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, 2012
 
OR
 
¨
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
 
87-0564472
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
     
3355 Bee Caves Road, Suite 608, Austin, Texas
 
78746
(Address of principal executive offices)
 
(Zip Code)
 
Registrant’s telephone number, including area code: 512-347-7300

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
o
Accelerated Filer
o
Non-Accelerated Filer
o
Smaller Reporting Company
x
(do not check if Smaller Reporting Company)      
 
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 common equity held by non-affiliates of the registrant, computed by reference to the closing price of such stock on June 29, 2012 was approximately $23,012,225 based on the closing price of such stock and such date of $1.05.
 
The number of shares outstanding of the Registrant’s common stock, $0.001 par value, as of November 12, 2013 was 27,563,619.
 


 
 

 
VICTORY ENERGY CORPORATION
ANNUAL REPORT ON
 
 FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2012
 
TABLE OF CONTENTS
 
Table of Contents
 
PART I      
         
Item 1.
Business
    5  
           
Item1A.
Risk Factors
    14  
           
Item 1B.
Unresolved Staff Comments
    21  
           
Item 2.
Properties
    22  
           
Item 3.
Legal Proceedings
    28  
           
Item 4. Mine Safety Disclosure     28  
           
PART II        
           
Item 5.
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
    29  
           
Item 6.
Selected Financial Data
    30  
           
Item 7.
Management Discussion and Analysis of Financial Condition and Results of Operations
    30  
           
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
    50  
           
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
    51  
           
Item 9A.
Controls and Procedures
    51  
           
Item 9B.
Other Information
    52  
           
PART III
       
           
Item 10.
Directors, Executive Officers and Corporate Governance
    53  
           
Item 11.
Executive Compensation
    55  
           
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
    57  
           
Item 13.
Certain Relationships and Related Transactions, and Director Independence
    58  
           
Item 14.
Principal Accounting Fees and Services
    58  
           
PART IV        
           
Item 15.
Exhibits, Financial Statement Schedules
    59  
           
SIGNATURES     62  
         
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM     F-1  
 
 
2

 
 
EXPLANATORY NOTE
 
Unless otherwise indicated or the context otherwise requires, all references in this Annual Report on Form 10-K (“Report”) to “we,” “us,” “our,” “Victory Energy Corporation” and the “Company” are to Victory Energy Corporation, a Nevada corporation, and, unless the context otherwise requires, includes Aurora Energy Partners, a Texas general partnership (“Aurora”). Aurora is a consolidated subsidiary of Victory Energy Corporation for financial statement purposes. Victory Energy Corporation is a 50% partner and the managing partner of Aurora. Unless otherwise indicated, references herein to “$” or “dollars” are to United States dollars and have been presented in accordance with U.S generally accepted accounting principles.
 
The Company has assessed the amount of non-controlling interest that should be separately stated on the face of the Company’s consolidated financial statements and is restating its consolidated financial statements for the impacted periods in this Comprehensive Annual Report on Form 10-K for the fiscal year ended December 31, 2012. The non-controlling interest in Aurora is separately identified in the consolidated stockholders equity section of the consolidated financial statements. As a result of this restatement, the Company estimates that its net loss per share will improve by the effect of the non-controlling interest in the loss of Aurora.
 
The Company has labeled the 2011 financial information in the Form 10-K “As Restated” and provided explanatoryfootnote disclosures. The Company has also provided quarterly financial information for 2011 and 2012, reconciling the restated quarterly consolidated balance sheets and statements of operations to those included in the Affected Reports. The Audit Committee of the Company’s Board of Directors discussed the matters described in this Report with the Company’s independent accountants.
 
Cautionary Notice Regarding Forward Looking Statements
 
We desire 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.
 
 
3

 
 
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. Our actual results, performance or achievements could differ materially from the results expressed in, or implied by, these forward-looking statements. In particular, our business, including our financial condition and results of operations and our ability to continue as a going concern may be impacted by a number of factors, including, but not limited to, the following:
 
· continued operating losses;
· our auditors questioning of our ability to continue as a going concern;
· difficulties in raising additional capital;
· challenges in growing our business;
· designation of our common stock as a “penny stock” under SEC regulations;
· FINRA requirements that may limit the ability to buy and sell our common stock;
· volatility in the price of our common stock;
· the highly speculative nature of an investment in our common stock;
· climate change and greenhouse gas regulations;
· global economic conditions;
· the substantial amount of capital required by our operations;
· the volatility of oil and natural gas prices;
· the high level of risk associated with drilling for and producing oil and natural gas;
· assumptions associated with reserve estimates;
· the potential that drilling activities will not yield oil or natural gas in commercial quantities;
· seismic studies may not guarantee the presence of oil or natural gas in commercial quantities;
· potential exploration, production and acquisitions may not maintain revenue levels in the future;
· future acquisitions may yield revenues or production that differ significantly from our projections;
· difficulties associated with managing a small and growing enterprise;
· strong competition from other oil and natural gas companies;
· the unavailability or high cost of drilling rigs and related equipment;
· our inability to control properties that we do not operate;
· our dependence on key management personnel and technical experts;
· the potential for write-downs in the carrying values of our oil and natural gas properties;
· our compliance with complex laws governing our business;
· our failure to comply with environmental laws and regulations;
· the financial condition of the operators of the properties in which we own an interest;
· terrorist attacks on our operations;
· the dilutive effect of additional issuances of our common stock, options or warrants;
· any impairments of our oil and natural gas properties; and
· the results of pending litigation; and
· state regulatory policies regarding spacing of wells and units.
 
 
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PART I
 
Item 1. Business
 
The Company
 
Victory Energy Corporation was organized under the laws of the State of Nevada on January 7, 1982. The Company is authorized to issue 47,500,000 shares of $0.001 par value common stock. On January 12, 2012 the Company implemented a 50:1 reverse stock split. All information in this Annual Report on Form 10-K reflects the stock split.
 
Prior to May 3, 2006 the Company operated as Victory Capital Holdings Corporation among other corporate names.
 
Copies of the initial Articles of Incorporation of the Company and the Certificates of Amendment to the Articles of Incorporation are incorporated herein by reference.

Our Relationship with Aurora Energy Partners

Victory Energy Corporation is the managing partner of Aurora Energy Partners, a Texas General Partnership (“Aurora”), and holds a 50% partnership interest in Aurora. Aurora is a consolidated subsidiary with Victory Energy Corporation for financial statement purposes. The partnership gives Victory Energy Corporation control of the partnership. Article XI of the partnership agreement cannot be modified unless there is a 100% vote of the partners, therefore Victory Energy Corporation cannot be removed as a managing member of the partnership regardless of the partnership interest held by the partners, and thus consolidation is appropriate for all reporting periods. Currently, Victory Energy Corporation conducts all of its oil and natural gas operations through, and holds all of its oil and natural gas assets through, Aurora, which owns record title to all of the oil and natural gas properties, wells and reserves referred to in this Annual Report on Form 10-K. Through its partnership interest in Aurora, Victory Energy Corporation is the beneficial owner of 50% of such oil and gas properties, wells and reserves held of record by Aurora.
 
Operational Overview and Strategy
 
Victory Energy Corporation is an independent, growth oriented oil and natural gas company engaged in the acquisition, exploration and production of oil and natural gas properties. The Company is a partner in Aurora Energy Partners, which is a Texas Partnership that was established in January 2008 by its partners. The other partner in Aurora is the Navitus Energy Group (Navitus), a Texas General Partnership. In an effort to accelerate growth and new capital investment, Aurora’s structure was modified on October 1, 2011 to offer new accredited investors of Navitus, a 10% return for five years, to be paid by Victory, one warrant to purchase one share of Victory common stock for every dollar invested and additional benefits. Under this agreement Navitus has the right to contribute up to $15 million dollars into Aurora, and Victory is obligated to match this plus previous contributions made by Navitus and prior Navitus investments; creating a near $53 million portfolio. By utilizing accumulated proved reserves created from the investment of this capital, Victory Energy Corporation has the ability to meet its capital matching obligations, specifically through a combination of traditional financing sources such as private equity placement, credit facilities, and debt. Under the agreement separation of the partners is not mandatory and Victory may raise funds from other sources. All oil and natural gas assets are owned by Aurora during the 5 year term of the partnership. Victory is the managing partner and shares in Aurora’s profits and losses via its 50% partnership interest.

The Company is geographically focused onshore, with a primary focus in the Permian Basin of Texas and southeast New Mexico. The Company leverages both internal capabilities and strategic industry relationships to acquire working interest positions in low-to-moderate risk oil and natural gas prospects.
 
The Company’s strategy is to continue diversifying its interests by targeting additional prospects that are modeled on our most recent success, the Lightnin’ property. On March 27, 2013, the first well at Lightnin’, Cotter #1 went in production. Current flow rates support a rate of cash-flow that is greater than the company produced in all of calendar year 2012. This single property offers the Company at least seven additional well locations, each offering an estimated 128,000 gross barrels of oil equivalent (BOE), for an estimated total gross yield of 1,024,000 BOE (192,000 net). The Company plans to drill two additional wells on this property in 2013. With the combination of higher working interest, the multi-pay stacked formation opportunities provided, low well costs and the production type curve available, the Lightnin’ property is considered a model for all future acquisitions targeted in the Permian basin of Texas and New Mexico. In 2011, approximately 82,000 active wells were drilled in the Permian Basin, making up 71% of all oil production in Texas and 14% of total U.S. production. Analysts estimated there could be another 40 years of drilling opportunity available in this region.
 
 
5

 

As it executes its strategy, the Company will be targeting investments in larger working interest projects that are weighted toward oil and liquids rich natural gas. This approach of increasing its economic interest should allow it to realize economies of scale, cost efficiencies and, thus improve returns. To further this objective, the Company is managing its cash general and administrative expenses while pursuing additional properties that add revenue at competitive finding and development (F&D) costs per BOE. Lower expenses and additional capital will give the Company flexibility to invest in developing its current asset base. Its increased use of in-house and third party technical and geological capabilities will also help generate additional oil and natural gas prospects with improved working interest positions.

Our primary objectives are two-fold: 1) increase oil and natural gas reserves through the drill bit to expand existing reserve opportunities, 2) grow the business via acquisition of larger oil focused projects with a higher working interest position where possible. To support these objectives, the Company has put in place a highly experienced management and technical team with over 170 years of combined relevant oil and natural gas experience and is continuing to build outside relationships with established operators and geologists.

As of May 20, 2013, the Company had 24 wells on production and 2 wells that have been successfully drilled and are in various stages of completion. The Company’s portfolio of producing assets now includes; the Lightnin’ property, the Bootleg Canyon Ellenberger Field, the Adams-Baggett Gas Field, the Morgan property, the Uno-Mas property and the Clear Water Wolfberry resource play. Proved commercial accumulations of hydrocarbons now occur in multiple horizons, at depths ranging from 4,700 to 13,100 feet with the majority of proved reserves being located on properties in the prolific Permian Basin of Texas and New Mexico. As the Company continues to drill available locations on its current properties and add properties that are accessible to the Company through its established deal flow pipeline, it anticipates an accelerated pace toward oil-weighted production and the addition of new reserves.
 
The Company’s capital and exploration expenditures, including projects at year end, totaled $1,019,901 for 2012. At December 31, 2012, the Company had $158,165 of cash on hand with no outstanding long term debt during 2012. Navitus Energy Group contributed $1.1 million in cash to Aurora. The Company anticipates that Navitus will make additional contributions to Aurora as the portfolios of properties are developed.

During February 2012, the Company raised $1,815,000 of new capital by issuing convertible debt via a private placement offering (PPM) to investors. This new capital followed the successful completion of a 50:1 reverse stock split.

On March 28, 2013, the Company filed a form 12b-25 with the Securities and Exchange Commission (“SEC) disclosing that is was unable to timely file with the SEC its Annual Report on Form 10-K for the year ended December 31, 2012. The Company required additional time to complete the filing due to requirements to restate the consolidated financial statements associated with the proper presentation of the non-controlling interest (“NCI”) in Aurora Energy Partners, which is discussed in further detail in the Note 1 to our audited consolidated financial statements included in this Annual Report on Form 10-K.
 
Distribution Methods
 
Each of our fields that produce oil distributes the oil through one purchaser for each field. 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.
 
Competition
 
We encounter competition from other oil and natural gas companies in all areas of our operations. Because of record high prices for oil, there are many companies competing for the leasehold rights to good oil and natural gas prospects. Additionally, 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.
 
 
6

 
 
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.
 
Marketing Arrangements
 
There is a ready market for the sale of oil and gas. Each of our fields currently sells all of its oil and gas production on the spot market basis.
 
Federal 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 any material adverse effect upon our capital expenditures, net earnings or competitive position. However, the legislative and regulatory burden placed on the industry raises our cost of doing business and therefore could impact profitability. Please refer to Item 1A, Risk Factors.
 
Regulation of Sale and Transportation of Natural Gas
 
Historically, the transportation and sales 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 (the NGPA) and Federal Energy Regulatory Commission (“FERC”) regulations. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act for all “first sales” of natural gas.
 
Thus, all of our sales of natural gas may be made at market prices, subject to applicable contract provisions. Sales of natural gas are affected by availability, terms and cost of pipeline transportation. Since 1985, FERC has implemented regulations intended to make natural gas transportation more accessible to gas buyers and sellers on an open access, non-discriminatory basis. We cannot predict what further action FERC will take on these matters. Some of FERC’s more recent proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers and marketers with which we compete. 
 
The Outer Continental Shelf Lands Act (the “OCSLA”) requires that all pipelines operating on or across the Outer Continental Shelf provides open-access, non-discriminatory service. There are currently no regulations implemented by FERC under its OCSLA authority on gatherers and other entities outside the reach of its NGA jurisdiction. Therefore, we do not believe that any action taken under OCSLA will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers with which we compete.

Our natural gas sales are generally made at the prevailing market price at the time of sale. Therefore, even though we sell significant volumes to major purchasers, we believe that other purchasers would be willing to buy our natural gas at comparable market prices.

Natural gas continues to supply a significant portion of North America’s energy needs and we believe the importance of natural gas in meeting this energy need will continue. The impact of the ongoing economic downturn on natural gas supply and demand fundamentals has resulted in extremely volatile natural gas prices, which is expected to continue.
 
 
7

 

On August 8, 2005, the Energy Policy Act of 2005 (the “2005 EPA”) was signed into law. This comprehensive act contains many provisions that will encourage oil and natural gas exploration and development in the United States. The 2005 EPA directs FERC and other federal agencies to issue regulations that will further the goals set out in the 2005 EPA. The 2005 EPA amends the NGA to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. On January 20, 2006, FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects a significant expansion of FERC’s enforcement authority. We do not anticipate that we will be affected any differently than other producers of natural gas.

In 2007, FERC issued a final rule on annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers are now required to report, on May 1 of each year, beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. The monitoring and reporting required by these rules have increased our general and administrative expenses. We do not anticipate that we will be affected any differently than other producers of natural gas.

Regulation of the Sale and Transportation of Oil

Our sales of crude oil, condensate and NGL are not currently regulated, and are subject only to applicable contract provisions negotiated by us and our counterparties. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes.

The regulation of pipelines that transport oil, condensate and NGL is generally less restrictive than FERC’s regulation of natural gas pipelines under the NGA. Regulated pipelines that transport crude oil, condensate and NGL are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of FERC under the ICA, rates generally must be cost-based, although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, pipeline rates are subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods, minus 1%. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge market based rates if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline.

Federal, State or American Indian Leases. In the event we conduct operations on federal, state or American Indian onshore oil and natural gas leases, such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, certain on-site security regulations and must also obtain permits issued by the Bureau of Land Management (the “BLM”) or other appropriate federal, tribal or state agencies.

The Mineral Leasing Act of 1920 (the “Mineral Act”) prohibits direct or indirect ownership of any interest in federal onshore oil and natural gas leases by a foreign citizen of a country that denies “similar or like privileges” to citizens of the United States. Such restrictions on citizens of a “non-reciprocal” country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and natural gas lease. If this restriction is violated, the corporation’s lease can be cancelled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. We own interests in numerous federal onshore oil and natural gas leases. It is possible that holders of our equity interests may be citizens of foreign countries, which at some time in the future might be determined to be non-reciprocal under the Mineral Act. If any of our equity holders is deemed to be a citizen of a non-reciprocal country, then our interests in federal onshore oil and natural gas leases may be cancelled. Any such cancellation could have a material adverse effect on our financial condition, cash flows and results of operations.
 
 
8

 

State Regulations

Most states regulate the production and sale of oil and natural gas, including:

 
requirements for obtaining drilling permits;
 
the method of developing new fields;
 
the spacing and operation of wells;
 
the prevention of waste of oil and gas resources; and
 
the plugging and abandonment of wells.

The rate of production may be regulated and the maximum daily production allowable from both oil and natural gas wells may be established on a market demand or conservation basis or both.

