, James Capital, LLC, Aurora Energy Partners, Zamber Energy Investments, LLC, International Vision Quest, Miranda & Associates, Ronald Zamber, Robert Miranda, Richard May, and Tom Konz, on the other hand, incorporated by reference to Exhibit 10.5 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.

10.6		Consulting Services Agreement by and between Victory Energy Corporation and Miranda & Associates, A Professional Accountancy Corporation dated November 16, 2008 incorporated by reference to Exhibit 10.6 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.

10.7		Consulting Services Agreement by and between the Victory Energy Corporation and Miranda & Associates, A Professional Accountancy Corporation, dated August 1, 2009 incorporated by reference to Exhibit 10.7 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.

10.8		Option Agreement by and among Victory Energy Corporation, Santiago Resources, LP, 1519 Partners, LP, Via Fortuna Minerals, LLC, Wesley G. Ritchie, and Barrier Island Minerals, LLC dated December 20, 2010.incorporated by reference to Exhibit 99.1 of the Company’s Form 8-K filed with the SEC on January 4, 2011.

31.1		Rule 13a-14(a)/15d-14(a) Certification of Robert Miranda

31.2		Rule 13a-14(a)/15d-14(a) Certification of Robert Miranda

32		Section 1350 Certification of Robert Miranda

SIGNATURES

In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

	VICTORY ENERGY CORPORATION

Date: May 16, 2011	By:	/s/ Robert J. Miranda
		Robert J. Miranda
		Chief Executive Officer,
		Chief Financial Officer, Chairman, and Director

In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date: May 16, 2011	By:	/s/ Ronald W. Zamber
		Ronald W. Zamber
		Director

Date: May 16, 2011	By:	/s/ Robert Grenley
		Robert Grenley
		Director

Date: May 16, 2011	By:	/s/ David B. McCall
		David B. McCall
		Director

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders of

Victory Energy Corporation

Newport Beach, California

We have audited the accompanying balance sheets of Victory Energy Corporation (the “Company”) as of December 31, 2010 and 2009, and the related statements of operations, shareholders’ deficit and cash flows for 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 on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2010 and 2009, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming the Company will continue as a going concern. The Company has experienced recurring losses since inception and has an accumulated deficit. These conditions raise substantial doubt regarding the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are described in Note 1 to the financial statements. The financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of this uncertainty.

/s/ WilsonMorgan LLP

Irvine, California

May 16, 2011

F-1

VICTORY ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2010			2009

CURRENT ASSETS
Cash and cash equivalents	$	111,572		$	22,076
Accounts receivable, net		74,828			100,319
Prepaid expenses		24,898			46,818
Total current assets		211,298			169,213

FIXED ASSETS
Furniture and equipment		2,294			2,294
Accumulated depreciation		(2,294	)		(2,294	)
Total furniture and equipment		-			-

Option to acquire leases and mineral interest		25,000			-
Oil and natural gas properties		1,466,813			1,660,533
Accumulated depletion		(953,084	)		(853,152	)
Oil and natural gas properties, net		538,729			807,381

OTHER ASSETS
Funds held by court		13,006			13,006

TOTAL ASSETS	$	763,033		$	989,600

LIABILITIES AND STOCKHOLDERS' DEFICIT

CURRENT LIABILITIES
Accounts payable	$	342,285		$	240,310
Accrued liabilities		74,088			61,331
Accrued interest		10,501			27,148
Line of credit - bank		68,667			85,444
Notes payable - related parties		50,000			355,000
Liability for unauthorized preferred stock issued		85,654			85,654
Amounts due former officer		-			404,623
Total Current Liabilities		631,195			1,259,510

OTHER LIABILITIES
Senior convertible debenture, net of debt discount		127,338			-
Deferred tax liability		238,000			-
Asset retirement obligation		27,282			34,977
TOTAL LIABILITIES		1,023,815			1,294,487

STOCKHOLDERS' DEFICIT
Common Stock, $0.001 par value, 490,000,000 shares
authorized, 136,719,608 and 136,719,608
issued and outstanding, respectively		136,720			136,720
Additional paid in capital		31,740,090			31,263,272
Accumulated Deficit		(32,137,592	)		(31,704,879	)
TOTAL STOCKHOLDERS' DEFICIT		(260,782	)		(304,887	)

TOTAL LIABILITIES AND
STOCKHOLDERS' DEFICIT	$	763,033		$	989,600

F-2

VICTORY ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Years Ended December 31,
	2010			2009

REVENUES	$	491,558		$	512,607

COSTS AND EXPENSES
Costs of production		202,750			196,520
General and administrative expense		788,140			935,983
Depletion and accretion		102,484			291,867
Malfeasance losses		-			280,647
Impairment of oil and natural gas properties		183,473			342,366
Gain on settlement with former officer		(404,623	)		(1,199,748	)
Total costs and expenses		872,224			847,635

LOSS FROM OPERATIONS		(380,666	)		(335,028	)

OTHER EXPENSE
Interest expense		52,047			50,111
Total other expense		52,047			50,111

NET LOSS	$	(432,713	)	$	(385,139	)

Weighted average shares, basic and diluted		136,719,608			136,719,608
Net loss per share, basic and diluted	$	(0.00	)	$	(0.00	)

F-3

VICTORY ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOW

		For the Years Ended
		December 31,
		2010			2009

CASH FLOW FROM OPERATING ACTIVITIES
Net loss		$	(432,713	)	$	(385,139	)
Adjustment to reconcile net loss from operations to net cash used in operating activities
	Depletion and amortization		100,743			290,344
	Amortization of debt discount		-			8,997
	Accretion of asset retirement obligation		2,552			1,523
	Impairment of oil and natural gas properties		183,473			342,366
	Warrants for services		14,070			27,791
	Gain on settlement with former officer		(404,623	)		(1,199,748	)
Change in working capital
	Accounts receivable		25,491			(100,319	)
	Funds held by court		-			(7,342	)
	Prepaid expense		21,920			(39,568	)
	Accounts payable		101,975			202,053
	Accrued liabilities		51,385			88,369
	Asset retirement obligations		-			13,334
Net cash used in operating activities			(335,727	)		(757,339	)

CASH FLOWS FROM INVESTING ACTIVITIES
	Purchase of option		(25,000	)		-
	Drilled wells		-			(9,715	)
	Purchase of wells		-			(398,619	)
Net cash used in investing activities			(25,000	)		(408,334	)

