VICTORY OILFIELD TECH, INC. - FORM 10-K

Attached files

file	filename
EX-21.1 - EXHIBIT 21.1 - VICTORY OILFIELD TECH, INC.	exhibit211.htm
EX-23.2 - EXHIBIT 23.2 - VICTORY OILFIELD TECH, INC.	vyey_ex233.htm
EX-32.1 - EXHIBIT 32.1 - VICTORY OILFIELD TECH, INC.	vyey_ex3211.htm
EX-31.1 - EXHIBIT 31.1 - VICTORY OILFIELD TECH, INC.	vyey_ex3112.htm
EX-31.2 - EXHIBIT 31.2 - VICTORY OILFIELD TECH, INC.	vyey_ex3122.htm
EX-23.1 - EXHIBIT 23.1 - VICTORY OILFIELD TECH, INC.	vyey_ex2321.htm
EX-99.1 - EXHIBIT 99.1 - VICTORY OILFIELD TECH, INC.	aurora2015secreport.htm
EX-4.1 - EXHIBIT 4.1 - VICTORY OILFIELD TECH, INC.	khillstockcetificate.htm
EX-3.1 - EXHIBIT 3.1 - VICTORY OILFIELD TECH, INC.	victoryenergycorporation.htm
EX-10.22 - EXHIBIT 10.22 - VICTORY OILFIELD TECH, INC.	kennyhillemploymentcontrac.htm
EXCEL - IDEA: XBRL DOCUMENT - VICTORY OILFIELD TECH, INC.	Financial_Report.xls
EX-32.2 - EXHIBIT 32.2 - VICTORY OILFIELD TECH, INC.	vyey_ex3221.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K



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

For the fiscal year ended December 31, 2014



¨	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 ý

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 ý

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 ý No o

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

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

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	ý
(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 ý

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 30, 2014 was approximately $6,147,833 based on the closing price of such stock and such date of $.32.

The number of shares outstanding of the Registrant’s common stock, $0.001 par value, as of March 31, 2015 was 29,202,826.

VICTORY ENERGY CORPORATION

ANNUAL REPORT ON

FORM 10-K

FOR THE YEAR ENDED December 31, 2014

TABLE OF CONTENTS

Table of Contents



PART I

Item 1.	Business	4

Item1A.	Risk Factors	14

Item 1B.	Unresolved Staff Comments	22

Item 2.	Properties	22

Item 3.	Legal Proceedings	28

Item 4.	Mine Safety Disclosure	29

PART II

Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30

Item 6.	Selected Financial Data	31

Item 7.	Management Discussion and Analysis of Financial Condition and Results of Operations	31

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	37

Item 8.	Consolidated financial statements and Supplementary Data	38

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	38

Item 9A.	Controls and Procedures	38

Item 9B.	Other Information	39

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	40

Item 11.	Executive Compensation	43

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	46

Item 13.	Certain Relationships and Related Transactions, and Director Independence	48

Item 14.	Principal Accounting Fees and Services	48

PART IV

Item 15.	Exhibits, Financial Statement Schedules	49

SIGNATURES		53

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		F-1

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 on Form 10-K other than statements of historical fact, including statements that address operating performance, events or developments that management expects or anticipates will or may occur in the future, including statements related to revenues, cash flow, profitability, adequacy of funds from operations, statements expressing general optimism about future operating results and non-historical information, are forward looking statements. In particular, the words “believe,” “expect,” “intend,” “anticipate,” “estimate,” “may,” “will,” variations of such words, and similar expressions identify forward-looking statements, but are not the exclusive means of identifying such statements and their absence does not mean that the statement is not forward-looking.

Readers should not place undue reliance on these forward-looking statements, which are based on management’s current expectations and projections about future events, are not guarantees of future performance, are subject to risks, uncertainties and assumptions and apply only as of the date of this report. 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;

· investors 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;

· the results of pending litigation; and

· state regulatory policies regarding spacing of wells and units.

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 common stock par value $0.001 per share ("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.

The terms "Victory", "Company", "we", our", and "us" refer to Victory Energy Corporation and its consolidated subsidiaries unless the context suggests otherwise.

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 Second Amended Partnership Agreement of Aurora (" Aurora Partnership Agreement") gives Victory Energy Corporation control of Aurora. Article XI of the Aurora 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 a publicly held, independent, growth-oriented exploration and production company, headquartered in Austin, Texas, with additional technical and specialized resources located in Midland, Texas. The company is focused on creating shareholder value by rapidly growing conventional oil and liquids-rich natural gas reserves and cash-flow via continued low-risk vertical well development on existing properties, as well as through the acquisition of new resource properties. This focus on returns is achieved by targeting the predictable resources plays, favorable operating environment, and consistent reservoir quality across multiple target horizons, long-lived reserve characteristics, and high drilling success rates of the Permian Basin of Texas and southeast New Mexico.

Victory Energy has carefully assembled a management team with more than 130 years of direct and relevant oil and gas experience. The Company also utilizes a team of third-party professionals on an as-needed basis. This team includes geologists for prospect evaluation and assessment and reservoir engineering resources for the analysis of current and new properties. Reserve reporting is performed by a third-party engineer located in Midland, Texas. Each independent operator utilized by the company also has their own array of experts tailored for the specific formations and well completion techniques of each property the company holds an interest in. The Company strategically utilizes both internal capabilities and strategic industry relationships to acquire non-operated, high-grade working interest positions in predictable, low-to-moderate risk oil and gas prospects.

The Company is traded under the ticker symbol VYEY on the OTCQX , operated by OTC Markets Group.

The Company is one of two partners in Aurora which was established in January 2008. The second partner in Aurora is the Navitus Energy Group ("Navitus"), also a Texas general partnership. The Company and Navitus work together to increase proved reserves and the valuation of Aurora, with a future goal of consolidating the two partners into a single entity and moving to a larger stock exchange such as the NYSE or NASDAQ.

Navitus is currently utilizing a private placement memorandum to raise up to $15 million of capital for the Aurora partnership. Capital from this private placement is generally focused on acquiring and developing targeted oil and gas opportunities that are available to the company through a variety of industry sources. The Navitus private placement is offered to accredited investors and provides these investors with a 10% preferred return distribution 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. Under the agreement, separation of the partners is not mandatory and Victory may raise funds from other sources. All producing oil and natural gas assets are held in the Aurora partnership during the five year term of the Aurora Partnership Agreement which ends in October 2017. As of December 31, 2014, Navitus has contributed $4.4 million dollars into Aurora.