We may enter into agreements relating to the construction or operation of a pipeline system for the transportation of natural gas. To the extent that such natural gas is produced, transported and consumed wholly within one state, such operations may, in certain instances, be subject to the jurisdiction of such state’s administrative authority charged with the responsibility of regulating intrastate pipelines. In such event, the rates that we could charge for natural gas, the transportation of natural gas, and the construction and operation of such pipeline would be subject to the rules and regulations governing such matters, if any, of such administrative authority.
 
Environmental, Health and Safety Regulation
 
General. Our activities are subject to existing federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, we believe that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, regulations and rules regulating the release of materials in the environment or otherwise relating to the protection of human health, safety and the environment will not have a material effect upon our capital expenditures, earnings or competitive position with respect to our existing assets and operations. We cannot predict what effect additional regulation or legislation, enforcement policies, and claims for damages to property, employees, other persons and the environment resulting from our operations could have on our activities.

Our activities with respect to exploration and production of oil and natural gas, including the drilling of wells, are subject to stringent environmental regulation by state and federal authorities, including the USEPA. Such regulations can increase the cost of our activities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities are inherent in oil and natural gas production operations, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover it is possible that other developments, such as spills or other unanticipated releases, stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and natural gas production, would result in substantial costs and liabilities to us.

Solid and Hazardous Waste. We own or lease numerous properties that have been used for production of oil and natural gas for many years. Although we have utilized operating and disposal practices standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed of or released on, under, or from these properties. In addition, many of these properties have been operated by third parties that controlled the treatment of hydrocarbons and solid wastes and the manner in which such substances may have been disposed or released. State and federal laws applicable to oil and natural gas wastes and properties have gradually become stricter over time. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future contamination.

We generate wastes, including hazardous wastes, which are subject to regulation under the federal Resource Conservation and Recovery Act (the “RCRA”) and state statutes. The USEPA has limited the disposal options for certain hazardous wastes. Furthermore, it is possible that certain wastes generated by our oil and natural gas operations that are currently exempt from regulation as “hazardous wastes” may in the future become regulated as “hazardous wastes” under RCRA or other applicable statutes, and therefore may become subject to more rigorous and costly management and disposal requirements.
 
 
9

 

Naturally Occurring Radioactive Materials (“NORM”) are radioactive materials which precipitate on production equipment or area soils during oil and natural gas extraction or processing. NORM wastes are regulated under the RCRA framework, although such wastes may qualify for the oil and gas hazardous waste exclusion. Primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection; treatment, storage and disposal of NORM waste; management of waste piles, containers and tanks; and limitations upon the release of NORM-contaminated land for unrestricted use. We believe that our operations are in material compliance with all applicable NORM standards.
 
Superfund. The 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 the legality of the original conduct, in connection on certain persons with respect to the release or threatened release of a “hazardous substance” into the environment. Persons potentially liable under CERCLA. These persons include the current or former owner or and operator of the site where the release occurred and anyone who and persons that 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 a site. CERCLA also authorizes the USEPA and, in some cases, 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 to take 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 in response to threats to the public health or the environment and to seek to recover from the responsible persons the costs of such action. Certain state statutes impose similar liability. Neither we nor, to our knowledge, our predecessors have been designated as a potentially responsible party by the USEPA under CERCLA or by any state under a similar state law.
 
 
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Health safety and disclosure regulation. Under CERCLA, the term “hazardous substance” does not include “petroleum, including crude oil or any fraction thereof,” unless specifically listed or designated and the term does not include natural gas, NGL, liquefied natural gas, or synthetic gas usable for fuel. While this “petroleum exclusion” lessens the significance of CERCLA to our operations, we may generate waste that may fall within CERCLA's definition of a “hazardous substance” in the course of our ordinary operations. We also currently own or lease properties that for many years have been used for the exploration and production of oil and natural gas. Although we and, to our knowledge, our predecessors have used operating and disposal practices that were standard in the industry at the time, “hazardous substances” may have been disposed or released on, under or from the properties owned or leased by us or on, under or from other locations where these wastes have been taken for disposal. At this time, we do not believe that we have any liability associated with any Superfund site, and we have not been notified of any claim, liability or damages under CERCLA.

Oil Pollution Act. The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in certain United States waters. A “responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if a spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. If a party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA.

The OPA currently establishes a liability limit for onshore facilities of $350 million and for offshore facilities of all removal costs plus $75 million, and lesser limits for some vessels depending upon their size. The regulations promulgated under OPA impose proof of financial responsibility requirements that can be satisfied through insurance, guarantee, indemnity, surety bond, letter of credit, qualification as a self-insurer, or a combination thereof. The amount of financial responsibility required depends upon a variety of factors including the type of facility or vessel, its size, storage capacity, oil throughput, proximity to sensitive areas, type of oil handled, history of discharges and other factors. We carry insurance coverage to meet these obligations, which we believe is customary for comparable companies in our industry. A failure to comply with OPA's requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions.

Clean Water Act. The Clean Water Act (the “CWA”) regulates the discharge of pollutants into waters of the United States and adjoining shorelines, including wetlands, and requires a permit for the discharge of pollutants, including petroleum and dredged or fill materials, into such waters and wetlands. Certain state regulations and the general permits issued under the federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry operations into certain coastal and offshore waters. Further, the USEPA has adopted regulations requiring certain facilities that store or otherwise handle oil to prepare and implement Spill Prevention, Control and Countermeasure Plans and Facility Response Plans relating to the possible discharge of oil to surface waters. We are required to prepare and comply with such plans and to obtain and comply with discharge permits. The CWA also prohibits spills of oil and hazardous substances to waters of the United States in excess of levels set by regulations and imposes liability in the event of a spill. State laws further provide civil and criminal penalties and liabilities for spills to both surface and groundwater and require permits that set limits on discharges to such waters. We believe we are in substantial compliance with these requirements and that any noncompliance would not have a material adverse effect on us.

Safe Drinking Water Act. The underground injection of oil and natural gas wastes is regulated by the Underground Injection Control (“UIC”) Program, authorized by the federal Safe Drinking Water Act (“SDWA”). The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In Oklahoma, Louisiana, Mississippi and Texas, no underground injection may take place except as authorized by permit or rule. We currently own and operate various underground injection wells. Failure to comply with our permits could subject us to civil and/or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits and authorizations.

Moreover, our exploration and production activities may involve the use of hydraulic fracturing techniques to stimulate wells and maximize natural gas production. Citing concerns over the potential for hydraulic fracturing to impact drinking water, human health and the environment, and in response to a congressional directive, the USEPA has commissioned a study to identify potential risks associated with hydraulic fracturing. The USEPA published a progress report on this study in December 2012 and a final draft report will be delivered in 2014. Additionally, the BLM proposed to regulate the use of hydraulic fracturing on federal and tribal lands, but following extensive public comment on the proposals, announced it would issue an improved proposal before finalizing new rules. The revised proposal is expected to address disclosure of fluids used in the fracturing process, integrity of well construction, and the management and disposal of wastewater that flows back from the drilling process. Some states now regulate utilization of hydraulic fracturing and others are in the process of developing, or are considering development of, such rules. Depending on the results of the USEPA study and other developments related to the impact of hydraulic fracturing, our drilling activities could be subjected to new or enhanced federal, state and/or local regulatory requirements governing hydraulic fracturing.
 
 
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Air Emissions. Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. The USEPA has promulgated new rules to address air emissions from the oil and natural gas industry which, among other things, would require installation of equipment to capture certain gases released from new or refitted hydraulically fractured natural gas wells by January 1, 2015. Other new rules, many effective in 2012, impose stricter standards on emissions associated with gas production, storage and transport. The proposals would revise New Source Performance Standards for volatile organic compounds and sulfur dioxide, impose controls on toxics emitted at oil and natural gas wells and their associated production facilities, and limit fugitive emissions from the production, storage and transport equipment. In addition, states impose requirements to address emissions from certain production and associated facilities. We have complied and will continue to comply with these regulations as applicable to our operations. Due to the uncertainties surrounding proposed regulations, we are unable to predict the financial impact going forward.

Administrative enforcement actions for failure to comply strictly with air regulations or permits may be resolved by payment of monetary fines and/or correction of any identified deficiencies. Alternatively, civil and criminal liability can be imposed for non-compliance. Any such action could require us to forego construction or operation of certain air emission sources. We believe that we are in substantial compliance with air pollution control requirements and that, if a particular permit application were denied, we would have enough permitted or permittable capacity to continue our operations without a material adverse effect on any particular producing field.

Climate Change. According to certain scientific studies, emissions of carbon dioxide, methane, nitrous oxide and other gases commonly known as greenhouse gases (“GHG”) may be contributing to global warming of the earth's atmosphere and to global climate change. In response to the scientific studies, legislative and regulatory initiatives have been underway to limit GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the federal Clean Air Act (“CAA”) definition of an “air pollutant”, and in response the USEPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. The USEPA has also promulgated rules requiring large sources to report their GHG emissions. Sources subject to these reporting requirements include on- and offshore petroleum and natural gas production and onshore natural gas processing and distribution facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year in aggregate emissions from all site sources. We are not subject to GHG reporting requirements. In addition, the USEPA promulgated rules that significantly increase the GHG emission threshold that would identify major stationary sources of GHG subject to CAA permitting programs. As currently written and based on current operations, we are not subject to federal GHG permitting requirements. Regulation of GHG emissions is new and highly controversial, and further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. Further, apart from these developments, recent judicial decisions that have not precluded certain state tort claims alleging property damage to proceed against GHG emissions sources may increase our litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us.

OSHA. 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 standards, the USEPA community right-to-know regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require that we use to organize and/or disclose information about hazardous materials stored, used or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens.

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. 

Employees
 
The Company has 4 full-time employees as of the date of this Annual Report on Form 10-K. We believe that our relationships with our employees are satisfactory. We utilize the services of independent contractors to perform various daily operational duties.
 
Available Information

We make available free of charge through our “Investor Center – SEC Filings” section of our webs-site at www.vyey.com our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) of the Securities Exchange Act of 1934, as amended (“Exchange Act”), and the amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to the SEC.
 
 
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Glossary of Certain Industry Terms

The definitions set forth below shall apply to the indicated terms as used throughout this Annual Report on Form 10-K.

Bbl. One barrel (of oil or natural gas liquids).

BOE. One barrel of oil equivalent. A Boe is determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids, which approximates the relative energy content of oil, condensate and natural gas liquids as compared to natural gas. Despite holding this ratio constant at six Mcf to one Bbl, prices have historically often been higher or substantially higher for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.

Completion. Installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Developed acreage. The number of acres which are allocated or held by producing wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole; dry well. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Equivalent volumes. Equivalent volumes are computed with oil and natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in Regulation S-X.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

HBP. Held by production.

Liquids. Describes oil, condensate, and natural gas liquids.
 
MBbls. Thousands of barrels of oil or natural gas liquids.

MBoe. Million barrels of oil equivalent.

Mcf. Thousand cubic feet (of natural gas).

Mcfe. Thousand cubic feet equivalent.

MBbls. Millions of barrels of oil or natural gas liquids.

MMcf. Million cubic feet.

MMcfe. Million cubic feet equivalent.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers.

NGL. Natural gas liquids.
 
 
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NYMEX. New York Mercantile Exchange.

Present value or PV10% or “SEC PV10%.” When used with respect to oil and gas reserves, present value or PV10% or SEC PV10% means the estimated future gross revenue to be generated from the production of net proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service, accretion, and future income tax expense or to depreciation, depletion, and amortization, discounted using monthly end-of-period discounting at a nominal discount rate of 10% per annum.

Productive wells. Producing wells and wells that are capable of production in sufficient quantities to justify completion, including injection wells, salt water disposal wells, service wells, and wells that are shut-in.

Proved developed reserves. Estimated proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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

Proved undeveloped reserves. Estimated proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.

Undeveloped acreage. Acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains estimated proved reserves.

Working Interest or WI. An operating interest which gives the owner the right to drill, produce, and conduct operating activities on the property and a share of production.

Item1A. Risk Factors
 
Our business is subject to a number of risks including, but not limited to, those described below:
 
We continue to incur operating losses through 2012.

While the Company has taken steps to reduce general and administrative costs and add further oil and natural gas reserves through additional investment, there is no guarantee the Company will become profitable, or have continued and sustained profitability over the longer term. Our profitability is affected by, among other factors, our ability to have continued access to high-potential reserves, our success in drilling operations, the economic life of any reserves developed, and the market price of crude oil or natural gas. Future losses may adversely our affect our business, financial condition and cash flows.

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 are sometimes 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.
 
 
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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 SEC defines and applies “penny stock” regulations to any equity security that has a market price of less $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 (excluding the value of primary residence and mortgage debt on primary residence) 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.
 
FINRA 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 Financial Industry Regulatory Authority (“FINRA”) 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 FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. The FINRA 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 and with low trading volumes, 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 and low trading volumes. 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 are considered highly speculative, generally because of the nature of our business and the early stage we are in of building a long life asset base. While operating revenues are planned to increase over time, through our capital and exploration program, there are risks associated with drilling success, oil and natural gas prices, and our ability to raise additional monies through share offerings or debt. Access to capital is vital and unless the revenue base grows over time that could prove difficult to accomplish.
 
Potential legislative and regulatory actions addressing climate change could increase our costs, reduce our revenue and cash flow from oil and gas sales or otherwise alter the way we conduct our business.

Future changes in the laws and regulations to which we are subject may make it more difficult or expensive to conduct our operations and may have other adverse effects on us. For example, the USEPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allows the USEPA to begin regulating emissions of GHGs under existing provisions of the CAA. The USEPA has begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress has considered and may in the future consider “cap and trade” legislation that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for our production.
 
 
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Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
 
Congress has considered legislation to amend the SDWA to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process and other legislation regulating hydraulic fracturing has been considered, and in some cases adopted, at various levels of government. Hydraulic fracturing is an important and commonly used process in the completion of unconventional gas wells in shale formations as well as tight conventional formations. This process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate gas production. Sponsors of these bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and/or that hydraulic fracturing could pose a variety of other risks. Any additional level of regulation could lead to operational delays, or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing, and increase our costs of compliance and doing business.
 
Gas drilling and production operations require adequate sources of water to facilitate the fracturing process and the disposal of that water when it flows back to the wellbore. If we are unable to obtain adequate water supplies and dispose of the water we use or remove at a reasonable cost and within applicable environmental rules, our ability to produce gas commercially and in commercial quantities would be impaired.

New environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial performance. Water that is used to fracture gas wells must be removed when it flows back to the wellbore. Our ability to remove and dispose of water will affect our production and the cost of water treatment and disposal may affect our profitability. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing or disposal of waste, including produced water, drilling fluids and other wastes associated with the exploration, development and production of gas.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.

The U.S. President’s Fiscal Year 2013 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws applicable to oil and gas exploration and production companies. These changes include, but are not limited to:
 
 
the repeal of the limited percentage depletion allowance for oil and natural gas production in the United States;
 
the elimination of current deductions for intangible drilling and development costs;
 
the elimination of the deduction for certain domestic production activities; and
 
an extension of the amortization period for certain geological and geophysical expenditures.

Members of the U.S. Congress have considered similar changes to the existing federal income tax laws that affect oil and natural gas exploration and production companies. It is unclear whether these or similar changes will be enacted. The passage of this legislation or any similar changes in federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to U.S. oil and gas exploration and development. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) provides for new statutory and regulatory requirements for derivative transactions, including oil and natural gas hedging transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be cleared on exchanges for which cash collateral will be required. In October 2011, the CFTC approved final rules that establish position limits for futures contracts on 28 physical commodities, including four energy commodities, and swaps, futures and options that are economically equivalent to those contracts. The rules provide an exemption for “bona fide hedging” transactions or positions, but this exemption is narrower than the exemption under existing CFTC position limit rules. These newly approved CFTC position limits rules were vacated by the United States District Court for the District of Columbia in September 2012, although the CFTC has stated that it will appeal the District Court’s decision.
 
 
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It is not possible at this time to predict with certainty the full effect of the Dodd-Frank Act and CFTC rules on us and the timing of such effects. The Dodd-Frank Act may require us to comply with margin requirements and with certain clearing and trade-execution requirements if we do not satisfy certain specific exceptions. The Dodd-Frank Act may also require the counterparties to our derivatives contracts to transfer or assign some of their derivatives contracts to a separate entity, which may not be as creditworthy as the current counterparty. Depending on the rules adopted by the CFTC or similar rules that may be adopted by other regulatory bodies, we might in the future be required to provide cash collateral for our commodities hedging transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures. A requirement to post cash collateral could therefore reduce our ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

Oil and gas prices are volatile. Declines in commodity prices have adversely affected, and in the future may adversely affect, our financial condition and results of operations, cash flows, access to the capital markets and ability to grow.
 