CASH FLOWS FROM FINANCING ACTIVITIES
	Bank line of credit net repayments		(16,777	)		(8,909	)
	Proceeds from notes payable to related parties		192,000			325,000
	Proceeds from former officer		-			19,838
	Proceeds from unauthorized preferred stock issued		-			53,499
	Payments on notes payable to related parties		-			(353,673	)
	Payments to former officer		-			(61,004	)
	Sale of senior convertible debentures		275,000			-
	Aurora capital contributions		-			1,371,674
	Aurora capital distributions		-			(324,865	)
Net cash provided by financing activities			450,223			1,021,560

Net change in cash and cash equivalents			89,496			(144,113	)

Beginning cash and cash equivalents			22,076			166,189

Ending cash and cash equivalents		$	111,572		$	22,076

Supplemental schedule of non-cash investing and financing activities:
	Deferred tax liability	$	238,000		$	-
	Notes payable and accrued interest
	exchanged for senior convertible debentures -
	related party	$	552,275		$	-

Supplemental disclosures of cash flow information:
Cash paid during the period for
	Interest	$	-		$	-
	Income taxes	$	-		$	-

F-4

VICTORY ENERGY CORPORATION AND SUBSIDARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' DEFICIT

	Common Stock $0.001 Par				Additional Paid In			Accumulated			Total Equity
Description	Number		Amount		Capital			Deficit			(Deficit)
Balance, December 31, 2008		136,719,608	$	136,720	$	30,188,672		$	(31,319,740	)	$	(994,348	)

Warrants in exchange for services		-		-		27,792			-			27,792
Aurora capital contributions		-		-		1,371,673			-			1,371,673
Aurora capital distributions		-		-		(324,865	)		-			(324,865	)
Net loss for year		-		-					(385,139	)		(385,139	)
Balance, December 31, 2009		136,719,608	$	136,720	$	31,263,272		$	(31,704,879	)	$	(304,887	)

Financing discount on debentures sold, net		-		-		98,046			-			98,046
Financing discount on debentures exchanged, net		-		-		364,702			-			364,702
Warrants in exchange for services		-		-		14,070			-			14,070
Net loss for year		-		-		-			(432,713	)		(432,713	)
Balance, December 31, 2010		136,719,608	$	136,720	$	31,740,090		$	(32,137,592	)	$	(260,782	)

F-5

Victory Energy Corporation and Subsidiaries

Notes to the Consolidated Financial Statements

Note 1 – Financial Statement Presentation

Organization and nature of operations

Victory Energy Corporation (Pink Sheets symbol VYEY), formerly known as Victory Capital Holdings Corporation (the “Company”) was organized under the laws of the State of Nevada on January 7, 1982, under the name All Things, Inc. On March 21, 1985 the Corporation’s name was changed to New Environmental Technologies Corporation and on April 28, 2003 to Victory Capital Holdings Corporation. The name was changed finally to Victory Energy Corporation on May 3, 2006.

The business of the Company is to acquire, develop, produce and exploit oil and natural gas properties. The Company’s major oil and natural gas properties are located in Texas. The Company’s executive offices are located in Newport Beach, California and its operations offices are located in Austin, Texas.

The Company’s initial authorized capital consisted of 100,000,000 shares of $0.001 par value common voting stock and, as of the date of this filing, has authorized capital of 490,000,000 shares of $0.001 par value common stock.

Going Concern

As presented in the consolidated financial statements, the Company has incurred a net loss of $432,713 during the twelve months ended December 31, 2010, and losses are expected to continue in the near term. Current liabilities exceeded current assets by $419,897 and the accumulated deficit is $32,137,592 at December 31, 2010. Amounts outstanding and payable to creditors are in arrears and the Company is in negotiations with certain creditors to obtain extensions and settlements of outstanding amounts. The Company is currently in default on one of its debt obligations and the Company has no future borrowings or funding sources available under existing financing arrangements. Management anticipates that significant additional capital expenditures will be necessary to develop the Company’s oil and natural gas properties, which consist of proved and unproved reserves, some of which may be non-producing, before significant positive operating cash flows will be achieved.

Management's plans to alleviate these conditions include the renegotiation of certain trade payables, settlements of debt amounts with stock, and deferral of certain scheduled payments, as considered necessary. In addition, management is pursuing business partnering arrangements for the acquisition and development of its properties as well as debt and equity funding through private placements. Without outside investment from the sale of equity securities, debt financing or partnering with other oil and natural gas companies, operating activities and overhead expenses will be reduced to a pace that available operating cash flows will support.

The accompanying consolidated financial statements are prepared as if the Company will continue as a going concern. The consolidated financial statements do not contain adjustments, including adjustments to recorded assets and liabilities, which might be necessary if the Company were unable to continue as a going concern.

Note 2 – Summary of Significant Accounting Policies

Principles of consolidation

The accompanying consolidated financial statements are presented in accordance with accounting principles generally accepted in the United States of America. The consolidated financial statements include the accounts of the Company and Aurora Energy Partners, A Texas General Partnership. The Company holds a 15% equity interest in Aurora Energy Partners. Since the Company serves as managing partner and is responsible for managing all business operations of the partnership, the financial statements of Aurora have been consolidated with the Company. All significant intercompany transactions have been eliminated. The consolidated financial statements reflect necessary adjustments, all of which were of a recurring nature and are in the opinion of management necessary for a fair presentation.

Property and equipment

Property and equipment are recorded at cost. Cost of repairs and maintenance are expensed as they are incurred. Major repairs that extend the useful life of equipment are capitalized and depreciated over the remaining estimated useful life. When property and equipment are sold or otherwise disposed, the related costs and accumulated depreciation are removed from the respective accounts and the gains or losses realized on the disposition are reflected in operations. The Company uses the straight-line method in computing depreciation for financial reporting purposes.

F-6

Revenue Recognition

We use the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of gas and oil sold to purchasers. The volumes sold may differ from the volumes to which we are entitled based on our interests in the properties. Differences between volumes sold and entitled volumes create oil and gas imbalances which are generally reflected as adjustments to reported proved oil and gas reserves and future cash flows in our supplemental oil and gas disclosures. If our excess takes of natural gas or oil exceed our estimated remaining proved reserves for a property, a natural gas or oil imbalance liability is recorded in the consolidated balance sheet.