As of March 31, 2015, the Company had 26 wells on production. The Company’s portfolio of producing assets now includes the following properties: the Fairway property, the Bootleg Canyon Ellenberger Field, the Adams-Baggett Gas Field, the Morgan property, the Uno-Mas property and the Clear Water Wolfberry resource property. 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 Permian Basin of Texas and New Mexico.

As the Company continues to evaluate 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. Due to the precipitous downturn in oil prices in the later part of 2014, the Company is concentrating its efforts on attractive acquisitions of proved producing properties, as well as the proposed business combination Lucas Energy Inc. ("Lucas") announced on February 4, 2015.

The Company’s capital and exploration expenditures totaled $1,293,356 and property acquisitions totaled $3,397,122, for the year ended December 31, 2014. At December 31, 2014, the Company had $2,941 of cash on hand with $800,000 outstanding under its credit facility with Texas Capital Bank, National Association. The credit facility was classified as currently payable due to the failure to meet the current ratio covenant set forth in the credit facility at December 31, 2014. This requirement was met as of February 28, 2015.

Navitus contributed $1,140,000 in cash to Aurora for the year ended December 31, 2014, and $2,336,000 for the year ended December 31, 2013. Distributions to Navitus totaled $647,421 for the year ended December 31, 2014. The Company anticipates that Navitus will make additional contributions to Aurora as the portfolios of properties are developed and or acquisitions are made.

Proposed Business Combination

On February 4, 2015, Victory Energy Corporation entered into a letter of intent relating to a proposed business combination with Lucas ("the Combination"). The Combination is nonbinding, subject to among other things, the parties completing due diligence, the mutual negotiation of definitive documents, regulatory approvals and the registration of the securities to be issued to the shareholders of the combined company resulting from the Combination (the “Combined Company”).

On February 26, 2015, Victory Energy Corporation entered into (a) the Pre-Merger Collaboration Agreement (the “Collaboration Agreement”) by and among Victory, Lucas, Aurora, Navitus, and AEP Assets, LLC, a wholly-owned subsidiary of Aurora (“AEP”); and (b) the Pre-Merger Loan and Funding Agreement between Victory and Lucas (the “Loan Agreement”). Subsequently the parties entered into Amendment No. 1 to the Pre-Merger Collaboration Agreement on March 3, 2015 (the “First Amendment to Collaboration Agreement”), which amendments affected thereby are included in the discussion of the Collaboration Agreement below.

Pursuant to the Pre-Merger Loan and Funding Agreement, Victory agreed to loan Lucas up to $2 million, with $250,000 initially loaned on February 26, 2015 (the "Initial Draw"). Pursuant to the Collaboration Agreement, Lucas agreed to assign to the Company all of Lucas' rights and interests in five (5) Penn Virginia wells that are scheduled to be funded February through March 2015 and go into production in April 2015 and two (2) Earthstone Energy/Oak Valley Resources wells that are scheduled to be funded on or before April 1, 2015 and begin production in June or July of 2015. These seven (7) wells are located in Karnes, Lavaca and Gonzales Counties, Texas. Immediately upon the funding, Lucas is required to assign certain wellbore rights to Victory, and upon complete payment and satisfaction of the certain financial requirements described in the Collaboration Agreement (the “Well Funding Requirements”), Victory shall assign the Well Rights to Aurora, and Aurora is required to assign certain wellbore rights to AEP. On March 2, 2015, payments of $195,928 and $317,027 were made by Aurora , on behalf AEP, to Earthstone Energy/Oak Valley Resources and Penn Virginia, respectively, pursuant to the Pre-Merger Collaboration Agreement.

If the Combination is consummated, then AEP shall become a direct or indirect subsidiary of the Combined Company. If the letter of intent is terminated and/or if a subsequent definitive agreement is entered into and thereafter terminated such that the Combination does not occur, then AEP shall retain ownership of the Well Rights and Lucas shall have no claim whatsoever to the Well Rights.

maturity. The maturity date of the Draw Note is February 26, 2016 and Lucas has the right to pre-pay any amounts owed under the Draw Note at any time with ten days prior written notice to the Victory. Upon the occurrence of the event of default specified in the Draw Note, the interest rate increases by 5% per annum, Victory can declare the entire outstanding balance of the Draw Note immediately due and payable, and can further take actions to enforce its security interests in the Pledged Shares (as defined below).

Amounts owed under the Draw Note are secured by the pledge of shares of the Lucas’ common stock pursuant to the terms of a Pledge Agreement between Lucas and Victory (the “Pledge Agreement”). Shares pledged pursuant to the Pledge Agreement are to be issued from Lucas’ treasury in the name of Lucas and held by the Company to secure the repayment of the Draw Note. The number of shares required to be pledged by Lucas from time to time under the Pledge Agreement is equal to the amount of each draw under the Pre-Merger Loan and Funding Agreement divided by the volume weighted average closing stock price of Lucas’ common stock (the “VWAP”) on the twenty trading days prior to the closing date of each such draw. Based on the VWAP for the twenty trading days prior to the date of the Initial Draw, Lucas was required to pledge 1,100,655 shares of its common stock to Victory (the “Pledged Shares”) to secure the repayment of the $250,000 Initial Draw. Amounts owed under the Draw Note are also required to be guaranteed by any subsidiaries Lucas forms or acquires in the future pursuant to the terms of a Subsidiary Guaranty, provided that as of the date of this filing Lucas does not have any subsidiaries. The Pledged Shares constitute treasury shares and unless and until there is a default under the Loan Agreement or the Draw Note or a failure to satisfy any other obligation thereunder, the Pledged Shares may not be voted by Victory or Lucas.

Borrowings under the Pre-Merger Loan and Funding Agreement are at the discretion of Lucas, provided that the total number of shares of common stock of Lucas issuable as collateral under the Pledge Agreement may not exceed 19.9% of the total number of outstanding shares of the Lucas’ common stock as of February 26, 2015, unless the Lucas receives shareholder approval consistent with the rules of the NYSE MKT. Notwithstanding the above, the Loan Agreement requires Lucas and Victory to operate in accordance with a mutually agreed 12 month budget (the “Budget”), which governs the timing and use of amounts borrowed under the Loan Agreement. The Budget is intended to prioritize the payment of expenses in a manner designed to ensure that the Combination is consummated. The Budget governs the utilization of Lucas’ cash and credit during the period prior to the consummation of the Combination and provides a monthly breakdown of expenses and uses of cash and credit available to Lucas. Lucas is not allowed to use any of its cash or credit to make payments to any third parties except in accordance with the Budget.

Separately from the pledge requirements described above, the Draw Note provides that upon maturity, Lucas may pay such Draw Note in cash or in kind, by the issuance of shares of Lucas’ common stock based on the VWAP for the twenty trading days prior to the maturity date, provided that Lucas is then required to register such shares with the Securities and Exchange Commission within sixty days of the maturity date. Additionally, the Draw Note and all obligations thereunder will become intercompany obligations of the Combined Company and forgiven if the Combination is consummated.