Our revenue reserves, cash flows, profitability and future rate of growth substantially depend upon the market prices of oil and natural gas. Our ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, is substantially dependent on prevailing prices of oil and natural gas. Historically, the markets for oil and gas have been volatile, and those markets are likely to continue to be volatile in the future. It is impossible to predict future oil and gasoil and gas price movements with certainty. The prices we receive for our oil and natural gas depend upon factors beyond our control, including, among others:
 
 
changes in the supply of and demand for oil and natural gas;
 
market uncertainty;
 
level of consumer product demands;
 
weather conditions;
 
domestic governmental regulations and taxes;
 
price and availability of alternative fuels;
 
political and economic conditions in oil producing countries;
 
actions by the Organization of Petroleum Exporting Countries;
 
price of oil and natural gas imports; and
 
overall domestic and foreign economic conditions.
 
These factors make it very difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not long-term fixed price contracts. Further, oil prices and gas prices do not necessarily fluctuate in direct relation to each other.

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 gas prices; and
 
oil and gas property title problems.
 
 
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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.
 
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.
 
We depend on successful exploration, development and acquisitions to maintain revenue in the future.
 
In general, the volume of production from oil and gas 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 oil and gas 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 oil and gas 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.
 
We are not the operator of our oil and gas properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.
 
 
the timing and amount of capital expenditures;
 
the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
 
the operator’s expertise and financial resources;
 
approval of other participants in drilling wells;
 
selection of technology; and
 
the rate of production of the reserves.
 
In addition, when we are not the majority owner or operator of a particular oil or gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.

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 oil and gas 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.
 
 
18

 
 
We cannot assure you that:
 
 
we will be able to identify desirable oil and gas 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 oil and gas prospects will include prospects that contain proved oil and gas 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 oil and gas 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.
 
We face strong competition from other oil and gas companies.
 
We encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of exploratory prospects and proved properties. Our competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies that have been engaged in the oil and gas 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 oil and gas 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.
 
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 depend on key management personnel and technical experts. The loss of key employees or access to third party technical expertise could impact our ability to execute our business.
 
If we lose the services of the senior management, or access to independent land men, geologists and reservoir engineers with whom the Company has strategic relationships, our ability to function and grow could suffer, in turn, negatively affecting our business, financial condition and results of operations.

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 gas production depends in part upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities. We generally deliver 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.
 
 
19

 
 
If oil and gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties, 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. In the future should our properties serve as collateral for credit facilities, 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 natural 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 natural 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 natural 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 oil and gas wells below actual production capacity in order to conserve supplies of oil and gas.
 
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.
 
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.
 
 
20

 
 
We may issue additional shares of capital stock that could affect the value of existing holders of the Company’s stock, stock options, or warrants.
 
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 options and warrants into shares of common stock could be adversely affected.
 
Our results of operations could be adversely affected as a result of impairments of oil and natural gas properties.
 
While we provide that our assets will be depleted over the estimated productive reserves of the oil and natural 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 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. Litigation continues and the outcome is uncertain. The risk is that our investment in two Adams-Baggett gas wells could be lost.
 
We are also prosecuting a lawsuit against our former drilling contractor, former operator, and other related parties. In that case, an interlocutory Default Judgment against the defendants was awarded to Victory and James Capital, which is a general partner of Navitus. The judgment amounted to $17,183,987. No monies have yet been received related to this favorable judgment.

Item 1B. Unresolved Staff Comments

We are a “smaller reporting company” as defined by Rule 12b-2 under the Securities Exchange Act, and as such, are not required to provide the information required under this item.
 
 
21

 
 
Item 2. Properties
 
Office Space Leases.
 
Our executive office space lease is set to expire on June 30, 2014 and is for approximately 1,200 square feet at 3355 Bee Caves Road, Suite 608, Austin, TX 78746. The monthly lease cost is $2,250.
 
Portfolio.

As of May 24, 2013, the Company, through Aurora had 24 wells in production and 2 wells that have been successfully drilled and were in various stages of completion. The Company’s producing portfolio of producing assets now includes; the Lightnin’ property, the Bootleg Canyon Ellenberger Field, the Adams-Baggett Gas Field, the Morgan property, the Uno-Mas property and the Clear Water Wolfberry resource play. Proved commercial accumulations of hydrocarbons now occur in multiple horizons, at depths ranging from 4,700 to 13,100 feet with the majority of proved reserves being located on properties in the prolific Permian Basin of Texas and New Mexico. As the Company continues to drill available locations on its current properties and add properties that are accessible to the Company through its established deal flow pipeline, it anticipates an accelerated pace toward oil-weighted production and the addition of new reserves.

On March 27, 2013, the first well at Lightnin’, Cotter #1 went in production. Current flow rates support a rate of cash-flow that is greater than the Company produced in all of calendar year 2012. On this single property, the Company has the opportunity to drill at least seven additional well locations, each offering an estimated 128,000 gross barrels of oil equivalent (BOE), for an estimated total gross yield of 1,024,000 BOE (192,000 net). The Company plans to drill two additional wells on this property in 2013.

With the combination of higher working interest, the multi-pay stacked formation opportunities provided, low well costs and the production type curve available, the Lightnin property is considered a model for all future acquisitions targeted in the prolific Permian Basin of Texas and New Mexico.
 
The Lightnin’ Property, Glascock County, Texas

In March 2012, the Company, through its ownership in Aurora acquired a 75% working interest and a 56.25% net revenue interest in 320 gross acres known as the Lightnin’ Property. This property is located in the very active Permian Basin resource play known as the Wolfberry. In January 2013, the Company farmed out 50% of its working interest and selected an operator for the prospect. The Company now holds a 25% working interest and an 18.75% net revenue interest in the project. The first well, the Cotter #1, was spud in January 2013, completed in February and brought into production in late March. The Lightnin’ property holds at least seven additional well locations, each offering an estimated 128,000 gross barrels of oil equivalent (BOE), for an estimated total gross yield of 1,024,000 BOE (192,000 net). The Company plans to drill two additional wells on this property in 2013. There were no proved reserves associated with this property in the Company’s reserve report for the period ended December 31, 2012.

The Bootleg Canyon Property, Pecos County, Texas

The Company, through its ownership in Aurora owns a 5% working interest and a 3.75% net revenue interest in 5,000 gross acres known as the Bootleg Canyon property. The first well on this property was drilled in June of 2011. At the end of 2012 there were two producing oil wells on the property. A third well was successfully completed as a gas well in early 2013. There are two proved producing wells and one proved undeveloped well location in the Company’s reserve report for the period ended December 31, 2012. Additional well locations are being evaluated for drilling in 2013.

The Adams-Baggett Property, Crocket County, Texas

The Company, through its ownership in Aurora, holds a working interest in nine wells on the Adams-Baggett Property; 100% working interest and a 75% net revenue interest in seven wells and a 50% working interest with 38% net revenue interest in two wells. The Company received its first production revenue from this field in March of 2008 and continues to receive income today. Due to its higher BTU content per cubic foot, natural gas from the Canyon Sandstone generally receives a 25% or more price premium above the standard market price for natural gas.
 
 
22

 

The Morgan Property, Martin County, Texas

In November 2012, the Company, through its ownership in Aurora Energy Partners acquired a 3% working interest and a 2.25% net revenue interest in 80 gross acres known as the Morgan Property. This property is located in the Permian Basin Wolfberry Play. The first well, Morgan #1 was spud in December 2012 and reached total depth (10,616 feet) in January 2013. The Morgan #1 was fracture stimulated and completed in March 2013. The well is currently producing both oil and natural gas while the well continues to unload frac fluids. There are two proved undeveloped well locations included in the Company’s reserve report for the period ended December 31, 2012.
 
The Uno-Mas Property, Lea County, New Mexico

In September 2011, the Company, through its ownership in Aurora, acquired a 10% working interest and a 7.5% net revenue interest in 320 gross acres known as the Uno-Mas Property. In December 2011, the Company successfully completed the Uno-Mas #1 re-entry well in the Mississippian formation. The well is currently producing oil and natural gas to sales. In 2012 the Company entered into a farm out agreement with an operator covering the shallower formations on the Uno-Mas Property. In exchange for the farm out rights, the operator has agreed to drill four wells. The Company will be carried through the tanks on the first two wells and then will be given the opportunity to participate on a heads-up basis on the next two wells bearing its working interest share of the well costs. Two of these wells (Hickory 14 State #1 and Milan 12 State #1) have been successfully drilled and are in various stages of completion.
 
Under the farm out agreement the Company owns a 1.25% carried working interest and a .9375% net revenue interest in the first two wells which reverts to a 2.5% working interest 1.875% net revenue interest once the wells payout. If the shallower formations in the Hickory and Milan prove to be successful, additional potential pay may be available in the Uno-Mas #1 re-entry well-bore.

Clearwater Wolfberry Resource Play, Howard County, Texas

In April 2011, the Company, through its ownership in Aurora acquired a 1.5% working interest and a 1.125% net revenue interest in 3,186 gross acres known as the Clearwater Property. At the time of acquisition this property held two producing wells and a third exploration well was in progress. At year-end 2011, there were three producing oil wells on this property. During February 1, 2012 the Company assigned approximately 944 gross acres of mineral rights related to the Hamlin 26 and Hamlin 24 tracts to another operator in exchange for an overriding royalty interest proportional to the working interest held by the Company. In exchange for the assignment, the Company retained a 0.375% overriding royalty interest in the 944 gross acres. The Company still owns a 1.5% working interest and a 1.125% net revenue interest in the remaining 2,242 acres.

The Chapman Ranch Property, Nueces County, Texas

In April 2012, the Company, through its ownership in Aurora acquired a 5% working interest and a 3.75% net revenue interest in 320 gross acres known as the Chapman Ranch Property. The first well was drilled and completed in July of 2012. Multiple pay zones were present in the well-logs; however oil and natural gas production from the target formation was not of a commercial quantity. The operator has determined that a different geological zone may be productive and the working interest partners have elected to participate in the completion of this zone. Recompletion is anticipated in the second quarter of 2013.

The Pinetop Property, Lea County, New Mexico

In April 2012, the Company, through its ownership in Aurora, acquired a before payout (BPO) working interest of 4% with a 2.94% net revenue interest and an after payout (APO) working interest of 3% with a 2.205% net revenue interest in this 1,201 gross acre property. The first of nine (9) development wells was spud in June 2012 and was successfully completed by the operator. The well had initial flow rates of over 400 barrels of oil per day and unmetered flow of 300 Mcf of natural gas per day. Once on production, the well naturally flowed over 3,000 barrels of oil and 2,125 Mcf of natural gas during the first ten days of operation. After a few weeks, production dramatically decreased to less than 10 BO per day. The well was later put on rod-pump; however production of commercial volumes did not occur. The operator has evaluated the previously producing formation (Lower Cisco) and believes that fracture porosity was not significant enough to produce additional oil beyond the 3,000 barrel pocket that generated the initial production. Two additional formations (Upper Cisco and Wolfcamp) are now being targeted for re-completion. The test of these recompletions is anticipated to occur in June 2013. If the Upper Cisco and Wolfcamp formations prove to be productive, eight additional 3D seismic supported drilling locations remain.
 
 
23

 
 
Developed and Undeveloped Lease Acreage
 
The following table sets forth certain information regarding developed and undeveloped leasehold acreage held by Aurora as of December 31, 2012. “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.
 
         
Developed Acreage
   
Undeveloped Acreage
   
Total Acreage
 
   
WI %
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Adams-Baggett Ranch
                                         
Adams-Baggett Ranch
    100 %     140.0       140.0       -       -       140.0       140.0  
Adams-Baggett Ranch
    50 %     40.0       20.0       -       -       40.0       20.0  
                                                         
The Bootleg Canyon Property
                                                       
Bootleg Prospect
    5.00 %     320.0       16.0       5,127.4       256.4       5,447.4       272.4  
                                                         
Saddle Butte Prospect
    3.00 %     -       -       2,560.0       76.8       2,560.0       76.8  
                                                         
The Lightnin' Property
    25.00 %     -       -       320.0       80.0       320.0       80.0  
                                                         
The Uno-Mas Property
    10 %     160.0       16.0       160.0       2.0       320.0       18.0  
                                                         
The Morgan Property
    3.00 %     -       -       86.0       2.6       86.0       2.6  
                                                         
The Chapman Ranch Property
    5.00 %     80.0       4.0       240.0       12.0       320.0       16.0  
                                                         
The Pinetop Property
    4.00 %     80.0       3.2       1,120.0       44.8       1,200.0       48.0  
                                                         
Clearwater Wolfberry Resource Play
    1.50 %     320.0       4.8       1,922.0       28.8       2,242.0       33.6  
*Royalty Interest Acreage
    -       -       -       944.0       3.5       944.0       3.5  
Total Acreage
            1,140.0       204.0       12,479.4       506.9       13,619.4       710.9  
 
Internal Controls Over Reserve Estimates, Technical Qualifications and Technologies Used

The Company’s policies regarding internal controls over reserve estimates requires reserves to be in compliance with the SEC definitions and guidance, and for reserves to be prepared by an independent third party reserve engineering firm and reviewed by certain members of senior management.
 
Estimates of our reserves were prepared by an independent reserve engineer, Mr. James Nicolson 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, and a former chairman of the Permian Basin Oil & Gas Recovery Conference. Our independent consultants, including a geologist and an oil & gas operations professional have reviewed and approved the reserve report which is filed as an exhibit to this Annual Report on Form 10-K.
 
 
24

 
 
At December 31, 2012, our proved developed reserves were 18% oil and 82% gas and liquids, respectively. The following table sets forth our estimated proved oil and natural gas reserves for the 21 wells and the PW value of such reserves as of December 31, 2012 and 2011.
 
Total Estimated Proved Reserves
 
2012
   
2011
 
Oil (MBbl)
    24.3       8.0  
Gas (Mcf)
    679.4       691.1  
% Oil
    18 %     6 %
% Proved Developed
    92 %     100 %
PV - 10% (in thousands)
  $ 1,745.3     $ 1,357.4  
 
Reconciliation of PV-10 to Standardized Measure
 
PV-10 is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the Standardized Measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure 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. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure of discounted future net cash flows. Our PV-10 measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.
 
The following table provides a reconciliation of PV-10 to the Standardized Measure of discounted future net cash flows at December 31, 2012 and 2011:
 
   
December 31,
 
 
 
2012
 
 
2011
 
 
 
(In Thousands)
 
PV-10
 
$
 1,745.3
 
 
$
1,357.4
 
Present value of future income taxes discounted at 10%
 
 
601.1
 
 
 
461.5
 
 
 
     
 
     
Standardized Measure of discounted future net cash flows
 
$
1,144.2
 
 
$
895.9
 
 
Estimated future net revenues
 
The following table sets forth the estimated future net revenues, excluding derivative contracts, from proved reserves, the present value of those net revenues (PV-10) and the standardized measure values at December 31, 2012 and 2011:
 
   
December 31,
 
   
2012
   
2011
 
    (In Thousands)  
Future net revenues
  $ 3,342.6     $ 2,742.1  
Present value of net revenues:
               
Before income tax (PV-10)
    1,745.3       1,357.4  
After income tax (Standardized Measure)
   
1,144.2
      898.9  
 
 
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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, 2012 and 2011.
 
   
December 31,
 
   
2012
   
2011
 
   
Gross
   
Net
   
Gross
   
Net
 
Natural Gas
   
10.0
     
8.1
     
9.0
     
8.0
 
Oil
   
11.0
     
0.4
     
8.0
     
0.3
 
Totals
   
21.0
     
8.5
     
17.0
     
8.3
 
 
Technologies Used in Establishing Proved Reserves in 2012 and 2011
 
Our proved reserves in 2012 and 2011 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. Surface geological information was also utilized in the preparation of the data where applicable. 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, 2012 and 2011, our proved undeveloped reserves were 3 prospects (the University 7 #1, the Morgan #1, and the Morgan #2) and none, respectively.
 
Oil and natural gas Production, Production Prices and Production Costs

The following table sets forth certain information regarding our production volume, and average sales and production costs for the periods indicated.
 
   
Years Ended December 31,
 
   
2012
   
2011
 
Production:
           
Oil (Bbls)
    1,659       572  
Natural gas (Mcf)
    61,582       44,682  
BOE
    11,923       8,019  
Average sales prices:
               
Oil (per Bbl)
  $ 83.98     $ 88.10  
Natural gas (per Mcf)
  $ 4.55     $ 6.59  
BOE
  $ 27.37     $ 38.06  
Average production costs
               
Lease operating expense
  $ 126,131     $ 121,580  
Production tax
  $ 24,649     $ 39,156  
BOE
  $ 12.65     $ 20.04  
 
 
26

 
 
Drilling and Other Exploratory and Development Activities
 
The following table sets forth our drilling activity for the periods indicated.
 