Allowance for Doubtful Accounts

We recognize an allowance for doubtful accounts to ensure trade receivables are not overstated due to uncollectability. Bad debt reserves are maintained for all customers based on a variety of factors, including the length of time receivables are past due, macroeconomic conditions, significant one-time events and historical experience. An additional reserve for individual accounts is recorded when we become aware of a customer's inability to meet its financial obligations, such as in the case of bankruptcy filings or deterioration in the customer's operating results or financial position. If circumstances related to customers change, estimates of the recoverability of receivables would be further adjusted.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, other assets, fixed assets, accounts payable, accrued liabilities and short-term debt. The estimated fair value of cash, accounts receivable, other assets, accounts payable, deferred revenue and accrued liabilities approximated their carrying amounts due to the short-term nature of these instruments. The carrying value of short-term debt also approximates fair value since their terms are similar to those in the lending market for comparable loans with comparable risks. None of these instruments are held for trading purposes.

The Company utilizes various types of financing to fund its business needs, including debt with warrants attached and other instruments indexed to its stock. The Company reviews its warrants and conversion features of securities issued as to whether they are freestanding or contain an embedded derivative and if so, whether they are classified as a liability at each reporting period until the amount is settled and reclassified into equity with changes in fair value recognized in current earnings.

Inputs used in the valuation to derive fair value are classified based on a fair value hierarchy which distinguishes between assumptions based on market data (observable inputs) and an entity’s own assumptions (unobservable inputs). The hierarchy consists of three levels:

	·	Level one – Quoted market prices in active markets for identical assets or liabilities;

	·	Level two - Inputs other than level one inputs that are either directly or indirectly observable; and

	·	Level three – Unobservable inputs developed using estimates and assumptions, which are developed by the reporting entity and reflect those assumptions that a market participant would use.

Determining which category an asset or liability falls within the hierarchy requires significant judgment. The Company evaluates its hierarchy disclosures each quarter. The following table presents all assets that were measured and recognized at fair value as of December 31, 2010 and 2009, and for the twelve months then ended on a non-recurring basis. The assets shown below were presented at fair value due to the impairment analysis indicating an estimated fair value below the carrying value for the proved oil and gas properties.

F-7

Fair value of assets measured and recognized at fair value on a non-recurring basis as of December 31, 2010 and 2009 were as follows:

As of December 31, 2010 and for the year then ended:

Description	Level 1		Level 2		Level 3		Total Realized (Loss) Due to Valuation			Total Unrealized (Loss)
Proved Properties (net)	$	—	$	—	$	538,729	$	(183,473	)	$	—
Totals	$		$	—	$	538,729	$	(183,473	)	$	—

As of December 31, 2009 and for the year then ended:

Description	Level 1		Level 2		Level 3		Total Realized (Loss) Due to Valuation			Total Unrealized (Loss)
Proved Properties (net)	$	—	$	—	$	807,381	$	(342,366	)	$	—
Totals	$		$	—	$	807,381	$	(342,366	)	$	—

The Company valued the Proved Properties at their fair value in accordance with the applicable Financial Accounting Standards Board (“FASB”) standard due to the impairment indicators prevalent as of December 31, 2010 and 2009. The inputs that were used in determining the fair value of these assets were Level 3 inputs. These inputs consist of but are not limited to the following: estimates of reserve quantities, estimates of future production costs and taxes, estimates of consistent pricing of commodities, 10% discount rate, etc. Impairment expense was recorded at both year ends at the amount the carrying value of the assets exceeded their estimated fair values as of December 31, 2010 and 2009.

Recent Accounting Pronouncements

Recently Issued Accounting Standards

F-8

Concentrations

There is a ready market for the sale of crude oil and natural gas. During 2010 and 2009, each of our fields sold all of its oil production to one purchaser for each field and all of its natural gas production to one purchaser for each field. However, because alternate purchasers of oil and natural gas are readily available at similar prices, we believe that the loss of any of our purchasers would not have a material adverse effect on our financial results

Accounting estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.

Oil and natural gas properties

The Company accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, all costs associated with property acquisitions, successful exploratory wells, all development wells, including dry hole development wells, and asset retirement obligation assets are capitalized. Additionally, interest is capitalized while wells are being drilled and the underlying property is in development. Costs of exploratory wells are capitalized pending determination of whether each well has resulted in the discovery of proved reserves. Oil and natural gas mineral leasehold costs are capitalized as incurred. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells, and oil and natural gas production costs. Capitalized costs of proved properties including associated salvage are depleted on a well-by-well or field-by-field (common reservoir) basis using the units-of-production method based upon proved producing oil and natural gas reserves. The depletion rate is the current period production as a percentage of the total proved producing reserves. The depletion rate is applied to the net book value of property costs to calculate the depletion expense. Proved reserves materially impact depletion expense. If the proved reserves decline, then the depletion rate (the rate at which we record depletion expense) increases, reducing net income. Dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs with gain or loss recognized upon sale. A gain (loss) is recognized to the extent the sales price exceeds or is less than original cost or the carrying value, net of impairment. Oil and natural gas properties are also subject to impairment at the end of each reporting period. Unproved property costs are excluded from depletable costs until the related properties are developed. See impairment discussed in “Long-lived assets and intangible assets” below.

F-9

We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to 10 years.

Long-lived assets and intangible assets

The Company accounts for intangible assets in accordance with the applicable ASC. Intangible assets that have defined lives are subject to amortization over the useful life of the assets. Intangible assets held having no contractual factors or other factors limiting the useful life of the asset are not subject to amortization but are reviewed at least annually for impairment or when indicators suggest that impairment may be needed. Intangible assets are subject to impairment review at least annually or when there is an indication that an asset has been impaired. While there are prospects for possible capital funding (either debt or equity), much is left to the market and outside instability. As such, at this time, management cannot anticipate with a comfortable degree of certainty if the appropriate amount of funding will be achieved and any funding will be diverted fully to its E&P activities. This will further postpone the Company’s ability to dedicate financial as well as human resources to its technology division in the short term future. As such, the Company has eliminated the division entirely.

For unproved property costs, management reviews these investments for impairment on a property-by-property basis if a triggering event should occur that may suggest that impairment may be required.