The Collaboration Agreement also required Victory to provide Louise H. Rogers, Lucas’ senior lender, a Contingent Promissory Note in the amount of $250,000, which accrues interest at the rate of 18% per annum. The Contingent Promissory Note is due and payable within ninety days following the earlier of (a) the date the letter of intent is terminated, or if a subsequent definitive agreement is entered into and thereafter terminated such that the Combination does not occur, the date ninety days from the termination date of such definitive agreement, or (b) the failure of AEP to satisfy the Well Funding Requirements, which failure is not cured within sixty (60) days of AEP receiving written notice from Lucas of such failure. In connection with the issuance of the Contingent Promissory Note, the lender agreed to release certain wellbore rights from its security interest in order to accommodate the transactions contemplated by the Collaboration Agreement and Loan Agreement.

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. Many of our competitors are large, well-established companies that have been engaged in the oil and natural gas business for much longer than we have and

possess substantially larger operating staffs and greater capital resources than we do. We compete by leveraging our experience and hands on knowledge of the marketplace of available properties for sale and/or development.

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 business is subject to federal, state and local laws, regulations, and other legal requirements enacted by governmental authorities, including regulations related to the operation of wells, pricing and terms for access to pipeline transportation, and environmental matters. 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

The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the Natural Gas Act of 1938 ("NGA") and the Natural Gas Policy Act of 1978. The statutes are administered by the Federal Energy Regulatory Commission ("FERC"). Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas prices for all “first sales” of natural gas, which includes all sales by the Company of its own production. All other sales subject to a blanket sales certificate under the NGA, which has flexible terms and conditions. Consequently, all of the Company’s sales of natural gas currently may be made at market prices, subject to applicable contract provisions. The Company’s jurisdictional sales, however, are subject to the future possibility of greater federal oversight, including the possibility that the FERC might prospectively impose more restrictive conditions on such sales. Conversely, sales of crude oil and condensate and natural gas liquids by the Company are made at unregulated market prices.

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.

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.

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 believe that we are 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 canceled 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 canceled. Any such cancellation could have a material adverse effect on our financial condition, cash flows and results of operations.

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 U.S. Environmental Protection Agency (the "US EPA"). 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.

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(“CERCLA”), also known as the “Superfund” law, imposes joint and several liabilities, without regard to fault or the legality of the original conduct of certain persons with respect to the release or threatened release of a “hazardous substance” into the environment. 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 Ac( “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 (“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.

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 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.

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 forgo 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( “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 four full-time employees as of 2015. 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.

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.

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.

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).

MMcf. Million cubic feet.

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.

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:

Risks Related to Our Business, Industry, and Strategy

Oil and gas prices are volatile and oil prices have been significantly depressed since the end of 2014. 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 natural gas have been volatile, and those markets are likely to continue to be volatile in the future. Starting in the second half of 2014, the NYMEX price for a barrel of oil has fallen sharply. In addition, NYMEX prices for natural gas have been low compared with historical prices. Extended periods of low prices for oil or natural gas will have a material adverse effect on us, including the following possible negative effects:


•	our cash flow will be reduced, which will decrease funds available for capital investments employed to replace reserves;


•	certain reserves will no longer be economic to produce, resulting in lower proved reserves and cash flow and charges to earnings that impair the value of these assets; and


•	access to other sources of capital, such as bank loans and equity or debt markets, could be severely limited or unavailable.

It is impossible to predict future oil and natural 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.

If oil and gas prices remain depressed for extended periods of time, we may be required to take write-downs of the carrying values of our oil and natural gas properties, which could 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.

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.

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.

From time to time legislative proposals are made that would, if enacted, make significant changes to U.S. tax laws. These proposed changes have included, among others, eliminating the immediate deduction for intangible drilling and development costs, eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development, repealing the percentage depletion allowance for oil and natural gas properties and extending the amortization period for certain geological and geophysical expenditures. Such proposed changes in the U.S. tax laws, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and natural gas exploration and development, could adversely affect our business, financial condition, 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.

On July 21, 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Reform Act, which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation required the Commodities Futures Trading Commission, or the CFTC, and the SEC to promulgate rules and regulations implementing the new legislation, which they have done since late 2010. The CFTC has introduced dozens of proposed rules coming out of the Dodd-Frank Reform Act, and has promulgated numerous final rules based on those proposals. The effect of the proposed rules and any additional regulations on our business is not yet entirely clear, but it is increasingly clear that the costs of derivatives-based hedging for commodities will likely increase for all market participants. Of particular concern, the Dodd-Frank Reform Act does not explicitly exempt end users from the requirements to post margin in connection with hedging activities. While several senators have indicated that it was not the intent of the Act to require margin from end users, the exemption is not in the Act. While rules proposed by the CFTC and federal banking regulators appear to allow for non-cash collateral and certain exemptions from margin for end users, the rules are not final and uncertainty remains. The full range of new Dodd-Frank requirements to be enacted, to the extent applicable to us or our derivatives counterparties, may result in increased costs and cash collateral requirements for the types of derivative instruments we use to mitigate and otherwise manage our financial and commercial risks related to fluctuations in oil and natural gas prices. In addition, final rules were promulgated by the CFTC imposing federally-mandated position limits covering a wide range of derivatives positions, including non-exchange traded bilateral swaps related to commodities including oil and natural gas. These position limit rules were vacated by a Federal court in September 2012, and the CFTC has appealed that decision and could re-promulgate the rules in a manner that addresses the defects identified by the court. If these position limits rules go into effect in the future, they are likely to increase regulatory monitoring and compliance costs for all market participants, even where a given trading entity is not in danger of breaching position limits. These and other regulatory developments stemming from the Dodd-Frank Reform Act, including stringent new reporting requirements for derivatives positions and detailed criteria that must be satisfied to continue to enter into uncleared swap transactions, could have a material impact on our derivatives trading and hedging activities in the form of increased transaction costs and compliance responsibilities. Any of the foregoing consequences could have a material adverse effect on our financial position, results of operations and cash flows.

The borrowing base under our bank credit facility may be reduced below the amount of borrowings outstanding under such facility.