   
Years Ended December 31,
 
   
2012
   
2011
 
   
Gross
   
Net
   
Gross
   
Net
 
Exploratory Wells
                       
Productive
    3.0       0.1       4.0       0.2  
Dry
    3.0       0.1       5.0       0.1  
Developmental Wells
                               
Productive
    2.0       0.1       -       -  
Dry
    -       -       -       -  
 
During the period beginning January 1, 2013 and ending April 30, 2013, we participated in the drilling of 4 gross (.34 net) wells, all of which were completed.

Title to Properties

We believe that we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and natural gas industry. Our properties are subject to customary royalty interests, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect the value of such properties. Prior to acquiring undeveloped properties, we perform a title investigation that is thorough but less vigorous than that conducted prior to drilling, which is consistent with standard practice in the oil and natural gas industry. Before we commence drilling operations, we conduct a thorough title examination and perform curative work with respect to significant defects before proceeding with operations. We have performed a thorough title examination with respect to substantially all of our active properties.
 
 
27

 
 
Item 3. LEGAL PROCEEDINGS
 
Cause No. 08-04-07047-CV; Oz Gas Corporation v. Remuda Operating Company, et al. v. Victory Energy Corporation.; In the 112th District Court of Crockett County, Texas.
 
Plaintiff Oz Gas Corporation sued Victory Energy Corporation and other parties for bad faith trespass, among other claims, regarding the drilling of two wells on lands that Oz (“OZ”) claims title to Victory Energy Corporation has a 50% interest in one of the named wells involved in this lawsuit (that being well 155-2 on the Adams Baggett Ranch in Crockett County, Texas). The lawsuit was originally filed against other parties in April 2008, and Victory intervened in the case on November 18, 2009 to protect its interest in the 155-2 well.
 
The case was tried in February 2012. The Court found in favor of Oz and rendered verdict against Victory and the other defendants for the sum of $137,000. Victory Energy Corporation has appealed this decision to the 8th Court of Appeals in El Paso, Texas, and the case has been fully briefed and submitted.
 
Cause No. CV-47,230; James Capital Energy, LLC and Victory Energy Corporation v. Jim Dial, et al.; In the 142nd District Court of Midland County, Texas.
 
This lawsuit was filed in the 142nd District Court of Midland County, Texas on January 19, 2010 by James Capital Energy, LLC and Victory Energy Corporation against numerous parties for fraud, fraudulent inducement, and negligent misrepresentation, breach of contract, breach of fiduciary duty, trespass, conversion and a few other related causes of action. This lawsuit stems from an investment made by Victory for the purchase of six wells on the Adams Baggett Ranch.
 
On December 9, 2010, Victory was granted an interlocutory Default Judgment against Defendants Jim Dial, 1st Texas Natural Gas Company, Inc., Universal Energy Resources, Inc., Grifco International, Inc., and Precision Drilling & Exploration, Inc. The total judgment amounted to approximately $17.2 million. Recently Victory has added additional parties to this lawsuit. Discovery is ongoing in this case and no trial date has been set at this time.
 
Victory believes that it will be victorious against all the remaining Defendants in this case.
 
On October 20, 2011 Defendant Remuda filed a Motion to Consolidate and a Counterclaim against Victory. Remuda is seeking to consolidate this case with two other cases in which Remuda is the named Defendant. An objection to this motion was filed and the cases have not been consolidated. Additionally, we do not believe that the counterclaim made by Remuda has any legal merit.

Cause No. 10-09-07213; Perry Howell, et al. v. Charles Gary Garlitz, et al.; In the 112th District Court of Crockett County, Texas.
 
The above referenced lawsuit was filed in the 112th District Court of Crockett County, Texas on September 6, 2010. This lawsuit alleges that Cambrian Management, Ltd. and Victory Energy Corporation trespassed on lands owned by the Plaintiffs in the drilling of the Adams-Baggett 115-8 well in Crockett County, Texas.

Discovery is ongoing in this case and the case is set for trial in July 2014. Victory Energy Corporation believes that the claims have no merit and that it will prevail.

Cause No. D-1-GN-13-00044; Aurora Energy Partners and Victory Energy Corporation v. Crooked Oaks; In the 261st District Court of Travis County, Texas.

The Company has yet to collect an installment balance of $200,000 for the sale of its Jones County, Texas oil and gas interests in May of 2012. The Company believes it will ultimately recover this receivable, but has provided for it as an allowance for doubtful accounts, and has not included it in the net accounts receivable balance of the Company’s 2012 consolidated financial statements.
 
Item 4. MINE SAFETY DISCLOSURE

Not applicable.
 
 
28

 
 
PART II
 
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
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, 2012 and 2011. The information reflects prices between dealers, and does not include retail markup, markdown, or commission, and may not represent actual transactions.
 
Fiscal Year Ended
 
 
 
Bid Prices
 
December 31,
 
Period
 
High
 
 
Low
 
 
 
 
 
 
 
 
 
 
2012
 
First Quarter
 
$
2.35
 
 
$
1.07
 
 
 
Second Quarter
 
$
1.10
 
 
$
0.55
 
 
 
Third Quarter
 
$
1.04
 
 
$
0.21
 
 
 
Fourth Quarter
 
$
0.50
 
 
$
0.15
 
 
 
 
 
 
 
 
 
 
 
 
2011 (1)
 
First Quarter
 
$
1.10
 
 
$
0.48
 
 
 
Second Quarter
 
$
2.00
 
 
$
0.85
 
 
 
Third Quarter
 
$
2.90
 
 
$
1.25
 
 
 
Fourth Quarter
 
$
1.75
 
 
$
0.95
 
 
(1)
Reflects 50:1 reverse stock split that occurred January 12, 2012.

Holders
 
As of August 20, 2013, the high and low bid prices for our common stock on the OTC Market was $0.20 and $0.20, respectively. As of August 20, 2013, there were approximately 1432 holders of record of our common stock.
 
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
 
The following securities were issued through December 31, 2012:

Period
 
Investment
   
Warrants
 
August
  $ 249,900       249,900  
September
  $ 100,000       100,000  
October
  $ 200,000       200,000  
November
  $ 240,000       240,000  
December
  $ 300,000       300,000  
Totals
  $ 1,089,900       1,089,900  
 
 
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The following securities were issued through December 31, 2012 include the following:
 
Purpose
 
Granted
   
Outstanding
 
Board Services
    120,000       120,000  
Services
    788,191       785,041  
Employee Options
    130,000       40,000  
Private Placement
    36,500       33,000  
Totals
    1,074,691       978,041  

We did not purchase any of our own common stock during the year ended December 31, 2012.

Item 6. SELECTED FINANCIAL DATA

We are a “smaller reporting company” as defined by Rule 12b-2 under the Securities Exchange Act, and as such, are not required to provide the information required under this Item.
 
 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.
 
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
 
The Company is an independent, growth oriented oil and natural gas company engaged in the acquisition, exploration, development and production of oil and natural gas properties, through its partnership with Navitus in Aurora. The Company’s objective is to create long-term shareholder value by increasing oil and natural gas reserves, improving financial returns (higher production volumes and lower costs), and managing the capital on its balance sheets.

We are geographically focused onshore, with a primary focus in the Permian Basin of Texas and southeast New Mexico. The Company leverages both internal capabilities and strategic industry relationships to acquire working interest positions in low-to-moderate risk oil and natural gas prospects. Our focus is on oil or liquid-rich gas projects with longer-life reserves that offer competitive finding and development (F&D) costs.

At the end of 2012, the Company held a working interest in 21 wells located in Texas and New Mexico, predominantly in the Permian Basin of West Texas.
 
 
30

 

Our primary company business objective is to grow proved reserves through new drilling and grow the value of those reserves by focusing on oil. For 2012, we achieved both a shift toward oil and increase in proved reserves through successful drilling. We also added properties large enough to offer new multi-well drilling opportunities in the future. These efforts created a year to year increase of 12% in proved reserves for 2012.
 
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 oil and natural gas. Historically, the markets for oil and natural gas have been volatile, and those markets are likely to continue to be volatile in the future. It is impossible to predict with certainty future prices for oil and natural gas, as such prices are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of additional factors beyond our control.

Going Concern
 
As presented in the consolidated financial statements, the Company has incurred a net loss of $6.7 million during the twelve months ended December 31, 2012, and losses are expected to continue in the near term. The accumulated deficit at December 31, 2012 was $35.2 million. The Company has been funding its operations through the sale of senior convertible 10% Senior Secured Convertible Debentures and from contributions made by its partners. 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 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 will match available operating cash flows.
 
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.
 
Results of Operations

Comparison of Year Ended December 31, 2012 to Year Ended December 31, 2011
 
Revenues: All of our revenue was derived from the sale of oil and natural gas. Revenues consist of the proceeds of sales, net of royalty, and gas transportation deductions. Our net revenue increased $21,204 or 7% to $326,384 for the twelve months ended December 31, 2012 from $305,180 for the twelve months ended December 31, 2011. The increase reflects primarily the increase in oil production revenues which increased $82,428 to $139,320 for the 12 months ended December 31, 2012, from $56,892 for the twelve months ended December 31, 2011.
 
Lease Operating Expenses: Lease operating expenses which includes the operating expenses of obtaining the oil and natural gas increased $4,551 or 4% to $126,131 for the twelve months ended December 31, 2012 from $121,580 for the twelve months ended December 31, 2011. The increase in lease operating expenses reflects an increase in the number of operating properties for the year ended December 31, 2012. 

Dry Hole Costs: Dry Hole costs increased $54,678 or 100% for the twelve months ended December 31, 2012 from $0 for the twelve months ended December 31, 2011. The Company incurred dry holes costs in connection with the drilling of the Saddle Butte Prospect in Pecos County, Texas in 2012.

Production Taxes: Production taxes are charged at the well head for the production of gas and oil. Production taxes decreased $14,507 or 37% to $24,649 for the twelve months ended December 31, 2012 from $39,156 for the twelve months ended December 31, 2011. Although our revenues increased for 2012, our productions taxes were down because a larger percentage of our 2012 revenue came from oil sales which carry a lower tax of 4.6% versus 7.5% for natural gas.

Gain on Settlement with Former Officer: Gain on settlement with former officer decreased 100% for the twelve months ended December 31, 2012 from $404,624 for the twelve months ended December 31, 2011.
 
Exploration Expense: Exploration expenses decreased $293,009 or 52% to $266,514 for the twelve months ended December 31, 2012 from $559,523 for the twelve months ending December 31, 2011. The change is not considered meaningful and simply reflects the timing of expenses for exploration activities.
 
 
31

 

General and Administrative Expense: General and administrative expenses increased $729,171 or 35% to $2.8 million for the year ended December 31, 2012 from $2.1 million for the year ending December 31, 2011. The Cash G&A burn rate was higher for 2012 primarily due to additional headcount in Austin and non-recurring costs associated with the transfer of accounting services from California to Texas.
 
Depletion, Depreciation, and Accretion: Depletion and accretion expenses decreased $31,501 or 38% to $51,172 for the twelve months ended December 31, 2012 from $82,673 for the twelve months ended December 31, 2011. The decrease was due to the reduction in the amount of assets subject to depletion as a result of the sale of the Jones County/Atwood properties in May, 2012 and property impairments.
 
Impairment of Oil and Natural Gas Properties: Impairment of oil and natural gas properties increased $241,774 or 236% to $344,353 from $102,579 for the twelve months ended December 31, 2012. This is primarily due to our Uno Mas well which was deemed not commercial and a charge associated with the write-off of other undeveloped land costs in New Mexico.
 
Gain on Sale of Oil and Natural Gas Properties: Gain on sale of oil and natural gas properties increased $275,489 or 100% for the twelve months ended December 31, 2012. This is due to the sale of our Jones County property.

Interest Expense: Interest expense increased $2,194,941 or 121% to $4,009,979 for the twelve months ended December 31, 2012 from $1,815,038 for the twelve months ended December 31, 2011. Virtually all of the interest expense was associated with the Company’s 10% Senior Secured Convertible Debentures which were converted to common stock on February 29, 2012.
 
Income Taxes: There is no provision for income tax expenses recorded for either the twelve months ended December 31, 2012 or ended December 31, 2011 due to the expected net operating losses (NOL) of both years. The previously reported twelve months ended December 31, 2011 was restated to eliminate a tax benefit provision which was determined to not be realizable when applying ASC 740, based upon net realizable value evaluation. We had available Federal income tax net operating loss (“NOL”) carry forwards of 13,807,335 at December 31, 2012. Our NOL generally begins to expire in 2027.

The realization of future tax benefits is dependent on our ability to generate taxable income within the carry forward period. 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 thus be established when it is more likely than not that all or a portion of deferred tax assets will not be realized.

All tax benefits recognized in 2011 and 2012 due to the temporary difference in tax effect between the accounting and tax basis of the 10% Senior Secured Convertible Debentures were eliminated when the Debenture were converted to common stock on February 29, 2012.

Net Loss: Net losses increased 82% or $3,033,676 to $6,739,678 for the twelve months ended December 31, 2012 from a net loss of $3,706,002 for the twelve months ended December 31, 2011. This net loss should be viewed in light of the cash flow from operations discussed below.
 
During the year ended December 31, 2012, as with the year ended December 31, 2011, 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
 
Our cash and cash equivalents, total current assets, total assets, total current liabilities, and total liabilities as of December 31, 2012 as compared to December 31, 2011, are as follows:

 
 
Dec. 31,
2012
   
Dec. 31,
2011
 
Cash
  $ 158,165     $ 475,623  
Total current assets
    384,339       584,363  
Total assets
    1,859,981       1,626,795  
Total current liabilities
    273,209       689,383  
Total liabilities
    313,114       1,351,921  
 
 
32

 

At December 31, 2012, we had a working capital surplus of $111,130 compared to a working capital deficit of $105,020 at December 31, 2011. Current liabilities decreased to $273,209 at December 31, 2012 from $689,383 at December 31, 2011 primarily due to a decrease of $322,634 in accounts payable, a decrease in accrued interest of $124,628, a decrease in the liability for unauthorized preferred stock of $22,881, and an increase of $53,969 in accrued liabilities.
 
The Company had a $6.7 million net loss, of which $5 million was in non-cash, resulting in $2.6 million net cash used by operating activities. This compares to cash used by operating activities for the twelve months ended December 31, 2011 of $2.0 million after the net loss for the period of $3.7 million was decreased by $2.2 million in non-cash charges and increased by $272,277 in changes to the working capital accounts.
 
Net cash used in investing activities, excluding exploration-related charges taken directly to income and prepaid receivables for drilling cost, for the twelve months ended December 31, 2012 was $516,533. This includes $8,925 for the drilling and completion of wells, $675,058 for the acquisition of land, $200,000 of proceeds from the sale of oil and natural gas properties, and $32,550 for the purchase of furniture and fixtures. This compares to $597,724 of net cash used by investing activities for the twelve month period ended December 31, 2011 which included $219,700 for the acquisition of producing wells, $369,695 for the drilling and completion of wells and $8,329 for the purchase of furniture and fixtures.
 
Net cash provided by financing activities for the twelve months ended December 31, 2012 was $2.8 million. Of this amount, $1.8 million came from the sale of 10% Senior Secured Convertible Debentures and $1.1 million came from contributions from Navitus. This compares to the $3.0 million in cash provided by financing activities during the twelve months ended December 31, 2011, of which $3.1 million came from the sale of 10% Senior Secured Convertible Debentures.
 
Three Months Ended March 31, 2011 Compared to the Three Months Ended March 31, 2010

Revenues: All of our revenue was derived from the sale of natural gas. Our revenues decreased $63,585 or 43% to $85,786 for the three months ended March 31, 2011 from $149,371 for the three months ended March 31, 2010. The decrease reflects both a decline in volume of gas sold to 11,675 MCF in the three months ended March 31, 2011 compared to 21,406 MCF for the three months ended March 31, 2010 and the decrease in the average natural gas price received of $7.35 per MCF for the three months ended March 31, 2011 compared to $6.98 for the three months ended March 31, 2010. The decline in gas production is attributable to the normal productivity decline that occurs with these types of wells over time.

Costs of Production: Our cost of production, including lease operating costs and production taxes increased $34,744 or 293% to $46,626 for the three months ended March 31, 2011 from $11,882 for the three months ended March 31, 2010. This increase is due to additional operating expenses and other one-time charges associated with on-going well production.

Exploration Expense: Exploration expense for the three month period ended March 31, 2011 was $73,132. This compares to no exploration expense for the three month period ended March 31, 2010. This increase in exploration expense reflects a higher level of exploration activities.

General and Administrative Expense: General and administrative expenses increased $456,868 or 288% to $615,296 for the three months ended March 31, 2011 from $158,428 for the three months ended March 31, 2010. The increase reflects a number of one-time charges including accounting, auditing, and legal expenses to bring the Company current on its SEC filings, the final settlement with the former officer of the Company, and the increase in salaries and expenses associated with the startup of the Austin office.