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the carrying amount of the asset, including any intangible assets associated with that asset, exceeds its estimated future undiscounted net cash flows, the Company will recognize an impairment loss equal to the difference between its carrying amount and its estimated fair value. The fair value used to calculate the impairment for producing oil and natural gas field that produces from a common reservoir is first determined by comparing the undiscounted future net cash flows associated with total proved properties to the carrying value of the underlying evaluated property. If the cost of the underlying evaluated property is in excess of the undiscounted future net cash flows, the future net cash flows are discounted at 10%, which the Company believes approximates fair value, to determine the amount of impairment.

The Company recorded $183,473 and $342,366 respectively for 2010 and 2009 upon determining that the Crockett County gas project required impairment.

Asset retirement obligation

In accordance with the applicable ASC, the Company recognizes the fair value of the liability for asset retirement costs in an entity’s balance sheet, as both a liability and an increase in the carrying values of such assets, in the periods in which such liabilities can be reasonably estimated. The present value of the estimated future asset retirement obligation (“ARO”), as of the date of acquisition or the date at which a successful well is drilled, is capitalized as part of the costs of proved oil and natural gas properties and recorded as a liability. The asset retirement costs are depleted over the production life of the oil and natural gas property on a unit-of-production basis.

The ARO is recorded at fair value and accretion expense is recognized as the discounted liability is accreted to its expected settlement value. The fair value of the ARO liability is measured by using expected future cash outflows discounted at the Company’s credit adjusted risk free interest rate.

Amounts incurred to settle plugging and abandonment obligations that are either less than or greater than amounts accrued are recorded as a gain or loss in current operations. Revisions to previous estimates, such as the estimated cost to plug a well or the estimated future economic life of a well, may require adjustments to the ARO and are capitalized as part of the costs of proved oil and natural gas property.

The following table is a reconciliation of the ARO liability for continuing operations for the twelve months ended December 31 2010 and 2009.

	Years Ended December 31,
	2010		2009
Asset retirement obligation at beginning of period	$	34,977	$	20,120
Liabilities incurred		-		628
Revisions to previous estimates		(10,247)		12,706
Accretion expense		2,552		1,523
Asset retirement obligation at end of period	$	27,282	$	34,977

F-10

Income taxes

The Company accounts for income taxes in accordance with ASC 740 “Income Taxes” which requires an asset and liability approach for financial accounting and reporting of income taxes. Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws and regulations. Deferred tax assets include tax loss and credit carry forwards and are reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

On January 1, 2007, the Company adopted the FASB Interpretation on accounting for uncertainty in income taxes. The interpretation prescribes a measurement process for recording in the financial statements uncertain tax positions taken or expected to be taken in a tax return. Additionally, the interpretation provides guidance regarding uncertain tax positions relating to derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company will classify any interest and penalties associated with income taxes as interest expense.

Stock based compensation

Beginning January 1, 2006, the Company adopted the FASB standard for accounting for stock based compensation to account for its issuance of warrants to key partners, directors and officers. The standard requires all share-based payments, including employee stock options, warrants and restricted stock, be measured at the fair value of the award and expensed over the requisite service period (generally the vesting period). The fair value of common warrants granted to key partners, directors and officers is estimated at the date of grant using the Black-Scholes option pricing model by using the historical volatility of comparable public companies. The calculation also takes into account the common stock fair market value at the grant date, the exercise price, the expected life of the common stock option or warrant, the dividend yield and the risk-free interest rate.

The Company from time to time may issue stock options, warrants and restricted stock to acquire goods or services from third parties. Restricted stock, options or warrants issued are recorded on the basis of their fair value, which is measured as of the date issued. The options or warrants are valued using the Black-Scholes option pricing model on the basis of the market price of the underlying equity instrument on the “valuation date,” which for options and warrants related to contracts that have substantial disincentives to non-performance, is the date of the contract, and for all other contracts is the vesting date. Expense related to the options and warrants is recognized on a straight-line basis over the shorter of the period over which services are to be received or the vesting period.

The Company recognized stock-based compensation expense from warrants granted to directors for the twelve months ended December 31, 2010 and 2009 were $14,070 and $27,791, respectively.

Earnings per share

Basic earnings per share are computed using the weighted average number of common shares outstanding. Diluted earnings per share reflect the potential dilutive effects of common stock equivalents such as options, warrants and convertible securities. Due to the Company incurring a net loss from continuing operations during the twelve months ended December 31, 2010 and 2009, basic and diluted net loss per share are the same as all potentially dilutive common stock equivalents are anti-dilutive. The Company excluded 14,237,226 and 10,362,226, warrants, respectively, from the calculation for the years ended December 31, 2010 and 2009, as the exercise prices were in excess of the average closing price of the Company’s common stock for those periods.

Note 3 – Oil and natural gas properties

Oil and natural gas properties are comprised of the following at December 31:

	December 31,
	2010			2009
Option to acquire oil and mineral lease	$	25,000		$	—
Proved property – purchased wells		3,015,322			3,022,153
Proved property – drilled wells		1,753,026			1,756,442
Total oil and natural gas properties, cost		4,793,348			4,778,595
Less: accumulated depreciation , depletion and impairment		(4,254,619	)		(3,971,214	)
Oil and natural gas properties, net	$	538,729		$	807,381

F-11

Depletion expense for the years ended December 31, 2010 and 2009 was $99,932 and 290,344, respectively. During the years ended December 31, 2010 and 2009, the Company recorded impairment losses of $183,472 and $342,366 respectively.

Note 4 –Loans payable to related parties

Loans payable to related parties as of December 31, 2010 and 2009 were as follows.

	December 31,
	2010		2009
Loan payable to former CEO and shareholder	$	—	$	404,623
Total loans payable to related parties	$	—	$	404,623

The loans payable are due on demand and do not bear interest.

On March 24, 2011 the former CEO and shareholder waived his claim to this loan payable as part of a comprehensive settlement agreement with the Company (see Note 7). The Company realized a gain on settlement of $404,623 in 2010 as a result of the cancellation of this debt.

Note 5 – Unsecured notes payable to related parties

Unsecured notes payable to related parties as of December 31, 2010 and 2009 were as follows.