Under the terms of our bank credit facility, our borrowing base is subject to redeterminations at least semi-annually based in part on prevailing oil and gas prices. A negative adjustment could occur if the estimates of future prices used by the bank in calculating the borrowing base are significantly lower than those used in the last redetermination. The next redetermination of our borrowing base is scheduled to occur by March 31, 2015. In addition, the portion of our borrowing base made available to us is subject to the terms and covenants of the bank credit facility including, without limitation, compliance with the ratios and other financial covenants of such facility. In the event the amount outstanding under our bank credit facility exceeds the redetermined borrowing base, we could be forced to repay a portion of our borrowings. We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell a portion of our assets.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

Our bank credit facility contains a number of significant covenants that, among other things, restrict or limit our ability to:



	pay dividends or distributions on our capital stock or issue stock;



	repurchase, redeem or retire our capital stock;



	make certain loans and investments;



	sell assets;



	enter into certain transactions with affiliates;



	create or assume certain liens on our assets;



	enter into sale and leaseback transactions; or



	merge or to enter into other business combination transactions.

Also, our bank credit facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our bank credit facility impose on us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our bank credit facility. A default, if not cured or waived, could result in all indebtedness outstanding under our bank credit facility to become immediately due and payable. If that should occur, we may not be able to pay all such debt or borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. If we were unable to repay those amounts, the lenders could accelerate the maturity of the debt or proceed against any collateral granted to them to secure such defaulted debt.

We are exposed to the credit risk of our customers and other counterparties, and a general increase in the nonperformance by counterparties could have an adverse impact on our cash flows, results of operations and financial condition.

We are subject to risks of loss resulting from nonperformance by our counterparties, such as Lucas under the Pre-Merger Loan and Funding Agreement. Any deterioration in the financial health of Lucas or any of our future counterparties or any factors causing reduced access to capital for them may result in the reduction in their ability to pay or otherwise perform on their obligations to us. Any increase in the nonperformance by Lucas or any of our counterparties, either as a result of recent changes in financial and economic conditions or otherwise, could have an adverse impact on our operating results and could adversely affect our liquidity.

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 analyzes, 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.

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.

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, could negatively impact our results of operations for the period in which the impairment is recognized.

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.

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

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent that successful exploration and development activities are conducted on properties we own or we acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future oil and natural 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 natural 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.

We are a non-operator with respect to our natural gas and oil properties. Consequently, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of leasehold acquisition, drilling and development activities therefore will depend upon a number of factors outside of our control, including:


•	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 natural 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.

As a result of any of the above or other failure of the operator to act in ways that are in our best interest, our results of operations could be adversely affected.

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

In acquiring producing properties we assess the recoverable reserves, future oil and natural 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.

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 own properties 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.

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 currently do not and in the future 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.

Risks Related to Our Common Stock

We continue to incur operating losses and additional losses in the future which may adversely affect our business, financial condition and cash flows.

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 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 may be 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.

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 their primary residence and mortgage debt on their 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, 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.

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.

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 or may become party to legal proceedings that are considered to be either ordinary or routine litigation incidental to our business or not material to our financial position or results of operations. We also are or may become party to legal proceedings with the potential to be material to our financial position or results of operations.

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.

Item 2. Properties

Office Space Leases.

Our executive office space lease is month to month and is for approximately 1,200 square feet at 3355 Bee Caves Road, Suite 608, Austin, TX 78746. The monthly lease cost is $2,375.

Portfolio.

As of December 31, 2014, the Company, through Aurora had 26 gross and 9 net wells, in production. The Company’s portfolio of producing assets now includes the Fairway property, the Bootleg Canyon Ellenberger Field, the Adams-Baggett Gas Field, the Chapman Ranch, the Morgan Property, and the Clear Water Wolfberry Resource Play.

Proved commercial accumulations of hydrocarbons now occur in multiple target zones at depths ranging from 4,700 to 13,100 feet, with the majority of proved reserves being located on properties in the 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 Lightnin' Property, Glascock County, Texas

On June 5, 2014, Victory, through its controlling interest and as managing partner in Aurora , sold certain leasehold properties and all of Aurora’s related interests in approximately 640 gross and 128 net mineral acres located in Glascock County, Texas (the “Lightnin Assets”) to an unrelated third party (the “Lightnin' Buyer”) for approximately $4 million in cash gross to Aurora. The sale was made pursuant to a Purchase and Sale Agreement dated as of April 30, 2014 by and among the working interest owner/sellers, including Aurora, and the Lightnin' Buyer. The effective date for the transaction was April 1, 2014. Aurora held a 20% working and 15% net revenue interest in the Lightnin' Assets which were operated by a third party. Estimated daily net production to Aurora's interest was approximately 36 BOEPD (barrels of oil equivalent per day) at the time of the sale from the 3 producing wells. The Company recognized a gain on the sale of the Lightnin' Assets of $2,160,099 in its consolidated statement of operations as of December 31, 2014.

The Bootleg Canyon Property, Pecos County, Texas

Acquired in 2011, this 4,000+ acre lease is located in Pecos County, Texas. There are now two producing Ellenberger oil wells and one producing Connell gas well on this 3D seismic-controlled property. A third-party SEC reservoir report allocates a gross EUR for each Ellenberger oil well at 186 MBO (100% oil). Gross reserves for the gas well are 201 MMcf.

During the year ended December 31, 2014, gross production for the two oil wells (University 6 #1 and #2) was just over 51 MBO.

The gas well (University 7 #1) spud on December 23, 2012 and went into completion on March 6, 2013. During the year ended December 31, 2014, total net Mcf is 2,218 (3.75% working interest). Gross production was 59,158 Mcf, or 164 Mcf per day.

The operator of the Bootleg Canyon Property wells currently believes the University 6 #1 and 6 #2 are subject to water drive, and as a result, has restricted the flow of hydrocarbons to avoid excess water production.

The two completed oil wells and the one proved undeveloped oil well represent approximately $1.1 million of future undiscounted cash flow to the partnership. The acreage held currently provides 160 acre spacing between wells and thus an opportunity to drill additional wells on the prospect acreage. It’s estimated there may be ten total well locations on the property. The Company, through its interest in Aurora, holds a 5 % working interest and a 3.75 % net revenue interest.

Development capital required for the remaining ten well locations is estimated to be $870,650.

The Adams-Baggett Property, Crockett County, Texas

The Company, via its partnership interest in Aurora, received its first production revenue from this field in March of 2008 and continues to receive income today. Canyon sandstones are the primary hydrocarbon target within this prospect and they form a prolific low-permeability gas play located in the Val Verde Basin of Southwest Texas. Natural gas from the Canyon Sandstone generally receives a premium in price above the standard market price for natural gas due to its higher BTU content per cubic foot. In addition, each of the Adams-Baggett wells have historically displayed an established, well behaved decline trend of 4.5% per year.