Depletion and Accretion: Depletion, accretion, and depreciation declined $12,781 or 51% to $12,202 for the three months ended March 31, 2011 from $24,983 for the three months ended March 31, 2010. The decrease was due to the lower amount of asset cost basis available to deplete following the impairment adjustment of 2010.

Gain on Settlement: On March 24, 2011, we entered into a comprehensive Settlement Agreement with Jon Fullenkamp in which Fullenkamp gave up his claim to several amounts reported by us as owing to him. The elimination of the claims were made to the consolidated financial statements in 2010 and reported in the both the 2010 Annual Report on Form 10-K and the 2010 Quarterly Reports on Forms 10-Q which had not been filed at the time of the settlement.

Interest Expense: Interest expense increased $204,860 or 2,483% to $213,112 for the three months ended March 31, 2011 from $8,252 for the three months ended March 31, 2010. Of this amount, $170,086 represents the amortization of the non-cash debt discount associated with the sale of the 10% Senior Secured Convertible Debentures and $43,026 represents the actual interest expense due on the 10% Senior Secured Convertible Debentures.

Income Taxes: There is no provision for income tax recorded for either the three months ended March 31, 2011 or for the three months ended March 31, 2010 due to the expected operating losses of both years. The original provision of an income tax benefit of $58,105 for the three months ended March 31, 2011 has been eliminated in restatement due to applying a net realizable value evaluation. We had available Federal income tax net operating loss (“NOL”) carry forwards of approximately $5.5 million at December 31, 2010. Our NOL generally begins to expire in 2027.
 
 
33

 
 
Net Income (Loss): We had a net loss of $363,567 for the three months ended March 31, 2011, due primarily to the one-time gain of $404,624 on the settlement with our former executive officer. For the three months ended March 31, 2010, we had a net loss of $76,934. During the three months ended March 31, 2011, as with the three months ended March 31, 2010, we did not generate positive cash flow from normal 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

Our cash and cash equivalents, total current assets, total assets, total current liabilities, and total liabilities as of March 31, 2011 as compared to March 31, 2010, are as follows:
 
 
 
March 31,
2011
   
March 31,
2010
 
Cash
  $ 187,494     $ 48,600  
Total current assets
    280,806       182,784  
Total assets
    1,148,985       978,188  
Total current liabilities
    677,905       894,949  
Total liabilities
    1,002,611       929,926  
 
At March 31, 2011, we had a working capital deficit of $397,099 compared to a working capital deficit of $712,165 at March 31, 2010. Current liabilities decreased to $677,905 at March 31, 2011 from $894,949 at March 31, 2010 primarily due to the conversion of short term notes payable and accrued interest due a related party to a 10% Senior Debenture.

Net cash used by operating activities for the three months ended March 31, 2011 totaled $505,505 after the cash used in the net loss of $363,567 was decreased by $201,248 in non-cash charges and increased by $109,724 in net increases in the working capital accounts. This compares to cash used by operating activities for the three months ended March 31, 2010 was $57,419 after the net loss for the period of $76,934.

Net cash used in investing activities for the three months ended March 31, 2011 was $213,868 of which $205,539 was used for drilling costs related to the new working interest acquired during the period and $8,329 was used in the purchase of furniture and equipment for the Austin office. There was no cash used in investing activities for the three months ended March 31, 2010.

Net cash provided by financing activities for the three months ended March 31, 2011 totaled $853,400 of which $910,000 came from sale of the 10% Senior Secured Convertible Debentures. Notes payable to a related party was paid off for $50,000 and the bank line of credit was paid down by $6,600. This compares to $83,943 in cash used in financing activities for the three month period ended March 31, 2010 of which $90,000 came from notes payable to a related party and $6,057 was used to pay down the bank line of credit.

Three Months Ended June 30, 2011 Compared to the Three Months Ended June 30, 2010

Revenues: All of our revenue was derived from the sale of oil and natural gas. Our revenues decreased $37,055 or 31% to $81,873 for the three months ended June 30, 2011 from $118,928 for the three months ended June 30, 2010. The decrease reflects a decline in volume of gas sold to 10,931 MCF in the three months ended June 30, 2011 compared to 21,032 MCF for the three months ended June 30, 2010 offset by an in increase in the average natural gas price received of $7.49 per MCF for the three months ended June 30, 2011 compared to $5.65 for the three months ended June 30, 2010. The decline in gas production is attributable to the normal productivity decline that occurs with these types of wells over time.

Costs of Production: Our cost of production, including lease operating costs and production taxes for the three months ended June 30, 2011 were $39,074 and were flat when compared to our production costs for the three month period ended June 30, 2010.

Exploration Expense: Exploration expense for the three month period ended June 30, 2011 was $58,451. This compares to no exploration expense for the three month period ended June 30, 2010. This increase in exploration expense reflects a higher level of exploration activity during the second quarter of 2011.

General and Administrative Expense: General and administrative expenses increased $228,468 or 122% to $415,242 for the three months ended June 30, 2011 from $186,774 for the three months ended June 30, 2010. The increase reflects a number of one-time charges including accounting, auditing, and legal expenses to bring the Company current on its SEC filings, and the increase in salaries and expenses associated with the opening of the Austin office in January 2011.

Depletion and Accretion: Depletion, accretion, and depreciation declined $6,581 or 26% to $18,402 for the three months ended June 30, 2011 from $24,983 for the three months ended June 30, 2010. The decrease was due to the lower amount of asset cost basis available to deplete following the impairment adjustment of 2010.
 
 
34

 

Interest Expense: Interest expense increased $954,434 to $965,303 for the three months ended June 30, 2011 from $10,869 for the three months ended June 30, 2010. Of this amount, $904,340 represents the amortization of the non-cash debt discount associated with the sale and conversion of the 10% Senior Secured Convertible Debentures and $60,963 represents the actual interest expense due on the 10% Senior Secured Convertible Debentures and the bank line of credit.

Income Taxes: There is no provision for income tax recorded for either the three months ended June 30, 2011 or for the three months ended June 30, 2010 due to the expected operating losses of both years. The original provision of an income tax benefit of $331,927 for the three months ended June 30, 2011 has been eliminated in restatement due to applying a net realizable value evaluation. We had available Federal income tax net operating loss (“NOL”) carry forwards of approximately $5.5 million at December 31, 2010. Our NOL generally begins to expire in 2027.

Net Loss: We had a net loss of $1.4 million for the three months ended June 30, 2011 compared to a net loss of $127,347 for the three months ended June 30, 2010. Of this loss, approximately $316,563 represents a net decrease in operating income and $954,434 represents increases in cash and non-cash financing interest costs. This net loss should be viewed in light of the cash flow from operations discussed below.

Six Months Ended June 30, 2011 Compared to the Six Months Ended June 30, 2010

Revenues: All of our revenue was derived from the sale of oil and natural gas. Our revenues decreased $100,620 or 38% to $167,679 for the six months ended June 30, 2011 from $268,299 for the six months ended June 30, 2010. The decrease reflects a decline in volume of gas sold to 22,606 MCF in the six months ended June 30, 2011 compared to 42,438 MCF for the six months ended June 30, 2010 offset by the increase in the average natural gas price received of $7.41 per MCF for the six months ended June 30, 2011 compared to $6.32 for the six months ended June 30, 2010. The decline in gas production is attributable to the normal productivity decline that occurs with these types of wells over time.

Costs of Production: Our cost of production, including lease operating costs and production taxes increased $33,914 or 65% to $85,700 for the six months ended June 30, 2011 from $51,786 for the six months ended June 30, 2010. This increase is due to additional operating expenses and other one-time charges associated with on-going well production.

Exploration Expense: Exploration expense for the six month period ended June 30, 2011 was $117,923. This compares to no exploration expense for the same six month period of 2010. This increase in exploration expense reflects a higher level of exploration activity during the first six months of 2011.

General and Administrative Expense: General and administrative expenses increased $698,996 or 202% to $1,044,198 for the six months ended June 30, 2011 from $345,202 for the six months ended June 30, 2010. The increase reflects a number of one-time charges including accounting, auditing, and legal expenses to bring the Company current on its SEC filings, the legal cost related to the final settlement with the former officer of the Company, and the increase in salaries and expenses associated with the operations of the Austin office.

Depletion and Accretion: Depletion, accretion, and depreciation declined $19,362 or 39% to $30,604 for the six months ended June 30, 2011 from $49,966 for the six months ended June 30, 2010. The decrease was due to the lower amount of asset cost basis available to deplete following the impairment adjustment of 2010.

Gain on Settlement: On March 24, 2011, we entered into a comprehensive Settlement Agreement with Jon Fullenkamp in which Fullenkamp gave up his claim to several amounts reported by us as owing to him. The elimination of the claims were made to the consolidated financial statements in 2010 and reported in the both the 2010 Annual Report on Form 10-K and the 2010 Quarterly Reports on Forms 10-Q which had not been filed at the time of the settlement.

Interest Expense: Interest expense increased $1.2 million to $1.2 million for the six months ended June 30, 2011 from $19,121 for the six months ended June 30, 2010. Of this amount, $1.1 million represents the amortization of the non-cash debt discount associated with the sale and conversion of the 10% Senior Secured Convertible Debentures and $103,989 represents the actual interest expense due on the 10% Senior Secured Convertible Debentures.

Income Taxes: There is no provision for income tax recorded for either the six months ended June 30, 2011 or for the six months ended June 30, 2010 due to the expected operating losses of both years. The original provision of an income tax benefit of $390,032 for the six months ended June 30, 2011 has been eliminated in restatement due to applying a net realizable value evaluation. We had available Federal income tax net operating loss (“NOL”) carry forwards of approximately $5.5 million at December 31, 2010. Our NOL generally begins to expire in 2025.
 
 
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Net Income (Loss): We had a net loss of $1.7 million for the six months ended June 30, 2011. Of this amount, there was a one-time gain of $404,624 on the settlement with our former executive officer.

For the six months ended June 30, 2010, we had a net loss of $191,271. This net loss should be viewed in light of the cash flow from operations discussed below.

During the six months ended June 30, 2011, as with the six months ended June 30, 2010, we did not generate positive cash flow from normal 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

Our cash and cash equivalents, total current assets, total assets, total current liabilities, and total liabilities as of June 30, 2011 as compared to June 30, 2010, are as follows:

 
 
June 30, 2011
   
June 30, 2010
 
Cash
  $ 467,712     $ 68,838  
Total current assets
    553,366       172,316  
Total assets
    1,505,771       942,737  
Total current liabilities
    554,779       999,770  
Total liabilities
    671,325       1,034,747  

At June 30, 2011, we had a working capital deficit of $1,413 compared to a working capital deficit of $827,454 at June 30, 2010. Current liabilities decreased to $554,779 at June 30, 2011 from $999,770 at June 30, 2010 primarily due to the conversion of short term notes payable and accrued interest due a related party to a 10% Senior Secured Debenture.

Net cash used in operating activities for the six months ended June 30, 2011 totaled $.9 million after the cash used in the net loss of $1.7 million was decreased by $750,198 in non-cash charges and increased by $85,267 in net increases in the working capital accounts. This compares to cash used in operating activities for the six months ended June 30, 2010 of $66,533 after the net income for the period of $191,271 was reduced by $348,627 in non- cash charges and offset by $75,247 in changes to the working capital accounts.

Net cash used in investing activities for the six months ended June 30, 2011 was $316,496 of which $308,167 was used for drilling costs related to the new working interest acquired during the period and $8,329 was used in the purchase of furniture and equipment for the Austin office.

Net cash provided by financing activities for the six months ended June 30, 2011 was $1.7 million. Of this amount, $1.8 million came from the sale of 10% Senior Secured Convertible Debentures offset by $56,180 in payments on loans. This compares to $113,295 in cash was provided by financing activities during the six months ended June 30, 2011 of which $125,000 came from a related party loan and $11,705 was used to pay down loans.

Three Months Ended September 30, 2011 Compared to the Three Months Ended September 30, 2010

Revenues: All of our revenue was derived from the sale of oil and natural gas. Our revenues decreased $18,560 or 17% to $90,570 for the three months ended September 30, 2011 from $109,130 for the three months ended September 30, 2010. The decrease reflects the sale of 111 barrels of oil at a weighted average price of $87.75 per barrel. There were no sales of oil in the three months ended September 30, 2010. Before offsets for minority ownership, the decrease also reflects the sale of 16,688 MCF of natural gas at a weighted average price of $4.84 per MCF in the three months ended September 30, 2011 compared to 18,256 MCF of natural gas sold in the three months ending September 30, 2010 at an average price of $5.91 per MCF. The decline in physical gas production is attributable to the normal productivity decline that occurs with these types of wells over time.

Costs of Production: Our cost of production, including lease operating costs and production taxes decreased $7,605 or 20% to $31,213 for the three months ended September 30, 2011 from $38,818 for the three months ended September 30, 2010. This decrease is due to one-time charges associated with on-going well production that are included in our cost of production for the second quarter 2010.
 
 
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Exploration Expense: Exploration expense for the three month period ended September 30, 2011 was $113,301. This compares to no exploration expense for the same three month period of 2010. This increase in exploration expense reflects a higher level of exploration activity during the third quarter of 2011.

General and Administrative Expense: General and administrative expenses increased $222,149 or 100% to $445,091 for the three months ended September 30, 2011 from $222,942 for the three months ended September 30, 2010. For the most part, the increase reflects two additional officers hired in 2011 including the associated payroll taxes and benefits, the fair value of options granted the new officers in the current period, the operations of the Austin office opened in 2011, the services of an investor relations firm, and the fair value of the non-cash director’s compensation earned in the period.

Depletion and Accretion: Depletion, accretion, and depreciation declined $14,817 or 59% to $10,166 for the three months ended September 30, 2011 from $24,983 for the three months ended September 30, 2010. The decrease was due to the lower amount of asset cost basis available to deplete following the impairment adjustment of 2010.

Interest Expense: Interest expense increased $321,628 to $332,604 for the three months ended September 30, 2011 from $10,976 for the three months ended September 30, 2010. For the three months ended September 30, 2011, $297,418 represents the amortization of the non-cash debt discount associated with the sale of the 10% Senior Secured Convertible Debentures and $35,186 represents the actual interest expense accrued on the 10% Senior Secured Convertible Debentures outstanding.

Income Taxes: There is no provision for income tax recorded for either the three months ended September 30, 2011 or for the three months ended September 30, 2010 due to the expected operating losses of both years. The original provision of an income tax benefit of $76,671 for the three months ended September 30, 2011 has been eliminated in restatement due to applying a net realizable value evaluation. We had available Federal income tax net operating loss (“NOL”) carry forwards of approximately $5.5 million at December 31, 2010. Our NOL generally begins to expire in 2027.

Net Loss: We had a net loss of $820,048 for the three months ended September 30, 2011 compared to a net loss of $175,403 for the three months ended September 30, 2010. This net loss should be viewed in light of the cash flow from operations discussed below.

Nine Months Ended September 30, 2011 Compared to the Nine Months Ended September 30, 2010

Revenues: All of our revenue was derived from the sale of oil and natural gas. Our revenues decreased $123,635 or 33% to $253,794 for the nine months ended September 30, 2011 from $377,429 for the nine months ended September 30, 2010. Oil revenues for the nine months ended September 30, 2011 reflect the sale of 168 barrels of oil at a weighted average price of $90.31 per barrel. There were no sales of oil in the nine months ended September 30, 2010. Before offsets minority ownership, gas revenues reflect the sale of 50,762 MCF of gas at a weighted average price of $4.70 per MCF for the nine months ended September 30, 2011 compared to the sale of 60,695 MCF of natural gas sold at $6.22 per MCF for the nine month period ended September 30, 2010. The decline in gas production is attributable to the normal productivity decline that occurs with these types of wells over time.

Costs of Production: Our cost of production, including lease operating costs and production taxes increased $21,874 or 24% to $112,478 for the nine months ended September 30, 2011 from $90,604 for the nine months ended September 30, 2010. This increase is due to additional operating expenses and other one-time charges associated with on-going well production.

Exploration Expense: Exploration expense for the nine month period ended September 30, 2011 was $175,574. This compares to no exploration expense for the same nine month period of 2010. This increase in exploration expense reflects a higher level of exploration activity during the first nine months of 2011.

General and Administrative Expense: General and administrative expenses increased $1,152,237 or 202% to $1,544,897 for the nine months ended September 30, 2011 from $568,144 for the nine months ended September 30, 2010. The increase reflects a number of one-time charges including accounting, auditing, and legal expenses to bring the Company current on its SEC filings, the legal cost related to the final settlement with the former officer of the Company, as well as the two additional officers hired in 2011 including the associated payroll taxes and benefits, the fair value of options granted the new officers in the current period, the operations of the Austin office opened in 2011, the services of an investor relations firm, and the fair value of the non-cash director’s compensation earned in the period.