	December 31,
	2010		2009
Notes payable to a shareholder and director, unsecured, 10% interest payable at maturity, due on December 31, 2010	$	—	$	305,000
Note payable to an affiliate of a shareholder and director, unsecured, 10% interest payable at maturity, due on December 31, 2010		50,000		50,000
Total notes payable to related parties	$	50,000	$	355,000

The notes payable to a shareholder and director matured on December 31, 2010. These notes plus additional notes for $167,000 for cash received in 2010 and for cash advanced to purchase of the Padre Island, Texas option along with accrued interest of $55,275, were converted into a Senior Secured Convertible Debenture on December 31, 2010. See Notes 8 and 14.

The note payable to an affiliate of a shareholder and director was extended by 90 days on December 31, 2010. The note and the accrued interest were paid on March 22, 2011.

Note 6 – Line of credit payable to Wells Fargo Bank

On October 7, 2008, the Company executed an unsecured Business Line of Credit Agreement with Wells Fargo Bank, National Association. The Credit Agreement provides the Company with a line of credit facility in the aggregate amount of $96,761. Interest on the loan is payable monthly, at the rate of 10.0% per annum. Payments of $2,055, including interest, are due on the line of credit and the line matures on October 13, 2013. The line of credit was personally guaranteed by the Company’s former CEO and shareholder.

During the year ended December 31, 2010, the Company defaulted on its monthly loan payments to Wells Fargo Bank and the loan was referred to the Bank’s workout department. The Company has negotiated an informal repayment program with the Bank’s workout department whereby the Bank will not institute collection actions provided the Company continues to make monthly principal payments of $2,200 to the Bank. As of December 31, 2010, the Company was current on the terms of this line of credit.

	December 31,
	2010		2009
Line of credit payable to Wells Fargo Bank, 10% interest payable at maturity, due on October 13, 2013	$	68,667	$	85,444

F-12

Note 7 – Separation Settlement Payable to former officer and shareholder

During the year ended December 31, 2009, Fullenkamp filed a lawsuit against the Company. The Company subsequently filed a lawsuit against Fullenkamp and others on January 19, 2010, in Midland County, Texas.

NOTE 8 – Senior Secured Convertible Debentures

Between October 15, 2010, and April 22, 2011, the Company entered into agreements with 33 accredited investors for the cash sale by the Company of an aggregate of $1,535,000 of 10% Senior Secured Convertible Debentures (the “Debentures”) which are convertible into an aggregate of 307,000,000 shares of the Company’s common stock at a conversion price of $0.005 per share of common stock, subject to adjustment. The maturity date of the Debentures is September 30, 2013, but may be extended at the sole discretion of the Company to December 31, 2013. The Debentures are immediately convertible by the holder into shares of the Company’s common stock at a conversion price of $0.005 per share, subject to customary adjustments for stock splits, stock dividends, recapitalizations and the like. The Company has the right to force conversion of the Debenture if, among other things, the closing sales price of the Company’s common stock is equal to or exceeds $0.025 for twenty (20) consecutive trading days. In connection with this offering, the Company also issued five (5) year warrants to purchase an aggregate of 1,535,000 shares of the Company’s common stock at an exercise price of $0.005 per share, subject to adjustment, to the investors. The cash proceeds of $1,535,000 were allocated to working capital. The Debentures are secured under the terms of a Security Agreement by a security interest in all of the Company’s personal property. The relative fair value of the warrants and beneficial conversion features of the debentures were determined at the time of issuance using the methodology prescribed by current accounting guidance.

Between October 15, 2010 and December 31, 2010, the Company issued debentures for cash of $275,000. The Company determined the initial fair value of the beneficial conversion feature was approximately $1,887. The Company also determined that the relative fair value of the warrants upon issuance was $146,586 which was calculated under a Black-Scholes option pricing model using as assumptions an expected life of 3 years, a stock volatility ranging from 619.3% to 671.5% , a risk free interest rate ranging from 1.2% to 2.1%, and no expected dividend yield. The initial fair value of the warrants of $1,887 and the beneficial conversion feature of $146,586 were recorded by the Company as a financing discount of $148,473, which the Company is amortizing to interest expense over the life of the notes.

F-13

On December 31, 2010, the Company exchanged notes payable of $497,000 and accrued interest of $55,275 both due to a related party for $552,275 of the Company’s 10% Senior Secured Convertible Debenture in (1). No warrants were issued in the transaction. The Company determined that the fair value of the beneficial conversion feature on the date of exchange was equal to the face value of the debenture of $552,275 in this exchange and was recorded as a financing discount which the Company is amortizing to interest expense over the life of the notes.

Senior secured convertible debentures consists of the following at December 31, 2010:

	2010
Convertible debenture, interest at 10% per annum payable quarterly, due September 30, 2013 with separable warrants (1)	$	275,000
Convertible debenture, interest at 10% per annum payable quarterly, due September 30, 2013 issued in exchange for notes payable and accrued interest to related party (2)		552,275
Subtotal		827,275
Debt discount		(699,937	)
Net book value	$	127,338

Amortization of debt discount totaled $811 for the year ended December 31, 2010.

Note 9 – Liability for Unauthorized Preferred Stock Issued

During the year ended December 31, 2006, the Company authorized 10,000,000 shares of Preferred Stock, convertible to common stock at the rate of 100 shares of common for every share of preferred. During 2006, the Company issued 715,517 of this preferred stock for cash of $246,950. The Company subsequently issued additional preferred stock and had several preferred shareholders convert their shares into common stock during the years ended December 31, 2009, 2008, and 2007.

During the course of the Company’s internal investigation, it was determined by the Company’s legal counsel that the preferred shares had not been duly authorized by the State of Nevada. Since the Company had issued and received consideration for the preferred stock, notwithstanding that the stock was not legally authorized, the Company reclassified the preferred stock into a liability at its cash receipt value. The Company has offered to settle the debt with the remaining holders of the unauthorized preferred stock by honoring the terms of conversion of one share of preferred into 100 shares of common stock.

The preferred stock liability as of the December 31, 2010 and 2009 was as follows:

	December 31,
	2010		2009
Liability for unauthorized preferred stock	$	85,654	$	85,654

Note 10 – Income Taxes

As a result of net operating losses and the inability to record a benefit for its deferred income tax assets, the Company has no income tax provision for the years ended December 31, 2010 and 2009.