The Canyon Sandstone gas play is part of the large Adams-Baggett Canyon Sandstone gas field. The Canyon Sandstone formation is found at a depth of 4,300 feet to 4,900 feet. The average life span of a Canyon Sandstone gas well is approximately 30 years. Gross reserves for the Adams-Baggett property are estimated at 850 MMcf, which represents upwards of $1.3 million in future undiscounted cash flows to the Company.

Aurora Energy Partners holds a working interest in nine wells; 100% WI and a 75% NRI in seven wells and a 50% WI with 38% NRI in two wells in the Adams-Baggett property.

Fairway, Howard County, Texas

On June 30, 2014, Aurora completed the initial closing (the “First Closing”) of a purchase of a 10% working and 7.5% net revenue interest in the proved and unproved Permian Basin Fairway Operations from Target Energy Limited (“TELA”) for an initial payment of $2,491,888 in cash, subject to customary purchase price adjustments ( the "Fairway Acquisition"), pursuant to the terms and conditions of the Purchase and Sale Agreement dated June 30, 2014 between Aurora and TELA (the "Fairway PSA"). On the First Closing, TELA assigned certain assets in its Permian Basin Fairway Operation (the “First Closing Assets”) to Aurora. The second closing (the “Second Closing”) was planned to follow the completion of curative title work and was expected in August 2014. On the Second Closing,TELA was to assign the remainder of its assets in its Permian Basin Fairway Operations to Aurora. The Effective Date for the transfer of all assets was May 1, 2014. The acquisition of the First Closing Assets included 7 producing wells and 4 wells completed and awaiting production start-up.

The acquisition of the First Closing Assets included seven producing wells and four wells completed and awaiting production start-up. On September 23, 2014, the Company mutually agreed to the termination of the Fairway PSA. Pursuant to the termination of the Fairway PSA, the Second Closing did not occur as the result of certain title impairment issues that were uncovered during the due diligence process and that were not remedied to the satisfaction of the Company and TELA. No penalties or payments were due as a result of the termination of the Fairway PSA.

On January 9, 2015, Aurora was named in a lawsuit in Howard County, Texas by the operator of the Company’s Fairway assets acquired the Fairway Acquisition, for failure to pay certain costs associated with wells, for which AEP considers themselves in a non-consent status regarding the drilling and completion costs. Discussions are under way in an attempt to settle this matter. The Company does not expect to be required to pay additional costs related to these assets. The related payable of $637,248 is included in the Company’s accounts payable as of December 31, 2014.

On January 31, 2015, Aurora was named in a lawsuit in Harris County, Texas by TELAfor failure to pay certain charges related to costs of undeveloped properties related to the Fairway Acquisition. The Company is in the process of answering the petition claims and considering counter claims related to the provisions of the TELA PSA. The Company does not expect to be required to pay additional costs related to these assets. The related payable of $182,250 is included in the Company’s accounts payable as of December 31, 2014.

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 the acquisition this property contained 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

The Company through its interest in Aurora acquired this prospect in April 2012. The prospect is located in south central Nueces County, Texas. The prospect wells are a conventional drilling play targeting the Frio Sands formation.

The first well was drilled and completed in July 2012. Multiple pay zones were present in the well-logs; however oil and gas production from the target formation was not of a commercial quantity. A second well location is up-dip of the first well site and is in a different fault block.

This second well, the Chapman 4501, spud on December 22, 2013 and reached total depth of 7,800 feet on January 7, 2014. The well was perforated in several sections and was successfully flow tested from the Frio Sands on January 21, 2014 at 67 barrels of oil and 10 Mcf of dry gas per day. During the year ended December 31, 2014, the well produced 5,453 gross barrels of oil and 2,830 gross Mcf of natural gas.

On February 10th, 2015, the Company received a recommendation from the operator to plug and abandon the Chapman 4501, citing high recompletion costs and poor reservoir behavior. The Company concurred with the operator's proposal and agreed to bear the prorata share of the plugging and surface reclamation expenses.

The Company through its interest in Aurora holds a 5 % working interest and a 3.75 % net revenue interest.

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, 2014. “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	100.00	%	140.0	140.0	0.0	0.0	140.0	140.0
Adams-Baggett Ranch	50.00	%	20.0	10.0	0.0	0.0	20.0	10.0
The Fairway Prospect	10.00	%	240.0	24.0	560.0	56.0	800.0	80.0
Bootleg Prospect	5.00	%	480.0	24.0	4164.7	198.2	4644.7	222.2
Saddle Butte Prospect	3.00	%	0.0	0.0	2560.0	76.8	2560.0	76.8
The Uno-Mas Property	10.00	%	160.0	16.0	160.0	2.0	320.0	18.0
The Morgan Property	3.00	%	40.0	1.2	40.0	1.2	80.0	2.4
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	1120.0	48.0	1200.0	51.2
Clearwater Wolfberry	1.50	%	160.0	2.4	2082.0	29.1	2242.0	31.5
Royalty Interest Acreage	—	%	0.0	0.0	944.0	3.5	944.0	3.5
Total Acreage			1,400	224.8	11,870.7	426.8	13,270.7	651.6

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, specifically our CEO.

Estimates of our reserves were outsourced to Cambrian Management and prepared by their independent reserve engineer, Mr. James Nicholson, who specializes in preparing reservoir studies, reserve estimates, and property evaluations. Mr. Nicholson, 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 and gas operations professional have reviewed and approved the reserve report which is filed as an exhibit to this Annual Report on Form 10-K.

At December 31, 2014, the Company’s proved developed reserves accounted for 94% of total reserves. 17% of the total reserves are attributable to oil, while 83% are attributable to natural gas and other liquids. The following table sets forth our estimated proved oil and natural gas reserves for the 26 wells and the PV-10 of such reserves as of December 31, 2014 and 2013.



Total Estimated Proved Reserves	2014			2013
Proved Developed Reserves
Oil (Mbbl)	13.64			32.38
Gas (Mmcf)	598.14			702.15
Total proved developed reserves (Mboe)	113.33			149.41
Proved Undeveloped Reserves
Oil (Mbbl)	7.02			16.64
Gas (Mmcf)	1.79			21.05
Total proved undeveloped reserves (Mboe)	7.32			20.15
Total Proved Reserves (Mboe)	120.65			169.56
% Oil	17.12		%	28.91		%
% Proved Developed	93.93		%	88.12		%
PV- 10% (in thousands)	$	1,464.57		$	2,422.10

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 %. 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, 2013 and 2012 for the Company:



	December 31,
	2014		2013
	(In Thousands)
PV-10	$	1,464.6	$	2,422.1
Present value of future income taxes discounted at 10%	500.6		823.5
Standardized Measure of discounted future net cash flows	$	964.0	$	1,598.6

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, 2014 and 2013 for the Company:



	December 31,
	2014		2013
	(In Thousands)
Undiscounted future net revenues	$	2,688.0	$	4,230.8
Present value of net revenues:
Before income tax (PV-10)	$	1,464.6	$	2,422.1
After income tax (Standardized Measure)	$	964.0	$	1,598.6

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, 2014 and 2013 for the Company.