Depletion and Accretion: Depletion, accretion, and depreciation declined $34,179 or 46% to $40,770 for the nine months ended September 30, 2011 from $74,949 for the nine months ended September 30, 2010. The decrease was due to the lower amount of asset cost basis available to deplete following the impairment adjustment of 2010.
 
 
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Gain on Settlement: On March 24, 2011, we entered into a comprehensive Settlement Agreement with Jon Fullenkamp in which Fullenkamp gave up his claim to several amounts reported by us as owing to him. The elimination of the claims were made to the consolidated financial statements in 2010 and reported in both the 2010 Annual Report on Form 10-K and the 2010 Quarterly Reports on Forms 10-Q which had not been filed at the time of the settlement.

Interest Expense: Interest expense increased $1.5 million to $1.5 million for the nine months ended September 30, 2011 from $30,097 for the nine months ended September 30, 2010. Of this amount, $1.4 million represents the amortization of the non-cash debt discount associated with the sale and conversion of the 10% Senior Secured Convertible Debentures and $139,175 represents the actual interest expense due on the 10% Senior Secured Convertible Debentures.

Income Taxes: There is no provision for income tax recorded for either the nine months ended September 30, 2011 or for the nine months ended September 30, 2010 due to the expected operating losses of both years. The original provision of an income tax benefit of $466,703 for the nine months ended September 30, 2011 has been eliminated in restatement due to applying a net realizable value evaluation. We had available Federal income tax net operating loss (“NOL”) carry forwards of approximately $5.5 million at December 31, 2010. Our NOL generally begins to expire in 2025.

Net Income (Loss): We had a net loss of $2.6 million for the nine months ended September 30, 2011. This net loss should be viewed in light of the cash flow from operations discussed below, which included a one-time gain of $404,624 on the settlement with our former executive officer.

For the nine months ended September 30, 2010, we had a net loss of $379,684. This net income should be viewed in light of the cash flow from operations discussed below.

During the nine months ended September 30, 2011, as with the nine months ended September 30, 2010, we did not generate positive cash flow from normal 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

Our cash and cash equivalents, total current assets, total assets, total current liabilities, and total liabilities as of September 30, 2011 as compared to September 30, 2010, are as follows:

 
 
Sept. 30, 2011
   
Sept. 30, 2010
 
Cash
  $ 223,231     $ 69,038  
Total current assets
    345,455       151,836  
Total assets
    1,397,094       897,274  
Total current liabilities
    330,192       1,140,286  
Total liabilities
    744,156       1,175,263  

At September 30, 2011, we had working capital of $15,263 compared to a working capital deficit of $988,450 at September 30, 2010. Current liabilities decreased to $330,192 at September 30, 2011 from $1,140,286 at September 30, 2010 primarily due to the payoff of the amount due the bank, the amount due a related party, and the conversion of preferred stock to common stock.

Net cash used in operating activities for the nine months ended September 30, 2011 totaled $1.4 million after the net loss of $2.6 million was decreased by $1.2 million in non-cash charges offset by $113,398 in changes to the working capital accounts. This compares to cash used in operating activities for the nine months ended September 30, 2010 of $96,733 after the net loss for the period of $379,684 was decreased by $321,034 in non-cash charges and offset by $206,043 in changes to the working capital accounts.

Net cash used in investing activities for the nine months ended September 30, 2011 was $425,896 of which $417,567 was used for drilling costs related to the new working interest acquired during the period and $8,329 was used in the purchase of furniture and equipment for the Austin office.

Net cash provided by financing activities for the nine months ended September 30, 2011 was $2.1 million. Of this amount, $2.3 million came from the sale of 10% Senior Secured Convertible Debentures offset by $68,667 to retire the bank loan and the $50,000 payoff of amounts due related parties. This compares to $143,695 in cash was provided by financing activities during the nine months ended September 30, 2011 of which $162,000 came from a related party loan and $18,305 was used to pay down the bank loan.
 
 
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Three Months Ended March 31, 2012 Compared to the Three Months Ended March 31, 2011

Revenues: All of our revenue was derived from the sale of oil and natural gas. Our revenues decreased $21,821 or 25% to $63,965 for the three months ended March 31, 2012 from $85,786 for the three months ended March 31, 2011. The decrease reflects a decline in the amount of natural gas sold to 10,386 Mcf at $4.52 per Mcf for the three months ending March 31, 2012 from 11,675 Mcf sold at $6.49 per Mcf in the three months ended March 31, 2011. The decline in physical gas production is attributable to the normal productivity decline that occurs with these types of wells over time. During the three months ended March 31, 2012, we also sold 184 barrels of oil at $92.24 per barrel. There were no sales of oil in the three months ended March 31, 2011.

Lease Operating Expenses: Our cost of production includes a one-time credit of $35,157 received from an Operator that had received the credit from one of its vendors. Had this credit not been recognized in the period, our cost of production would have been approximately $21,002 for the three months ending March 31, 2012 which would have represented a decrease of $20,496 or 49% from $41,499 for the three months ended March 31, 2011.

Production Taxes: Production taxes increased $1,352 or 26% to $6,479 for the three months ended March 31, 2012 from $5,127 for the three months ended March 31, 2011. The change is not considered meaningful and reflects the timing of the calculation and payment of production taxes.

Exploration Expense: Exploration expense increased $23,735 or 32.5% to $96,867 for the three months ended March 31, 2012 from $73,132 for the three months ended March 31, 2011. This increase reflects the higher tempo of exploration activities as the Company had only just hired a full time exploration officer employee in the three months ended March 31, 2011.

General and Administrative Expense: General and administrative expenses increased $49,538 or 8.3% to $645,875 for the three months ended March 31, 2012 from $596,337 for the three months ended March 31, 2011. For the most part, the increase reflects the addition of a new chief financial officer, ongoing investor relations activities, and outside management consulting services which were not part of general and administrative expense in the three months ended March 31, 2011.

General and Administrative Expense – non cash: General and administrative non-cash expenses increased $316,890 to $335,850 for the three months ended March 31, 2012 from $18,960 for the three months ended March 31, 2011. The increase reflects the non-cash charges related to the issuance of warrants to board members for their service as members of the board, additional warrants to a related party to serve as general counsel of the Company, warrants to a management consultant for services in that capacity, employee stock options to the new Chief Financial Officer, and the amortization of employee stock options as such options vest. Such non-cash compensation totaled $18,960 in the three months ended March 31, 2011 in warrants to the board members for their service as members of the board.

Depletion and Accretion: Depletion, accretion, and depreciation increased $6,607 or 54% to $18,809 for the three months ended March 31, 2012 from $12,202 for the three months ended March 31, 2011. The increase is due to the additional depletion of the operating oil wells in 2012 which the company did not have in the three months ending March 31, 2011.

Interest Expense: Interest expense increased $3.8 million to $4.0 million for the three months ended March 31, 2012 from $213,112 for the three months ended March 31, 2011. For the three months ended March 31, 2012, $265,460 represents the amortization of the non-cash debt discount associated with the sale of the outstanding 10% Senior Secured Convertible Debentures from January 1, 2012 up to the point where the 10% Senior Secured Convertible Debentures were converted to common stock on February 29, 2012, $3.7 million represents the recognition of the remaining non-cash debt discount associated with the conversion of all the outstanding 10% Senior Secured Convertible Debentures to common stock on February 29, 2012, and $56,782, for the most part, represents the actual interest expense accrued on the 10% Senior Secured Convertible Debentures outstanding until their conversion on February 29, 2012.

Income Taxes: There is no provision for income tax recorded for either the three months ended March 31, 2012 or for the three months ended March 31, 2011 due to the expected operating losses of both years. The original provision of an income tax benefit of $58,105 for the three months ended March 31, 2011 has been eliminated in restatement due to applying a net realizable value evaluation. We had available Federal income tax net operating loss (“NOL”) carry forwards of approximately $12,960,120 at December 31, 2011. Our NOL generally begins to expire in 2027.
 
 
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Net Loss: We had a net loss of $5.0 million for the three months ended March 31, 2012 compared to a net loss of $363,567 for the three months ended March 31, 2011. For the three months ended March 31, 2012 approximately $4.3 million of this loss was related to the non-cash charges related to the debt discount on the 10% Senior Secured Convertible Debentures which were converted to common stock on February 29, 2012 and to non-cash compensation awards to individuals for board service, employee stock options, and other management and consulting services. This net loss should be viewed in light of the cash flow from operations discussed below.

Liquidity and Capital Resources

Our cash and cash equivalents, total current assets, total assets, total current liabilities, and total liabilities as of March 31, 2012 as compared to March 31, 2011, are as follows:

 
 
March 31, 2012
   
March 31, 2011
 
Cash
  $ 872,367     $ 187,494  
Total current assets
    1,034,470       280,806  
Total assets
    2,645,888       1,148,985  
Total current liabilities
    423,312       677,905  
Total liabilities
    453,316       1,002,611  

At March 31, 2012, we had working capital of $611,158 compared to a working capital deficit of $397,099 at March 31, 2011. Current liabilities decreased to $423,312 at March 31, 2012 from $677,905 at March 31, 2011 primarily due to the payoff of the amount due the bank, the amount due a related party, the conversion of unauthorized preferred stock to common stock, and the conversion of accrued interest to common stock.

Net cash used in operating activities for the three months ended March 31, 2012 totaled $830,461 after the net loss of $5.0 million was decreased by $4.3 million in non-cash charges and offset by $112,703 in changes to the working capital accounts. This compares to cash used in operating activities for the three months ended March 31, 2011 of $563,610 after the net loss for the period of $816,477 was decreased by $201,248 in non-cash charges and $109,724 in changes to the working capital accounts.

Net cash used in investing activities for the three months ended March 31, 2012 was $587,795 of which $82,795 was for drilling and related costs for exploration efforts and $505,000 was used to acquire land for drilling. This compares to $205,539 in drilling costs and $8,329 in purchases of furniture and fixtures for the then new Austin, Texas office during the three months ended March 31, 2011.

Net cash provided by financing activities for the three months ended March 31, 2012 was $1.8 million of which $1.7 million came from the sale of the Company’s 10% Senior Secured Convertible Debentures. This compares to $853,400 provided by financing activities during the three months ended March 31, 2011 of which $910,000 came from the sale of the Company’s 10% Senior Secured Convertible Debentures, $6,600 was used to pay down the bank line of credit and $50,000 was used to pay off a note due a related party.
 
Three Months Ended June 30, 2012 compared to the Three Months Ended June 30, 2011
 
Revenues: All of our revenue was derived from the sale of oil and natural gas. Our revenues decreased $13,722 or 16.8% to $68,151 for the three months ended June 30, 2012 from $81,873 for the three months ended June 30, 2011. The decrease primarily reflects a decline in the price and volume of natural gas sold to $3.51 per Mcf for the 10,549 Mcf of gas sold for the three months ending June 30, 2012 from $6.51 per Mcf for the 10,931 Mcf of gas sold in the three months ended June 30, 2011. The decline in physical gas production is attributable to the normal productivity decline that occurs with these types of wells over time. During the three months ended June 30, 2012, we also sold 289 barrels of oil at $90.90 per barrel. There were no sales of oil in the three months ended June 30, 2011.
 
Lease Operating Expenses: Our cost of production increased $27,063 or 89% to $57,565 for the three months ended June 30, 2012 from $30,502 for the three months ended June 30, 2011. The increase in lease operating expenses reflects an increase in the number of operating properties in the three months ended June 30, 2012 compared to the three months ended June 30, 2011.
 
Production Taxes: Production taxes decreased $2,901 or 33.8% to $5,671 for the three months ended June 30, 2012 from $8,572 for the three months ended June 30, 2011. The change is not considered meaningful and reflects the timing of the calculation and payment of production taxes.
 
 
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Exploration Expense: Exploration expense increased $1,753 or 3.0% to $60,204 for the three months ended June 30, 2012 from $58,451 for the three months ended June 30, 2011. The change is not considered meaningful and simply reflects the timing of expenses for exploration activities.
 
Exploration Expense – non cash: Exploration non-cash expense increased $10,125 for the three months ended June 30, 2012 from $0 for the three months ended June 30, 2011. This increase reflects the vesting of exploration-dedicated employee stock options during the three months ended June 30, 2012. There were no stock options outstanding during the three months ending June 30, 2011.
 
General and Administrative Expense: General and administrative expenses decreased $71,212 or 17.8% to $327,790 for the three months ended June 30, 2012 from $399,002 for the three months ended June 30, 2011. For the most part, the decrease reflects the reduction in professional and consulting fees with the consolidation of the Company’s operations in Austin, Texas.
 
General and Administrative Expense – non cash: General and administrative non-cash expenses increased $241,870 to $258,110 for the three months ended June 30, 2012 from $16,240 for the three months ended June 30, 2011. The increase reflects the non-cash charges related to the grant of employee stock options and the amortization of previous of stock options as they vest over time and the cost of warrants granted to one affiliate and two non-affiliates of the Company for special consulting assistance in certain undertakings of the Company. Such non-cash compensation totaled $18,960 in the three months ended June 30, 2011 for warrants to the board members for their service as members of the board.
 
Depletion and Accretion: Depletion, accretion, and depreciation decreased $5,130 or 27.9% to $13,272 for the three months ended June 30, 2012 from $18,402 for the three months ended June 30, 2011. The decrease is due to the reduction in amount of assets subject to depletion as a result of the sale of the Jones County/Atwood properties in May, 2012.
 
Gain on Sale of Assets: On May 10, 2012, the Company sold its interests in the Jones County Oil Play and the Atwood Secondary Oil Recovery project for $400,000 in cash payable in two even installments in May and July, 2012. The sale resulted in a one-time pre-tax gain of $268,169.
 
Interest Expense: Interest expense decreased $964,985 to $318 for the three months ended June 30, 2012 from $965,303 for the three months ended June 30, 2011. The decrease was due to the conversion of the 10% Senior Secured Convertible Debentures to the Company’s common stock on February 29, 2012 which eliminated the source of the interest expense. The $318 in interest expense results from the financing associated with one of the Company’s insurance policies.
 
Income Taxes: There is no provision for income tax recorded for either the three months ended June 30, 2012 or for the three months ended June 30, 2011 due to the expected operating losses of both years. The original provision of an income tax benefit of $396,735 for the three months ended June 30, 2011 has been eliminated in restatement due to applying a net realizable value evaluation. We had available Federal income tax net operating loss (“NOL”) carry forwards of 12,960,120 at December 31, 2011. Our NOL generally begin to expire in 2027.
 
 Net Loss: We had a net loss of $497,678 for the three months ended June 30, 2012 compared to a net loss of $1.4 million for the three months ended June 30, 2011. This net loss for the three months ended June 30, 2012 should be viewed in light of the cash flow from operations discussed below.
 
Six Months Ended June 30, 2012 Compared to the Six Months Ended June 30, 2011
 
 Revenues: All of our revenue was derived from the sale of oil and natural gas. Our revenues decreased $35,541 or 21.2% to $132,118 for the six months ended June 30, 2012 from $167,659 for the six months ended June 30, 2011. The decrease reflects a decline in the price and volume of natural gas sold to $4.14 per Mcf for the 20,892 Mcf of gas sold for the six months ending June 30, 2012 from $6.70 per Mcf for the 22,606 Mcf of gas sold in the six months ended June 30, 2011. The decline in physical gas production is attributable to the normal productivity decline that occurs with these types of wells over time. During the six months ended June 30, 2012, we also sold 492 barrels of oil at $92.88 per barrel. There were no sales of oil in the six months ended June 30, 2011.
 
Lease Operating Expenses: Our cost of production decreased $28,590 or 39.7% to $43,411 for the six months ended June 30, 2012 from $72,001 for the six months ended June 30, 2011. The decrease in lease operating expenses resulted from a large one-time credit from a 2011 sub-contractor billing error in favor of one of our field operators during the three months ended March 31, 2012. Had this credit not been received, our cost of production for the six months ended June 30, 2012 would have been $61,055. This would have been a decrease of $10,946 from $72,001 for the six month period ended June 30, 2011. This decrease is not meaningful and reflects the timing of operator activities on the properties. There was an increase in the number of oil and natural gas properties during the six months ended June 30, 2012 compared to the six months ended June 30, 2012, notwithstanding our sale of the Jones County Oil Play and the Atwood Secondary Oil Recovery project in May, 2012.
 
 
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Production Taxes: Production taxes decreased $1,549 or 11.3% to $12,150 for the six months ended June 30, 2012 from $13,699 for the six months ended June 30, 2011. The change is not considered meaningful and reflects the timing of the calculation and payment of production taxes.
 
Exploration Expense: Exploration expense increased $29,023 or 24.6% to $146,946 for the six months ended June 30, 2012 from $117,923 for the six months ended June 30, 2011. The increase reflects the higher overall level of exploration activities for the six months ended June 30, 2012 compared to the six month period ended June 30, 2011.
 