The Internal Revenue Code of 1986, as amended, imposes substantial restrictions on the utilization of net operating losses in the event of an “ownership change” of a corporation. Accordingly, a company’s ability to use net operating losses may be limited as prescribed under Internal Revenue Code Section 382 (“IRC Section 382”). Events which may cause limitations in the amount of the net operating losses that the company may use in any one year include, but are not limited to, a cumulative ownership change of more than 50% over a three-year period. There have been transactions that have changed the Company’s ownership structure since inception that may have resulted in one or more ownership changes as defined by the Internal Revenue Code of 1986.

At December 31, 2010 and 2009, the Company had available Federal and state net operating loss and capital loss carry forwards to reduce future taxable income. The net operating loss carryovers available were approximately $2,896,000 and $2,373,000 for federal and for state purposes, respectively. The Federal net operating loss carry forward begins to expire in 2025. Capital loss carryovers may only be used to offset capital gains. The capital loss carryover available was $50,900 for each of those years and expired in 2010.

F-14

Given the Company’s history of net operating losses, management has determined that it is more-likely-than-not the Company will not be able to realize the tax benefit of the carry forwards. Current standards require that a valuation allowance be established when it is more likely than not that all or a portion of deferred tax assets will not be realized.

Accordingly, the Company has recorded a full valuation allowance against its net deferred tax assets at December 31, 2010 and 2009. Upon the attainment of taxable income by the Company, management will assess the likelihood of realizing the tax benefit associated with the use of the carry forwards and will recognize a deferred tax asset at that time. For the years ended December 31, 2010 and 2009, the valuation allowance increased/(decreased) by $35,300 and ($120,800) respectively.

Significant components of the Company’s deferred income tax assets are as follows:

	December 31,
	2010			2009
Net operating and capital loss carry forwards	$	984,600		$	824,100
Property		156,100			159,000
Accounts payable and accrued expenses		15,500			70,200
Malfeasance Loss		265,700			265,700
Equity based compensation		4,130,700			4,125,900
AR and prepaid expenses		(3,800	)		(8,300	)
Valuation discount		(5,472,100	)		(5,436,600	)
Debt discount		(238,000	)		—
Deferred income		(76,700	)		—
Net deferred income tax liability	$	(238,000	)	$	—

F-15

Reconciliation of the effective income tax rate to the U.S. statutory rate is as follows:

	December 31
	2010		2009
Tax benefit at the U.S. statutory income tax	34.0	%		34.0	%
State income tax net of federal benefit	0.0	%		0.0	%
Permanent differences	(24.2)	%		(59.9)	%
Expiration of loss carryovers	(3.2)	%		—
Change in valuation allowance	(6.6)	%		25.9	%
Effective tax rate	0.0	%		0.0	%

The Company adopted authoritative guidance in accordance with GAAP which addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under the current accounting guidelines, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. Current accounting guidelines also provide guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and require increased disclosures. At the date of adoption, and as of December 31, 2010 and 2009 the Company does not have a liability for unrecognized tax benefits.

Note 11 – Stockholders’ Equity

For the year ended December 31, 2010

Common stock

No common stock was issued, converted, or retired in 2010.

During 2010, the Company granted 3,875,000 warrants to purchase the Company’s common stock with an exercise price ranging from $0.005 to $.01 per share to the Company’s Board of Directors in connection with the services rendered. These warrants expire in five years from the date of grant. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $14,070.

For the year ended December 31, 2009

Common stock

No common stock was issued, converted, or retired in 2009.

Warrants

During 2009, the Company granted 548,669 warrants to purchase the Company’s common stock with an exercise price of $0.25 per share in connection with the consulting services rendered. These warrants expire in fifteen years from the date of grant. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $3,162.

During 2009, the Company granted 5,100,000 warrants to purchase the Company’s common stock with an exercise price of $0.01 per share to the Company’s Board of Directors in connection with the services rendered. These warrants expire in five years from the date of grant. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $27,792.

F-16

Note 12 – Stock Warrants

At December 31, 2009, warrants shares outstanding were as follows:

	Shares		Weighted Average Exercise Price
Balance at January 1, 2009		4,713,557	$	0.26
Granted		5,648,669	$	0.03
Exercised		—		—
Cancelled		—		—
Balance at December 31, 2009		10,362,226	$	0.14

At December 31, 2010, warrants shares outstanding were as follows:

	Shares			Weighted Average Exercise Price
Balance at January 1, 2010		10,362,226		$	0.14
Granted		3,875,000		$	0.01
Exercised		—			—
Cancelled		(400,000	)	$	0.01
Balance at December 31, 2010		13,837,226		$	0.11

The following table summarizes information about stock warrants outstanding and exercisable as of December 31, 2009:

	Warrants Outstanding					Warrants Exercisable
Range of Exercise Prices	Number of Shares Underlying Warrants	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (in years)		Number of Shares		Weighted Average Exercise Price
$0.01 - $0.25	10,362,226	$	0.14		8.64		10,362,226	$	0.14
	10,362,226						10,362,226

The following table summarizes information about stock warrants outstanding and exercisable as of December 31, 2010:

	Warrants Outstanding						Warrants Exercisable
Range of Exercise Prices	Number of Shares Underlying Warrants		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (in years)		Number of Shares		Weighted Average Exercise Price
$0.005 - $0.35		13,837,226	$	0.11		6.89		13,837,226	$	0.11
		13,837,226						13,837,226

F-17

All future changes in the fair value of these warrants will be recognized currently in earnings until such time as the warrants are exercised or expire. These common stock purchase warrants do not trade in an active securities market, and as such, we estimate the fair value of these warrants using the Black-Scholes option pricing model using the following assumptions:

	2010			2009
Risk free rate		1.17%-2.55	%		1.67% - 3.85	%
Expected life	5 years			5-15 years
Volatility		586.7 – 677.8	%		542.7 – 585.4	%
Dividend yield		0	%		0	%

Expected volatility is based primarily on historical volatility. Historical volatility was computed using weekly pricing observations for recent periods that correspond to the remaining life of the warrants. We believe this method produces an estimate that is representative of our expectations of future volatility over the expected term of these warrants. We currently have no reason to believe future volatility over the expected remaining life of these warrants is likely to differ materially from historical volatility. The expected life is based on the remaining term of the warrants. The risk-free interest rate is based on U.S. Treasury securities.

At December 31, 2010 and 2009 the aggregate intrinsic value of the warrants outstanding and exercisable was $18,428 and zero, respectively.