A gross total of five producing wells were added to the Company's portfolio during the year ended December 31, 2014. The change in producing wells reflects the sale of the Lightnin' Prospect and the acquisition of the Fairway properties.



	December 31,
	2014		2013
	Gross	Net	Gross	Net
Natural Gas	11	8.1	10	8.1
Oil	15	0.9	11	0.4
Totals	26	9	21	8.5

Technologies Used in Establishing Proved Reserves in 2014 and 2013

Our proved reserves in 2014 and 2013 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, 2014 and 2013, our proved undeveloped reserves included 1 prospect (University 6 #3) and 2 prospects (the Cotter 6 #2 and the University 6 #3), respectively. As we are not the operator of these properties, we cannot predict the timing of the development of the properties.

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 for the Company:



	Years Ended December 31,
	2014		2013		2012
Production:
Oil (Bbls)	6,509		5,810		1,659
Natural gas (Mcf)	45,577		44,833		61,582
BOE	14,106		13,282		11,923
Average sales prices:
Oil (per Bbl)	$	71.16	$	84.81	$	83.98
Natural gas (per Mcf)	$	5.09	$	5.35	$	4.55
BOE	$	49.29	$	55.17	$	27.37
Average production costs
Lease operating expense	$	190,207	$	203,132	$	126,131
Production tax	$	34,867	$	44,218	$	24,649
BOE	$	15.96	$	18.61	$	12.65

Drilling and Other Exploratory and Development Activities

The following table sets forth our drilling activity for the periods indicated.



	Years Ended December 31,
	2014		2013		2012
	Gross	Net	Gross	Net	Gross	Net
Exploratory Wells
Productive	—	—	4	0.5	3.0	0.1
Dry	—	—	1	0.1	3.0	0.1
Developmental Wells
Productive	—	—	2	0.3	2.0	0.1
Dry	—	—	—	—	0.0	—

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.

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 112^th District Court of Crockett County, Texas.

Plaintiff Oz Gas Corporation (“Oz”) filed a lawsuit in April 2008 against various parties for bad faith trespass, among other claims, regarding the drilling of two wells on lands that Oz claims title to. On November 18, 2009, Victory Energy Corporation intervened in the lawsuit to protect its 50% interest in one of the named wells in the lawsuit (that being the 155-2 well located on the Adams Baggett Ranch in Crockett County, Texas).

This case was mediated, with no settlement reached. It went to trial February 8-9, 2012. The Court found in favor of Oz and rendered verdict against Victory and the other Defendants, jointly and severally. Victory appealed this case to the 8th Court of Appeals in El Paso, Texas where the Court of Appeals affirmed the verdict of the District Court and Victory filed a Motion for Rehearing, which was denied. Victory filed a Petition for Review in the Supreme Court of Texas on December 15, 2014 which was denied. Victory is in the process of deciding whether or not they want to file a Motion for Rehearing in this case.

Cause No. CV-47,230; James Capital Energy, LLC and Victory Energy Corporation v. Jim Dial, et al.; In the 142^nd District Court of Midland County, Texas.

This is a lawsuit filed on or about January 19, 2010 by James Capital Energy, LLC and Victory Energy Corporation against numerous parties for fraud, fraudulent inducement, 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 Victory entered into for the purchase of six wells on the Adams Baggett Ranch with the right of first refusal on option acreage.

On December 9, 2010, Victory was granted an interlocutory Default Judgment against Defendants Jim Dial, 1^st Texas Natural Gas Company, Inc., Universal Energy Resources, Inc., Grifco International, Inc., and Precision Drilling & Exploration, Inc. The total judgment amounted to approximately seventeen million, one-hundred eighty-three thousand, nine-hundred eighty-seven dollars and eight cents ($17,183,987).

Victory has added a few more parties to this lawsuit. Discovery is ongoing in this case and no trial date has been set at this time.

Victory believes they 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 wherein 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 112^th District Court of Crockett County, Texas.

The above referenced lawsuit was filed on or about September 6, 2010. This lawsuit alleges that Cambrian Management, Ltd. and Victory were trespassers on their land, and that they, along with other Defendants, drilled a well (115 #8) on land belonging to Plaintiffs. Plaintiffs claim trespass and unjust enrichment by certain Defendants because of the drilling of the 115 #8 well.

Discovery is ongoing in this case and no trial date has been set. Victory believes that the claims made by Plaintiffs have no merit and that they will prevail at trial. Mediation began on August 8, 2013 and was adjourned to a later date which has not been set yet.

Cause No. D-1-GN-13-000044; Aurora Energy Partners and Victory Energy Corporation v. Crooked Oaks, LLC; In the 261^st District Court of Travis County, Texas.

Victory Energy Corporation sued Crooked Oaks, LLC a/k/a Crooked Oak, LLC for breach of a purchase and sale agreement dated May 7, 2012 in which Victory sold certain assets to Crooked Oaks, LLC for $400,000 of which only $200,000 has been paid as of December 31, 2014. The lawsuit seeks to recover the remaining balance owed of $200,000.00 from Crooked Oaks, LLC in addition to attorney’s fees and all costs of court. Crooked Oaks, LLC has asserted a counterclaim for rescission of the underlying contract.

Victory believes it will ultimately recover this receivable.

Cause No. 50198; Trilogy Operating, Inc. v. Aurora Energy Partners; In the 118th District Court of Howard County, Texas.

This lawsuit was filed on January 9, 2015. This lawsuit alleges causes of action for declaratory judgment, breach of contract, and suit to quiet title regarding the drilling and completion of four wells. On or about February 12, 2015, the parties met at an informal settlement conference. At the adjournment of the meeting, Trilogy was to provide Aurora with a detailed accounting before proceeding forward. The accounting provided by Trilogy was not helpful and Aurora has asked for an audit under the terms set out in the Joint Operating Agreement. Discovery is ongoing in this case and no trial date has been set at this time. Victory does not believe that all of Plaintiff’s claims have merit, and thus an audit is needed before proceeding any further.

Cause No. 2015-05280; TELA Garwood Limited, LP. v. Aurora Energy Partners, Victory Energy Corporation, Kenneth Hill, David McCall, Robert Miranda, Robert Grenley, Ronald Zamber, and Patrick Barry; In the 164th District Court of Harris County, Texas.