Exploration Expense – non cash: Exploration non-cash expense increased $20,250 for the six months ended June 30, 2012 from $0 for the three months ended June 30, 2011. This increase reflects the vesting of exploration-dedicated employee stock options during the six months ended June 30, 2012. During the six months ended June 30, 2011, there were no option grants outstanding.
 
General and Administrative Expense: General and administrative expenses decreased $35,333 or 3.5% to $973,665 for the six months ended June 30, 2012 from $1,008,998 for the six months ended June 30, 2011. For the most part, the decrease reflects the net effect of the addition of a new chief financial officer, ongoing investor relations activities, and outside management consulting services which were not part of general and administrative expense in the six months ended June 30, 2011 offset by lower audit, accounting, and legal fees associated with the extensive restatement and catch up effort to bring the Company current on its SEC filings undertaken as well as the legal settlement with a former officer of the Company during the six months ended June 30, 2011.
 
General and Administrative Expense – non cash: General and administrative non-cash expenses increased $558,760 to $593,960 for the six months ended June 30, 2012 from $35,200 for the six months ended June 30, 2011. The increase reflects the non-cash charges related to grants of non-qualified stock options to employees and offices of the Company and the amortization of previous of stock option as they vest over time, the cost of warrants granted to affiliates and non-affiliates is of the Company for special consulting assistance in certain undertakings of the Company, and warrants granted to a related party to serve as general counsel of the Company. Such non-cash compensation totaled $35,200 in the six months ended June 30, 2011 for warrants to the board members for their service as members of the board.
 
Depletion and Accretion: Depletion, accretion, and depreciation increased $1,477 or 4.8% to $32,081 for the six months ended June 30, 2012 from $30,604 for the six months ended June 30, 2011. The increase is not considered meaningful and due to the additional depletion of the operating oil wells in early 2012 which the Company did not have in the six months ending June 30, 2011 which was somewhat offset by the reduction in amount of assets subject to depletion as a result of the sale of the Jones County/Atwood properties in May, 2012.
 
Gain on Sale of Assets: On May 10, 2012, the Company sold its interests in the Jones County Oil Play and the Atwood Secondary Oil Recovery project for $400,000 in cash payable in two even installments in May and July, 2012. The sale resulted in a one-time gain of $268,169.
 
Interest Expense: Interest expense increased $2.8 million to $4.0 million for the six months ended June 30, 2012 from $1.2 million for the six months ended June 30, 2011. For the six months ended June 30, 2012, $265,460 represents the amortization of the non-cash debt discount associated with the sale of the 10% Senior Secured Convertible Debentures from January 1, 2012 up to the point where the 10% Senior Secured Convertible Debentures were converted to common stock on February 29, 2012, $3.7 million represents the recognition of the remaining non-cash debt discount associated with the conversion of all the outstanding 10% Senior Secured Convertible Debentures to common stock on February 29, 2012, and $56,782, for the most part, represents the actual interest expense accrued on the 10% Senior Secured Convertible Debentures outstanding until the conversion of the 10% Senior Secured Convertible Debentures on February 29, 2012.
 
Income Taxes: There is no provision for income tax recorded for either the six months ended June 30, 2012 or for the six months ended June 30, 2011 due to the expected operating losses of both years. The original provision of an income tax benefit of $390,032 for the six months ended June 30, 2011 has been eliminated in restatement due to applying a net realizable value evaluation. We had available NOL carry forwards of 12,960,120 at December 31, 2011. Our NOL generally begins to expire in 2027.
 
Net Loss: We had a net loss of $5.5 million for the six months ended June 30, 2012 compared to a net loss of $1.7 million for the six months ended June 30, 2011. The net loss was reduced by the gain on the sale of assets of $268,169. For the six months ended June 30, 2012 approximately $4.5 million of this loss was related to the non-cash charges related to the debt discount on the 10% Senior Secured Convertible Debentures which were converted to common stock on February 29, 2012 and to non-cash compensation awards to individuals for board service, employee stock options, and other management and consulting services. This net loss should be viewed in light of the cash flow from operations discussed below.
 
 
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Liquidity and Capital Resources
 
Our cash, total current assets, total assets, total current liabilities, and total liabilities as of June 30, 2012 as compared to June 30, 2011, are as follows:

 
 
June 30, 2012
   
June 30, 2011
 
Cash
  $ 320,015     $ 467,712  
Total current assets
    590,258       553,366  
Total assets
    2,337,180       1,505,771  
Total current liabilities
    215,872       554,779  
Total liabilities
    245,876       671,325  

At June 30, 2012, we had working capital of $374,386 compared to a working capital deficit of $1,413 at June 30, 2011. Current liabilities decreased to $215,872 at June 30, 2012 from $554,779 at June 30, 2011 primarily due to the payoff of the amount due a bank, the amount due a related party, the conversion of unauthorized preferred stock to common stock, and the conversion of accrued interest to common stock.
 
Net cash used in operating activities for the six months ended June 30, 2012 $1.5 million after the net loss of $5.4 million was decreased by $4.3 million in non-cash charges and offset by $197,857 in changes to the working capital accounts. This compares to cash used in operating activities for the six months ended June 30, 2011 of $1.0 million after the net loss for the period of $1.7 million was decreased by $750,198 in non-cash charges and $85,267 in changes to the working capital accounts.
 
Net cash used in investing activities for the six months ended June 30, 2012 was $875,946 of which $159,494 was for drilling and related costs for exploration efforts, $706,093 was used to acquire land and rights to land for drilling, and $10,359 was used to purchase furniture and fixtures for the Austin, Texas office. This compares to $308,167 in drilling costs and $8,329 in purchases of furniture and fixtures for the then new Austin, Texas office during the six months ended June 30, 2011. $200,000 came from the sale of the Company’s investment in the Jones County/Atwood properties.
 
Net cash provided by financing activities for the six months ended June 30, 2012 was $2.2 million of which $1.8 million came from the sale of the 10% Senior Secured Convertible Debentures and $4,350 came from the exercise of warrants. This compares to $1.7 million provided by financing activities during the six months ended June 30, 2011 of which $1.8 million came from the sale of the 10% Senior Secured Convertible Debentures while $6,180 was used to pay down a bank line of credit and $50,000 was used to pay off a note due a related party.
 
Three Months Ended September 30, 2012 compared to the Three Months Ended September 30, 2011
 
Revenues: All of our revenue was derived from the sale of oil and natural gas. Our revenues decreased $13,535 or 14.9% to $77,035 for the three months ended September 30, 2012 from $90,570 for the three months ended September 30, 2011. The decrease reflects a decline in sale of natural gas during the three months ending September 30, 2012 from the three months ended September 30, 2011. The decline in gas production is attributable to the normal productivity decline that occurs with these types of wells over time.

 Lease Operating Expenses: Our cost of production increased $2,901 or 15.8% to $21,285 for the three months ended September 30, 2012 from $18,384 for the three months ended September 30, 2011. The increase in lease operating expenses reflects an increase in the number of operating properties in the three months ended September 30, 2012 compared to the three months ended September 30, 2011.
 
Production Taxes: Production taxes decreased $9,199 or 71.7% to $3,630 for the three months ended September 30, 2012 from $12,829 for the three months ended September 30, 2011. This results primarily from the decline in revenue for the three months ended September 30, 2012 compared to the same period in 2011.

Exploration Expense: Exploration expense decreased $50,886 or 45% to $62,415 for the three months ended September 30, 2012 from $113,301 for the three months ended September 30, 2011. The change is not considered meaningful and simply reflects the timing of expenses for exploration activities.
 
 
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General and Administrative Expense: General and administrative expenses increased $231,285 or 52% to $676,376 for the three months ended September 30, 2012 from $445,091 for the three months ended September 30, 2011. The G&A burn rate was higher for this this period in 2012 partially due to additional headcount in Austin, a chief financial officer and an accounting manager, and non-recurring costs associated with the transfer of accounting services from California to Texas. This increase reflects the bad debt expense of $200,000 recorded in the third quarter of 2012 associated with the sale of oil and natural gas assets to CO Energy in May 2012, warrants issued for Board service, all net of a negative adjustment for warrants authorized in a prior period of this year.
 
Depletion and Accretion: Depletion, accretion, and depreciation increased $5,513 or 54% to $15,679 for the three months ended September 30, 2012 from $10,166 for the three months ended September 30, 2011. The increase reflects the increase in the amount of producing wells in the during the respective time periods.
 
Impairment of Assets: During the three months ended September 30, 2012, the Company recorded $162,703 in asset impairment charges for our Uno Mas well which was deemed not commercial and a charge associated with the write-off of other undeveloped land costs in New Mexico. There were no impairment charges for the three months ending September 30, 2011.
 
Interest Expense: Interest expense was $3,040 for the three months ending September 30, 2012. This represents the 10% preferred return which Navitus receives under the Second Amended Partnership Agreement for capital contributions to Aurora arranged by Navitus. During the three months ended September 30, 2011, the Company incurred $332,604 in interest expense virtually all of which was associated with the Company’s 10% Senior Secured Convertible Debentures which were converted to common stock on February 29, 2012.
 
Income Taxes: There is no provision for income tax recorded for either the three months ended September 30, 2012 or for the three months ended September 30, 2011 due to the expected operating losses of both years. The original provision of an income tax benefit of $76,671 for the three months ended September 30, 2011 has been eliminated in restatement due to applying a net realizable value evaluation. We had available Federal income tax net operating loss (“NOL”) carry forwards of 12,960,120 at December 31, 2011. Our NOL generally begins to expire in 2027.
 
Net Loss: We had a net loss of $644,131 for the three months ended September 30, 2012 compared to a net loss of $820,048 for the three months ended September 30, 2011. The net loss for the three months ended September 30, 2012 included $200,000 in bad debt allowance recognized for the final payment due in July, 2012, on the sale of the Jones County Oil Play and the Atwood Secondary Oil Recovery recorded May 10, 2012. The net loss for the three months ended September 30, 2012 should be viewed in light of the cash flow from operations discussed below.

Nine Months Ended September 30, 2012 Compared to the Nine Months Ended September 30, 2011
 
Revenues: All of our revenue was derived from the sale of oil and natural gas. Our revenues decreased $44,643 or 17.6% to $209,151 for the nine months ended September 30, 2012 from $253,794 for the nine months ended September 30, 2011. The decrease reflects a decline in both the price and volume of natural gas sold for the nine months ending September 30, 2012 from the nine months ended September 30, 2011. The decline in physical gas production is attributable to the normal productivity decline that occurs with these types of wells over time.
 
Lease Operating Expenses: Our cost of production decreased $25,690 or 28% to $64,695 for the nine months ended September 30, 2012 from $90,385 for the nine months ended September 30, 2011. The decrease is primarily due to a credit received from a drilling services company in early 2012 for an over-charge paid in 2011.
 
Production Taxes: Production taxes decreased $6,313 or 28.6% to $15,780 for the nine months ended September 30, 2012 from $22,093 for the nine months ended September 30, 2011. The decrease is primarily due to the effect of lower gas volumes and sales prices in 2012 compared to 2011.
 
Exploration Expense: Exploration expense increased $54,037 or 30.7% to $229,611 for the nine months ended September 30, 2012 from $175,574 for the nine months ended September 30, 2011. The increase reflects the higher overall level of exploration activities for the nine months ended September 30, 2012 compared to the nine month period ended September 30, 2011.
 
 
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General and Administrative Expense: General and administrative expenses increased $523,530 or 46% to $2.2 million for the nine months ended September 30, 2012 from $1.5 million for the nine months ended September 30, 2011. For the most part, the increase reflects the increase in non-recurring accounting service expenses associated with the transfer of the accounting function from Irvine, CA, to Austin, TX during the three month period ending September 30, 2012 and the compensation expense associated with the addition of one officer and one employee compared to no such costs for the same three months ending September 30, 2011. The increase reflects charges in 2012 related to a bad debt expense associated with the sale of oil and natural gas assets in May 2012, grants related to non-qualified stock options to employees and officers of the Company, the amortization of previous of stock option as they vest over time, the cost of warrants granted to affiliates and non-affiliates is of the Company for special consulting assistance in certain undertakings of the Company, and warrants granted to a related party to serve as general counsel of the Company all net of a negative adjustment for warrants authorized in a prior period of this year.
 
Depletion and Accretion: Depletion, accretion, and depreciation increased $6,990 or 17.1% to $47,760 for the nine months ended September 30, 2012 from $40,770 for the nine months ended September 30, 2011. The increase is due to the additional depletion of the operating oil wells in early 2012 which the Company did not have in the nine months ending September 30, 2011 notwithstanding the reduction in amount of assets subject to depletion as a result of the sale of the Jones County/Atwood properties in May, 2012. 
 
Gain on Sale of Assets: On May 10, 2012, the Company sold its interests in the Jones County Oil Play and the Atwood Secondary Oil Recovery project for $400,000 in cash payable in two even installments in May and July, 2012. The sale resulted in a one-time gain of $268,169. The Company has recognized a bad debt allowance of $200,000 against the second installment which was due in July, 2012.
 
Impairment of Assets: During the nine months ended September 30, 2012, the Company recorded $162,703 in asset impairment charges for our Uno Mas well which was deemed not commercial and a charge associated with the write-off of other undeveloped land costs in New Mexico. There were no impairment charges for the nine months ending September 30, 2011.
 
Interest Expense: Interest expense increased $2.5 million to $4.0 million for the nine months ended September 30, 2012 from $1.5 million for the nine months ended September 30, 2011. For the nine months ended September 30, 2012, $265,460 represents the amortization of the non-cash debt discount associated with the sale of the 10% Senior Secured Convertible Debentures from January 1, 2012 up to the point where the 10% Senior Secured Convertible Debentures were converted to common stock on February 29, 2012, $3.7 million represents the recognition of the remaining non-cash debt discount associated with the conversion of all the outstanding 10% Senior Secured Convertible Debentures to common stock on February 29, 2012, and $57,100, for the most part, represents the actual interest expense accrued on the10% Senior Secured Convertible Debentures outstanding until the conversion of the 10% Senior Secured Convertible Debentures on February 29, 2012, and $3,040 represents the 10% return paid to Navitus for arranging for additional contributions to Aurora.
 
Income Taxes: There is no provision for income tax recorded for either the nine months ended September 30, 2012 or for the nine months ended September 30, 2011 due to the expected operating losses of both years. The original provision of an income tax benefit of $466,703 for the nine months ended September 30, 2011 has been eliminated in restatement due to applying a net realizable value evaluation. We had available NOL carry forwards of 12,960,120 at December 31, 2011. Our NOL generally begins to expire in 2027.
 
Net Loss: We had a net loss of $6.1 million for the nine months ended September 30, 2012 compared to a net loss of $2.6 million for the nine months ended September 30, 2011. This net loss should be viewed in light of the cash flow from operations discussed below.

Liquidity and Capital Resources
 
Our cash, total current assets, total assets, total current liabilities, and total liabilities as of September 30, 2012 as compared to September 30, 2011, are as follows:
 
 
 
Sept. 30, 2012
   
Sept. 30, 2011
 
Cash
  $ 99,363     $ 223,231  
Total current assets
    164,246       345,455  
Total assets
    1,804,004       1,397,094  
Total current liabilities
    229,882       330,192  
Total liabilities
    259,886       744,156  
 
 
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At September 30, 2012, we had a working capital deficit of $65,636 compared to a working capital surplus of $15,263 at September 30, 2011. Current liabilities decreased to $229,882 at September 30, 2012 from $330,192 at September 30, 2011 primarily due to the pay down of accounts payable offset somewhat by an increase in accrued royalties and the conversion of accrued interest to common stock.
 
Net cash used in operating activities for the nine months ended September 30, 2012 was $1.6 million after the net loss of $6.1 million was decreased by $4.7 million in non-cash charges and offset by $178,487 in changes to the working capital accounts. This compares to cash used in operating activities for the nine months ended September 30, 2011 of $1.6 million after the net loss for that period of $2.6 million was decreased by $1.2 million in non-cash charges offset by $113,398 in changes to the working capital accounts.
 
Net cash used in investing activities for the nine months ended September 30, 2012 was $936,292 of which $263,650 was for drilling and related costs for exploration efforts, $661,983 was used to acquire land and rights to land for drilling, and $10,359 was used to purchase furniture and fixtures for the Austin, Texas office. This compares to $417,567 in drilling costs and $8,329 in purchases of furniture and fixtures for the then new Austin, Texas office during the nine months ended September 30, 2011. $200,000 came from the sale of the Company’s investment in the Jones County/Atwood properties.
 
Net cash provided by financing activities for the nine months ended September 30, 2012 was $2.3 million of which $1.8 million came from the sale of the Company’s 10% Senior Secured Convertible Debentures, $349,900 came from contributions from Navitus, and $4,874 came from the exercise of warrants. In the meantime, $61,472 in distributions were made to Navitus in accordance with the Second Amended Aurora Partnership Agreement. This compares to $2.2 million provided by financing activities during the nine months ended September 30, 2011 of which $2.3 million came from the sale of the Company’s 10% Senior Secured Convertible Debentures while $68,667 was used to pay down a bank line of credit and $50,000 was used to pay off a note due a related party.