Note 13 – Commitments and Contingencies

Leases

Rent expense for the years ended December 31, 2010 and 2009 was $23,095, and $43,500, respectively. The Company is committed for $21,000 through January 31, 2012, on an operating lease for office space in Austin, Texas.

Litigation

The Company has filed litigation to pursue acts of malfeasance against the Company, and it is subject to other cases that have arisen in the ordinary course of business, the majority of which have resulted from its thorough restructuring efforts. Many of these claims have been resolved. Management believes individually such litigation and claims will not have a material adverse impact on our financial position or our results of operations but these matters are subject to inherent uncertainties and management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position and the results of operations for the period in which the effect becomes reasonably estimable.

The following describes legal action being pursued by the Company and against the Company.

Victory Energy Corporation and James Capital Energy, LLC filed a lawsuit in Midland County, Texas, under Cause No. CV-47230, against Jim Dial, Jon Fullenkamp, Remuda Operating Company and other parties related to Jim Dial. The lawsuit alleges fraud, breach of fiduciary duty, and other claims that Victory and JCE allege against these parties. This lawsuit seeks to recover damages in excess of $10.0 million, plus punitive damages.

The final judgment awards Victory Energy Corporation and James Capital Energy, LLC, the plaintiffs, compensatory damages against five of the defendants in the amount of $5.6 million, jointly. The court also awarded punitive damages against each of these defendants in the amount of $2.2 million per defendant, for a total punitive damage award of $11.2 million. Additionally, the court awarded the plaintiffs pre-judgment interest and attorney fees.

F-18

The Company will continue to pursue its claims against the remaining defendants, Remuda Operating Company, Ozona Natural Gas, LLC, Taylor Drilling and Ronnie Taylor.

The Company is an Intervener in a case pending in Crockett County, Texas under cause No. 08-04-07047-CV, and styled Oz Gas Corporation v Universal Energy Resources, Inc., et al, in which the plaintiff is seeking to establish ownership of the 155-2 well on the grounds that the well was illegally drilled on property belonging to the plaintiff. The Company intervened in this action to protect its interests in the 155-2 well and to recover its share of suspended money now being held in the court’s registry. On information and belief the court is holding funds in excess of $100,000.00 from the 155-2 well pending the outcome of this action.

On November 25, 2009, Jon Fullenkamp (“Fullenkamp”) filed a lawsuit in Orange County, California, against Victory, James Capital Energy, LLC, two of the Company’s directors, Bob Miranda and Ron Zamber, and other parties alleging fraud, breach of contract, libel, slander and other claims. After several attempts to amend the complaints were rejected by the Court, on February 17, 2011, the Court accepted the Fullenkamp complaint.

This matter, as well as the civil action filed in Midland County, Texas has been resolved through the comprehensive Settlement Agreement, as discussed herein.

On September 6, 2010, the Company and its operator, Cambrian Management, Ltd. (“Cambrian”), were named in a case pending in Midland, Texas under case No. 10-09-07213. The plaintiffs allege that the Company and Cambrian, along with other defendants, were trespassers on their land and drilled a well (#115-8) on land belonging to the plaintiffs. The plaintiffs claim trespass and unjust enrichment by certain defendants because of the drilling of the #115-8 well.

Discovery is ongoing on this matter and a trial has not been set at this time. Victory and Cambrian are in the process of completing some title work to decide which direction to go on this case. If the Company is not victorious in this case, it risks losing its investment in the well #115-8.

On March 18, 2011, the Company filed a lawsuit against its former independent auditor, John Kinross-Kennedy, CPA, for professional negligence in the audits of the company’s 2006 through 2007 financial statements, and the preparation of the 2008 quarterly forms 10Q. The lawsuit seeks compensatory damages, costs of suit, and other relief as may be deemed just and proper by the Court.

Note 14 - Related Party Transactions

The Notes have a total principal amount of $497,000 and have accumulated interest in the amount of $55,275. In consideration of the loan extension, the Notes and all accumulated interest were cancelled and the Company issued the Debenture to Visionary with a total face value of $552,275. The Debenture bears interest at the rate of 10% per year payable at maturity. The maturity date of the Debenture is September 30, 2013, but may be extended at the sole discretion of the Company to December 31, 2013. The Debenture is immediately convertible by the holder into shares of the Company’s common stock at a conversion price of $0.005 per share, subject to customary adjustments for stock splits, stock dividends, recapitalizations and the like. The Company has the right to force conversion of the Debenture if, among other things, the closing sales price of the Company’s common stock is equal to or exceeds $0.025 for twenty (20) consecutive trading days. The total number of shares of common stock issuable upon conversion of the Debenture is 110,455,000

F-19

Note 15 –

Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited)

The following disclosures provide unaudited information required by the FASB standard on oil and gas producing activities.

Results of operations from oil and natural gas producing activities

The Company’s oil and natural gas properties are located within the United States. The Company currently has no operations in foreign jurisdictions. Results of operations from oil and natural gas producing activities are summarized below for the years ended December 31:

		Years Ended December 31,
		2010			2009
Revenues	$	469,200		$	512,607

Costs incurred:
Lease operating, production, and royalties		285,061			196,520
Impairment of oil and natural gas reserves		183,473			342,366
Accretion of asset retirement obligation		2,552			1,523
Depletion, depreciation and amortization		100,743			290,344

Totals, costs incurred		571,829			830,753

Pre-tax income (loss) from producing activities		(102,629	)		(318,146)
Results of oil and natural gas producing activities (excluding overhead and interest costs)	$	(102,629	)	$	(318,146)

Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below for the years ended December 31, 2010 and 2009.:

	Years Ended December 31,
	2010		2009
Property acquisition costs:
Proved	$	—	$	395,000
Unproved		—		—
Exploration costs		—		289,460
Development costs		—		—
Asset retirement obligations		—		13,334
Totals costs incurred	$	—	$	697,764

Oil and natural gas reserves

Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods.

Proved oil and natural gas reserve quantities at December 31, 2010 and 2009, and the related discounted future net cash flows are based on estimates prepared by independent petroleum engineers. The reserves as of December 31, 2010 were derived from reserve estimates prepared by the independent reserve engineer; James Nicolson. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission. In 2009 the SEC issued guidance requiring oil and gas companies to calculate the value of proved reserves using prices that were calculated as the average price of the first day of the twelve months in the year. This guidance differed from the previous standard of valuing prices according to the end of year prices. The guidance does not require that prior year information be revised for the new method. As a result, this change in methods of pricing should be taken into account while reviewing the comparable information for 2010 and 2009 within this disclosure.