This lawsuit was filed on January 30, 2015 and supplemented on March 4, 2015. This lawsuit alleges breach of contract regarding a Purchase and Sale Agreement that TELA Garwood Limited, LP and Aurora Energy Partners entered into on June 30, 2014. A first closing was held on June 30, 2014 and a purchase price adjustment payment was made on July 31, 2014. Between these two dates Aurora paid TELA approximately three million fifty thousand one hundred thirty three dollars and sixty six cents ($3,050,133.66). A second closing was to take place in September, however several title defect were found to exist. The title defects could not be cured and a purchase price reduction could not be agreed upon by the parties in relation to the title defects, therefore, the second closing was terminated by TELA. Aurora and Victory have filed an answer in this case. Discovery is ongoing in this case and no trial date has been set.

Item 4. MINE SAFETY DISCLOSURE

Not applicable.

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, 2014 and 2013. The information reflects prices between dealers, and does not include retail markup, markdown, or commission, and may not represent actual transactions.



		Bid Prices
Fiscal Year Ended December 31,	Period	High		Low
2014	First Quarter	$	0.51	$	0.10
	Second Quarter	$	0.39	$	0.24
	Third Quarter	$	0.49	$	0.22
	Fourth Quarter	$	0.43	$	0.05
2013	First Quarter	$	0.40	$	0.02
	Second Quarter	$	0.33	$	0.01
	Third Quarter	$	0.25	$	0.02
	Fourth Quarter	$	0.30	$	0.02

Holders

As of March 31, 2015, the high and low bid prices for our common stock on the OTC Market was $0.32 and $0.25, respectively. As of March 31, 2015, there were approximately 1418 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 and Distributions 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.

Under the terms of the Second Amended Partnership Agreement of Aurora, Navitus earns a net profits interest and proceeds from asset sales respective to its 50% partnership interest in Aurora. Any distributions of the net profits interest and proceeds from asset sales to the partners are at the discretion of Victory, as managing partner , together with 100% of the partnership interests. The accumulated net deficits of Navitus, along with historical contributions, net of distributions, are reported as non-controlling interests in the equity section of the condensed consolidated financial statements.

Under the terms of Aurora’s Seconded Amended Partnership Agreement, Navitus Partners, LLC, the fourth partner of the Navitus Energy Group, admitted under the Navitus Private Placement Memorandum (the "Navitus PPM"), earns a preferred return distribution of 10% based upon capital contributions to Aurora used by Victory to acquire or develop oil and gas prospects or related enterprises on behalf of Aurora. The preferred return distribution is in addition to and does not reduce any net profits or asset sale proceeds interests.

The table below summarizes the net profit distributions, proceeds of asset sales and preferred return distributions paid to Navitus Energy Group during the years ended December 31, 2014 and 2013, respectively.



Payments Made to Navitus Energy Group	The Year Ended December 31,
	2014		2013
Distributions of Aurora Net Profits	$	86,516	—
Proceeds from the Sale of Aurora Assets	219,030		—
Preferred Distributions Due to Navitus Partners, LLC	341,876		—
Total Distributions Earned By Navitus Energy Group	$	647,422	—

Recent Sales of Unregistered Securities

During the twelve months ended December 31, 2014, we issued warrants to purchase shares of common stock at exercise prices ranging from $.14 to $.41 to Navitus in consideration of capital contributions by Aurora as follows:



Period	Investment		Warrants
First quarter ended March 31, 2014	$	320,000	320,000
Second quarter ended June 30, 2014	$	570,000	570,000
Third quarter ended September 30, 2014	$	250,000	250,000
Totals	$	1,140,000	1,140,000

During the twelve months ended December 31, 2014, we issued stock awards and stock options to directors, officers and employees of the Company, as well as to a vendor for services, at exercise prices ranging from $.14 to $.41as follows:



Purpose	Granted	Outstanding
Board Services	1,170,000	1,170,000
Vendor Services	350,000	350,000
Employee Awards	200,000	200,000
Employee Options	400,000	400,000
Totals	2,120,000	2,120,000

We did not purchase any of our own common stock during the year ended December 31, 2014.

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.

General Overview

The Company is an independent, growth-oriented oil and gas exploration and production company based in Austin, Texas, with additional resources located in Midland, Texas. The company is focused on the acquisition and development of stacked multi-pay resource play opportunities in the Permian Basin that offer predictable outcomes and long-lived reserve characteristics. The company presently utilizes low-risk vertical well development. Current Company assets include interest in proven formations such as the Spraberry, Wolfcamp, Wolfberry, Mississippian, Cline and Fusselman formations.. 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 2014, the Company held a working interest in 26 completed wells located in Texas and New Mexico, predominantly in the Permian Basin of West Texas.

Our primary company business objective is to grow proved reserves through high-grade development and acquisition of proved producing properties. We have a focus on oil and liquids rich gas. We also added properties large enough to offer new multi-well drilling opportunities in the future.

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, Victory has incurred a net loss of $3,209,932 during the twelve months ended December 31, 2014, and losses are expected to continue in the near term. The accumulated deficit at December 31, 2014 was $40,111,826. The Company has been funding its operations from contributions made by Aurora, and the Aurora bank credit facility, and the sale of the Lightnin' properties. 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 and other sources. 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, 2014 to Year Ended December 31, 2013

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 decreased $40,095, or 5.5%, for the twelve months ended December 31, 2014, from $735,413 for the twelve months ended December 31, 2013. The decrease is primarily the result of the change in prices the Company receives for the sale of oil and natural gas. The average price per barrel of oil decreased from $84.81 for the twelve months ended December 31, 2013 to $71.16 for the twelve months ended December 31, 2014. Similarly, the average price per Mcf decreased from $5.35 for the twelve months ended December 31, 2013 to $5.09 for the twelve months ended December 31, 2014 . The decreases in sales prices were offset by oil production increases from 5,810 to 6,509 barrels and natural gas production increases from 44,833 to 45,577 mcf for the twelve months ended December 31, 2014.

Lease Operating Expenses: Lease operating expenses, which include the operating expenses of obtaining the oil and natural gas, decreased $12,925 or 6.4% to $190,207 for the twelve months ended December 31, 2014 from $203,132 for the twelve months ended December 31, 2013. The decrease in lease operating expenses reflects the change in the aggregate net working interests held by Aurora in oil and gas producing properties.

Production Taxes: Production taxes are charged at the well head for the production of gas and oil. Production taxes decreased $9,351 or 21.1% to $34,867 for the twelve months ended December 31, 2014. The decrease is reflective of the change in oil and gas prices year to year.