Recently Issued Accounting Pronouncements
 
Recent Accounting Pronouncements

During the period ended December 31, 2012, the FASB issued ASU 2013-07, "Presentation of Consolidated financial statements (Topic 205): Liquidation Basis of Accounting." The ASU requires organization to prepare its consolidated financial statements using the liquidation basis of accounting when liquidation is "imminent." Liquidation is considered imminent when the likelihood is remote that the organization will return from liquidation and either: (a) a plan for liquidation is approved by the person or persons with the authority to make such a plan effective and the likelihood is remote that the execution of the plan will be blocked by other parties; or (b) a plan for liquidation is being imposed by other forces (e.g., involuntary bankruptcy). In cases where a plan for liquidation was specified in the organization's governing documents at inception (e.g., limited-life entities), the organization should apply the liquidation basis of accounting only if the approved plan for liquidation differs from the plan for liquidation that was specified in the organization's governing documents. This ASU is effective for interim and annual reporting periods beginning after December 15, 2013, with early adoption permitted. The adoption of this standard is not expected to have an impact on the Company's (consolidated) financial position and results of operations.

During the period ended December 31, 2012, the FASB has issued Accounting Standards Update (ASU) No. 2013-04, Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date. ASU 2013-04 provides guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this ASU is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. The guidance requires an entity to measure those obligations as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. The amendments in this ASU are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. For nonpublic entities, the amendments are effective for fiscal years ending after December 15, 2014, and interim periods and annual periods thereafter. The adoption of this standard is not expected to have a material impact on the Company's (consolidated) financial position and results of operations.
 
 
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In September 2011, the FASB issued Accounting Standard Update (“ASU”) No. 2011-08, Intangible – Goodwill and Other (Topic 350), Testing Goodwill for Impairment. Under the amendments of this ASU, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. However, if an entity concludes otherwise, then it is required to perform the first step of the two-step impairment test by calculating the fair value of the reporting unit and comparing the fair value with the carrying amount of the reporting unit, as described in paragraph 350-20-35-4. If the carrying amount of a reporting unit exceeds its fair value, then the entity is required to perform the second step of the goodwill impairment test to measure the amount of the impairment loss, if any, as described in paragraph 350-20-35-9. Under the amendments in this Update, an entity has the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. An entity may resume performing the qualitative assessment in any subsequent period. This ASU is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of this ASU did not have a material effect on the Company’s consolidated financial statements.
 
In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220), and Presentation of Comprehensive Income. Under the amendments of this ASU, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. In a single continuous statement, the entity is required to present the components of net income and total net income, the components of other comprehensive income and a total for other comprehensive income, along with the total of comprehensive income in that statement. In the two-statement approach, an entity is required to present components of net income and total net income in the statement of net income. The statement of other comprehensive income should immediately follow the statement of net income and include the components of other comprehensive income and a total for other comprehensive income, along with a total for comprehensive income. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The adoption of this ASU did not have a material effect on the Company’s consolidated financial statements.

Summary of Critical Accounting Policies
 
Consolidation Policy

The Company’s management, in considering accounting policies pertaining to consolidation, has reviewed the relevant authoritative guidance. The Company follows this authoritative, in assessing whether the rights of the non-controlling interests should overcome the presumption of consolidation when a majority voting, or controlling interest in its investee “is a matter of judgment that depends on facts and circumstances.” In applying the circumstances and contractual provisions of the Partnership Agreement, management determines that the non-controlling rights do not, individually or in the aggregate, provide for the non-controlling interest to “effectively participate in significant decisions that would be expected to be made in the ordinary course of business.” The rights of the non-controlling interest are protective in nature. The Company has corrected, pursuant to the Securities Exchange Commission directives, the audited consolidated financial statements for 2010 and 2011, as well as the unaudited quarterly statements for 2011 and 2012, to report the net income or loss and equity attributable to non-controlling interests (NCI), in accordance with ASC 810.

Use of Estimates
 
The preparation of consolidated 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 consolidated 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.
 
 
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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 oil and natural gas properties using the successful efforts method of accounting. Under this method of accounting, only successful exploration drilling costs that directly result in the discovery of proved reserves are capitalized. Unsuccessful exploration drilling 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 natural gas. Items charged to expense generally include geological and geophysical costs. Capitalized costs for producing wells and associated land and other assets are depleted using a Units of Production methodology based on the proved, developed and calculated by well basis by an independent petroleum engineer in accordance with SEC rules.
 
The net capitalized costs of proved oil and natural gas properties are subject to an impairment test which compares the net book value of assets, based on historical cost, to the discounted future cash flow of remaining 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. For the year 2010, the Public Company Accounting Oversight Board investigated and found that the Company made an error in its accounting for impairment charges by improperly using discounted cash flows rather than the undiscounted future net cash flows, resulting in an impairment error of $114,778, which has been corrected and which impact is restated in these consolidated financial statements.
 
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 Accounting Standards Code (“ASC”) 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. 
 
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 natural 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 ASC standard. Proved oil and natural 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.
 
 
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Stock Based Compensation
 
The Company adopted the ASC standard related to stock compensation to account for its warrants and options 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 the Company’s stock. 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
 
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, basic and diluted loss per share are the same for the years ended December 31, 2012 and 2011 as all potentially dilutive common stock equivalents become anti-dilutive in nature.
 
Income Taxes
 
Under the applicable ASC 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. The Company has corrected and restated for the year 2010 and 2011, the previously reported tax benefit provision by applying net realizable valuation principles in accordance with FASB 109, FIN 48, and ASC 740-10.
 
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, 2012 and 2011, 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.
 
 
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Contractual Obligations

The following table summarizes our contractual obligations and commercial commitments as of December 31, 2012:
 
 
 
2013
   
2014
   
2015
   
2016
   
2017
   
Total
 
Capital Leases
    -       -       -       -       -       -  
Operating Leases
  $ 30,000     $ 12,000       -       -       -     $ 42,000  
Purchase Obligations
    -       -       -       -       -       -  
Total
  $ 30,000     $ 12,000       -       -       -     $ 42,000  
 
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
 
Commodity Risk
 
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.
 
Volatility of 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 (MCF) of gas which the Company received for the periods indicated:
 
Three Months Ending
 
Average
Price per
MCF
 
March 31, 2011
 
$
6.49
 
June 30, 2011
 
$
6.51
 
September 30, 2011
 
$
4.84
 
December 31, 2011
 
$
4.68
 
March 31, 2012
 
$
4.52
 
June 30, 2012
 
$
3.51
 
September 30, 2012
 
$
2.97
 
December 31, 2012
 
$
3.03
 
 
Volatility of Oil Prices
 
The following table provides the average price per barrel of oil which the Company received for the periods indicated:
 
Three Months Ending
 
Average
Price per
Barrel
 
March 31, 2012
 
$
92.24
 
June 30, 2012
 
$
90.90
 
September 30, 2012
 
$
81.39
 
December 31, 2012
 
$
83.98
 
 
 
50

 
 
 
Item 8. Consolidated 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 on Form 10-K.
 
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 
See 8K filing on August 9, 2012, item 4.01 Changes to registrant’s certifying accountant and item 9.01 Exhibits. 

Item 9A. Controls and Procedures
 
Evaluation of Disclosure Controls and Procedures
 
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted 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 principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
 
Pursuant to Rule 13a-15(e) under the Exchange Act, the Company carried out an evaluation, with the participation of the Company’s management, including the Company’s Chief Executive Officer (“CEO”) (the Company's principal executive officer), of the effectiveness of the Company’s disclosure controls and procedures (as defined under Rule 13a-15(e) under the Exchange Act) as of December 31, 2012. Based upon that evaluation, our management concluded that our control over financial reporting and related disclosure controls and procedures reflect a material weakness due to the size and nature of our Company.
 
Management’s Report on Internal Control over Financial Reporting
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim consolidated financial statements will not be prevented or detected on a timely basis. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2012. Based on this assessment, management identified the following material weaknesses that have caused management to conclude that, as of December 31, 2012, our disclosure controls and procedures, and our internal control over financial reporting, were not effective at the reasonable assurance level:
 
1.
We do not have sufficient segregation of duties within accounting functions, which is a basic internal control. Due to our size and nature, segregation of all conflicting duties may not always be possible and may not be economically feasible. However, to the extent possible, the initiation of transactions, the custody of assets and the recording of transactions should be performed by separate individuals. Management evaluated the impact of our failure to have segregation of duties on our assessment of our disclosure controls and procedures and has concluded that the control deficiency that resulted represented a material weakness.
 
2.
To address this material weaknesses, management performed additional analyses and other procedures to ensure that the consolidated financial statements included herein fairly present, in all material respects, our financial position, results of operations and cash flows for the periods presented. Accordingly, we believe that the consolidated financial statements included in this report fairly present, in all material respects, our financial condition, results of operations and cash flows for the periods presented.
 
 
51

 
 
3.
During February 2011, we engaged a corporate accountant as CFO (Robert Miranda of Miranda and Associates) who had significant SEC financial reporting and accounting experience. This individual prepared the accounting update for the years ending December 31, 2007, 2008, 2009, and 2010, including preparation of the delinquent quarterly Forms 10Q. This individual also assisted in the preparation of the 2011 quarterly reports for the periods ended March 31, 2011, June 30, 2011, and September 30, 2011, respectively as well as the Form 10K for that period. Mr. Miranda has served as audit committee chairman since April of 2009. The auditor during these reporting periods was Wilson Morgan.
 
4.
During prior reporting years of 2010 and 2011, the Company, due to its small staff size lacked some of the expertise needed for proper SEC reporting, which led to the need for restatement for years 2010 and 2011. The Company has sought to address these deficiencies with the hiring of a full-time Controller with oil and gas and SEC experience effective June 1, 2013, and plans to seek additional public reporting assistance on and as needed basis.
 
This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only our management’s report in this Annual Report.
 
Changes in Internal Controls
 
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:
 
1.
While the Company is still small, we now have a full-time employee serving as the Chief Executive Officer. Moreover, the Board of Directors continues to be proactively involved in the management of the business. Thus, risks associated with adequate segregation of duties have been addressed. Also, the skills and capabilities of the team, as well as ongoing advice and expertise provided by outside advisors gives assurance that our financial reporting is accurate and timely. We have disclosure processes in place to identify transactions and events to be reported, as applicable. Additional internal control enhancements are always taken into consideration and implemented as needed.
 
2.
During February 2011, we engaged a corporate accountant, to serve as CFO (Robert Miranda of Miranda and Associates) who had significant SEC financial reporting and accounting experience. This individual assisted with the accounting update for the years ending December 31, 2007, 2008, 2009, and 2010, including preparation of the delinquent quarterly Forms 10Q. This individual also assisted in the preparation of the 2011 quarterly reports for the periods ended March 31, 2011, June 30, 2011, and September 30, 2011, respectively as well as this Form 10K. Mr. Miranda also was responsible for the selection of Wilson Morgan as auditor.
 
3.
In January of 2012 the Company also hired a full-time CFO (Mr. Mark Biggers), separating that job from the Audit Committee Chair (Robert Miranda). Mr. Biggers, however, left the Company before year end 2012 and in turn leaving the Company without an experienced full-time CFO. Effective January 1, 2013, the Company installed a new accounting system designed for the oil and gas industry, which includes more stringent controls and safeguards of internal data and provide audit trails for transactional research and review.
 
Item 9B. Other Information
 
Change of Officers
 
On April 15, 2013, Vice President of Exploration, Stan Lindsey, is no longer with the Company.

There are no other events required to be disclosed by this Item.
 
 
52

 
 
PART III
 
Item 10. Directors, Executive Officers and Corporate Governance

The following table sets forth information regarding the names, ages (as of March 31, 2013) and positions held by each of our executive officers, followed by biographies describing the business experience of our executive officers for at least the past five years. Our executive officers serve at the discretion of the board of directors.
 
Name
 
Age
 
Positions Held
Kenneth Hill
 
49
 
Director, Chief Executive Officer, and President
David McCall
 
64
 
Director, General Counsel
Robert Grenley
 
56
 
Director
Ronald Zamber
 
53
 
Director
Robert J. Miranda
 
60
 
Director, Chairman
 
Kenneth Hill was appointed CEO in January 2012. Mr. Hill previously served as Victory’s Vice President and Chief Operating Officer from January 2011 to January 2012 and has been a member of the Board of Directors since April 2011. Prior to joining the Company, Mr. Hill held titles of Interim CEO, VP of Operations and VP of Investor Relations for the U.S. subsidiary of a publicly traded oil and natural gas company on the Australian Stock Exchange, AUS TEX Exploration from December 2006 –to November 2010.

Since 2001, Hill through his private company has raised several million dollars of venture capital, personally invested in and consulted for a number of successful entrepreneurial ventures across a variety of industries, including oil and natural gas. Prior to 2001, Hill was employed for 16 years at Dell, Inc. As one of the first 20 employees at Dell he served in variety of management positions including manufacturing, sales, marketing, and business development. Prior to joining Dell, Hill studied Business Management and Business Marketing at Southwest Texas State University (now Texas State University). While at Dell, Mr. Hill continued his education at The University of Texas Graduate School of Business Executive Education program, The Aspen Institute and the Center for Creative Leadership. He is a team builder with a unique set of proven leadership, management and technical skills.
 
David McCall was appointed General Counsel and Director on January 20, 2011. Mr. McCall has over 35 years of experience in the oil and natural gas industry and has been with the law firm The McCall Firm in Austin, Texas for over five years. Mr. McCall’s law practice has centered on the activities of major and independent oil companies. Mr. McCall received a Bachelor of Arts in marketing from McMurry University, Abilene, Texas in 1971. He graduated from Texas Tech School of Law, Lubbock, Texas in 1974. He is a member of the Bar, State of Texas; a Life Fellow, Texas Bar Foundation; and a Founding Fellow, Austin Bar Foundation.

 Robert Grenley was appointed Director on June 1, 2010. Since May, 2007, Mr. Grenley is Chief Financial Officer of Ambient, Inc. a 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.

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 J. Miranda, CPA was appointed as our Chief Financial Officer (CFO) 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. On January 10, 2012, Mr. Miranda stepped down as CFO with the appointment of Mark Biggers to that position. On January 17, 2012, Mr. Miranda stepped down as President and CEO of the company and remains Chairman of the Board and a Director, at which time Kenneth Hill was appointed as 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.
 
 
53

 
 
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.
 
Corporate Governance and Board Composition
 
Our business and affairs are organized under the direction of our board of directors, which currently consists of five (5) 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. Our board of directors met 3 times during the year ended December 31, 2012.
 
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.
 
The Company maintains Directors and Officers insurance on behalf of if officers and directors.
 
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. Kenneth Hill, 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.
 
 
54

 

Compliance with Section 16(a) of the Exchange Act:
 
Under the securities laws of the United States, the Company's 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 2012 fiscal year.
 
To the best of our knowledge, the number of late reports for Kenneth Hill was 1.
 
To the best of our knowledge, the number of late reports for David McCall was 1.
 
To the best of our knowledge, the number of late reports for Robert Grenley was 1.
 
To the best of our knowledge, the number of late reports for Ron Zamber was 1.
 
To the best of our knowledge, the number of late reports for Robert Miranda was 1.
 
Code of Ethics
 
We have prepared and 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 during the year ended December 31, 2012.
 
Item 11. Executive Compensation
 
The following table sets forth the total compensation awarded to, earned by, or paid to our principal executive officers, and our other named executive officers for all services rendered in all capacities to us in 2012 and 2011.
 
Name and Principal
 
 
 
Salary
   
Bonus
   
Stock
Awards
   
Warrant/
Option Awards
   
Non-Equity Incentive Plan Compensation
   
Nonqualified Deferred Compensation
   
All Other Compensation
   
Total
 
Position
 
Year
 
($)
   
($)
   
($)
   
($)
   
($)
   
($)
   
($)
   
($)
 
                                                     
Kenneth Hill
 
 
 
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
 
President and CEO
 
2012
    180,000       -       -       55,260       -       -       -       235,260  
VP and COO
 
2011
    180,000       -       -       86,100       -       -       -       266,100  
                                                                     
Mark Biggers (1)
 
 
                                                               
Chief Financial Officer
 
2012
    220,000       -       -       96,922       -       -       -       316,922  
 
 
2011
    -       -       -       -       -       -       -       -  
                                                                     
Stanley Lindsey (2)
 
 
                                                               
VP of Exploration and Development
 
2012
    180,000       -       -       59,512       -       -       -       239,512  
VP of Exploration and Development
 
2011
    180,000       -       -       54,000       -       -       -       234,000  
                                                                     
Robert J. Miranda