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Standardized measure

The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved oil and natural gas reserves for the years ended December 31, 2010 and 2009 are shown below:

	Years Ended December 31,
	2010			2009
Natural gas:

Proved developed and undeveloped reserves (mcf):
Beginning of year		748,700			824,460
Purchase of natural gas properties in place					59,249
Discoveries and extensions
Revisions		51,971			(28,540	)
Production		(90,971	)		(106,469	)
Proved reserves, at end of year		709,700			748,700

		Years Ended December 31,
		2010			2009
Future cash inflows	$	4,314,940		$	3,601,210
Future costs:
Production		(431,490	)		(360,120	)
Development		(1,803,300	)		(1,666,490	)

Future cash flows		2,080,150			1,574,600
10% annual discount for estimated timing of cash flow		(1,099,070	)		(575,480	)

Standardized measure of discounted cash flow	$	981,080		$	999,120

Average product prices for gas respectively for 2010 and 2009 were $6.08/MCF and $4.81/MCF, respectively. In neither year was the Company allowed to value assets attributable to Proved Undeveloped or Probable Reserves because of the SEC guidelines requiring available capital to monetize the projects.

Future income taxes are based on year-end statutory rates, adjusted for tax basis of oil and natural gas properties and availability of applicable tax assets, such as net operating losses. A discount factor of 10% was used to reflect the timing of future net cash flows.

The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair value may also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and may require a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

Changes in standardized measure

Included within standardized measure are reserves purchased in place. The purchase of reserves in place includes undeveloped reserves which were acquired at minimal value that have been estimated by independent reserve engineers to be recoverable through existing wells utilizing equipment and operating methods available to the Company and that are expected to be developed in the near term based on an approved plan of development contingent on available capital.

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Changes in the standardized measure of future net cash flows relating to proved oil and natural gas reserves for the years ended December 31 is summarized below:

		December 31,
		2010			2009
Increase (decrease)
Sale of natural gas, net of natural gas operating expenses	$	(296,343	)	$	(316,492	)
Purchase of natural gas properties in place		---			52,110
Discoveries, extensions and improved recovery, net of future production and development costs		—
Accretion of discount		144,126			124,897
Net change in sales prices, net of production costs		316,177			(75,135	)
Net increase (decrease)		163,960			(214,620	)
Standardized measure of discounted future cash flows:
Beginning of the year		817,120			1,031,740
End of the year	$	981,080		$	817,120

Note 16 – Subsequent Events

Investment in Assignment of Working Interest in Oil Exploration Project in Jones County, Texas

On February 14, 2011, the Company, through its Aurora Energy Partners affiliate (“Aurora”), executed a Partial Assignment, Bill of Sale and Conveyance (the “Assignment”) with C.O. Energy assigning to Aurora Energy Partners a working interest in two oil and gas leases located in Jones County, Texas (the “Leases”). Pursuant to the Assignment, Aurora is entitled to a two and one-half percent (2½%) working interest in the Leases, including an interest in all production and all personal property located on the land covered by the Leases. The Assignment is effective February 1, 2011.

On February 14, 2011, Aurora and C.O. Energy also entered into a letter of intent whereby the parties anticipate C. O. Energy will convey to Aurora a one and one-half percent (1½%) working interest in a new oil and gas exploration project located in Jones County, Texas (the “Project”). In addition to this working interest in the Project, Aurora will have the option to purchase, accompanied with a right of first refusal, an interest in each prospect well developed on the Project by C. O. Energy. The letter of intent is non-binding and is contingent upon the parties reaching a definitive agreement.

Victory Energy Corporation (the “Company”) is the managing partner of Aurora and has a fifteen percent (15%) partnership interest in Aurora.

Investment in Working Interest in Pecos County, Texas Oil and Gas Well Interest

On April 14, 2011, Aurora acquired a working interest in the University 6 #1 oil and gas prospect (“Tunis Creek”). The company acquired the prospect from well known Midland Texas-based V-F Petroleum Inc., who will also be the operator of the well. The company acquired a 5 percent working interest (WI) and a 3.75 percent net revenue interest (NRI) and anticipates this well to spud near the end of April. The Tunis Creek prospect is located twenty-five miles due east of Fort Stockton, Texas in eastern Pecos County, and is surrounded by significant hydrocarbon shows in all three targeted horizons. The prospect has been permitted to test the Wichita, Albany, Wolfcamp and Ellenburger formations. The operator plans to drill the Tunis Creek prospect to a total depth of 7,500 feet. The 1,600 acre lease comprises two sections of block 20, University Lands survey.

Investment in Working Interest in Alwan West Natural Gas Prospect

On April 25, 2011, Aurora acquired a working interest in the Alwan West natural gas prospect. The Alwan West prospect will be the largest natural gas well drilled by Victory Energy to date. This prospect’s potential reservoir covers an area of 175 acres. It has a reserve potential of 8.75 billion cubic feet (BCF) of natural gas and 43.75 thousand barrels of gas condensate. The reserve potential is based on 50 feet of reservoir sand, one million cubic feet per acre-foot of natural gas and five barrels per million cubic feet of gas condensate. These reserve estimates are for the first Yegua sand only, which is the primary objective, and do not include potential in the secondary objectives. The Alwan West prospect is located in far western Wharton County, Texas, near the Jackson County line.

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Settlement of Litigation

Amendment to Private Placement Memorandum of 10% Senior Secured Convertible Debentures and related Warrants

In May 2011, the holders of 67% of the 10% Senior Secured Convertible Debentures and related warrants agreed to an amendment proposed by the Company of the Private Placement Memorandum, 10% senior secured convertible debentures, and related warrants to remove a condition under which the Company would be required to unilaterally adjust the conversion price of the convertible debenture and the exercise price of the warrants if the Company issued securities at a price below the stated conversion price of $.005 per share. As of December 31, 2010, the company had raised $275,000 of funds from the sale of these private securities to four (4) accredited investors. 100% of these investors agreed to the amendment described herein. The Company also authorized an increase in the total amount to be raised from the Private Placement Memorandum from $750,000 to $2.0 million. The Company also extended the closing of the Private Placement Memorandum from its original closing date of March 31, 2011 to a new closing date of June 30, 2011.

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