Exploration and Dry Hole Costs: Dry Hole costs decreased $55,772 or 49.7% to $56,351 for the twelve months ended December 31, 2014 from $112,123 for the twelve months ended December 31, 2013. The Company incurred dry holes costs in connection with the drilling of a Lightin' well in 2013, in which the Company held a 20% working interest. The decrease in Exploration and Dry Hole Costs is reflective of costs associated with wells in which the Company holds proportionally lower net working interests.

General and Administrative Expense: General and administrative expenses increased approximately $1.2 million or 78.2% to approximately $2.7 million for the year ended December 31, 2014 from approximately $1.5 million for the year ending December 31, 2013. The increase is due to continued efforts to expand our operations, become timely with all SEC filings and asset related transactions.

Depletion, Depreciation, and Amortization: Depletion, depreciation, and amortization expenses increased $52,514 or 13.9% to $430,912 for the twelve months ended December 31, 2014 from $378,398 for the twelve months ended December 31, 2013. The increase reflects the increase in the amount of oil and natural gas production during the respective periods coupled with downward reserve adjustments.

Impairment of Oil and Natural Gas Properties: Impairment of oil and natural gas properties increased $3,080,459 or 480.9% to $3,721,042 from $640,583 for the twelve months ended December 31, 2014. This is primarily due to significant downward revisions to the Fairway property reserves, acquired in June 2014 and then impaired at December 31, 2014.

Gain on Sale of Oil and Natural Gas Properties: Gain on sale of oil and natural gas properties increased $2,149,960 or 10,353.8% for the twelve months ended December 31, 2014. This is due to primarily due to the sale of the Lightnin' properties in June 2014.

Management Fee Income: Management fee income increased $76,077 or 517.2% for the twelve months ended December 31, 2014 compared to the twelve months ended December 31, 2013.

Interest Expense: Interest expense increased $64,351 to $65,181 for the twelve months ended December 31, 2014 from $830 for the twelve months ended December 31, 2013. The increase resulted from the Company entering into the credit facility in February 2014.

Income Taxes: There is no provision for income tax expenses recorded for either the twelve months ended December 31, 2014 or ended December 31, 2013 due to the expected net operating losses ("NOL") of both years.

The realization of future tax benefits is dependent on our ability to generate taxable income within the NOL 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 2013 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 approximately $2.1 million or 99.9% to approximately $4.2 million for the twelve months ended December 31, 2014 from a net loss ofapproximately $2.1 million for the twelve months ended December 31, 2013. This net loss should be viewed in light of the cash flow from operations discussed below. The net loss attributable to Victory increased approximately $.5 million or 90.3% toapproximately $3.2 million for the twelve months ended December 31, 2014, after taking into account the loss attributable to non-controlling interest.

During the year ended December 31, 2014, as with the year ended December 31, 2013, 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, 2014 as compared to December 31, 2013, are as follows:



	December 31, 2014		December 31, 2013
Cash	$	2,941	$	20,858
Total current assets	$	190,719	$	194,634
Total assets	$	1,203,713	$	2,424,022
Total current liabilities	$	2,632,043	$	676,173
Total liabilities	$	2,672,536	$	728,127

At December 31, 2014, we had a working capital deficit of $2,441,324, compared to a working capital deficit of $481,539 at December 31, 2013. Current liabilities increased to $2,632,043 at December 31, 2014 from $676,173 at December 31, 2013 primarily due to the current payable balances associated with the Fairway assets, which are in dispute with the operator of the assets and the seller, and are under legal proceedings. An additional $800,000 is associated with the current portion of long term debt respective to the Texas Capital Bank credit facility.

The Company had a $4,229,137 net loss, of which $3,091,915 was in non-cash changes and changes to working capital accounts, resulting in $1,137,222 net cash used by operating activities. This compares to cash used by operating activities for the twelve months ended December 31, 2013 of $580,275 after the net loss for the period of $2,116,138 was decreased by $1,535,863 in non-cash charges and changes to the working capital accounts.

Net cash used in investing activities, excluding exploration-related charges charged directly to income and prepaid receivables for drilling cost, for the twelve months ended December 31, 2014 was $50,804. This includes $841,270 for the drilling and completion of wells, $3,214,872 for the acquisition of leaseholds, and $4,031,625 of proceeds from the sale of oil and natural gas properties. This compares to $1,893,032 of net cash used by investing activities for the twelve month period ended December 31, 2013 which included, $2,346,482 for the drilling and completion of wells, $375,000 of proceeds from the sale of oil and natural gas properties, and $160,000 for the sale-farm out of leaseholds.

Net cash provided by financing activities for the twelve months ended December 31, 2014 was $1,170,109, which includes $1,140,000 of contributions from Navitus and $1,233,000 in proceeds from debt financing; offset by $647,422 in distributions to non-controlling interest owners, $122,469 in debt financing costs, and $433,000 in principal payments on debt financing. This compares to the $2,336,000 in cash provided by financing activities during the twelve months ended December 31, 2013, which is solely attributed to contributions from Navitus.

Recent Accounting Pronouncements

In February 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-02, "Consolidation (Topic 810): Amendments to the Consolidation Analysis." ASU 2015-02 affects reporting entities that are required to evaluate whether they should consolidate certain legal entities. ASU 2015-02 is effective for periods beginning after December 15, 2015 with early adoption permitted. The Company is currently evaluating the new guidance and has not determined the impact this standard may have on its financial statements.

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in Accounting Standards Codification ("ASC") Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2016 for public companies. Early adoption is not permitted. Entities have the option of using either a full retrospective or modified approach to adopt ASU 2014-09. The Company is currently evaluating the new guidance and has not determined the impact this standard may have on its financial statements or decided upon the method of adoption.

In April 2014, the FASB issued ASU 2014-08, "Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." ASU 2014-08 prospectively changes the criteria for reporting discontinued operations while enhancing disclosures around disposals of assets whether or not the disposal meets the definition of a discontinued operation. ASU 2014-08 is effective for annual and interim periods beginning after December 31, 2014 with early adoption permitted but only for disposals that have not been reported in financial statements previously issued. The impact of this guidance on the Company's consolidated financial statements will depend

on the size and nature of the Company's disposal transactions in the future, which the Company cannot accurately predict. Several of the Company's past dispositions that were treated as discontinued operations may not have been classified as such had the new guidance been in effect.

In September 2011, the FASB issued Accounting Standard Update (“ASU”) No. 2011-8, “Intangible – Goodwill and Other (Topic 350), Testing Goodwill for Impairment”. The ASU provides an option for an entity 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. Under the ASU, 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, and the adoption of this ASU did not have a material effect on the 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 ASC 810. 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.

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.

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

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 reserves and calculated on a by well basis, based upon reserve reports prepared 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 undiscounted 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.

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

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, the Company will determine the amount of impairment.

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.

Stock Based Compensation

The Company adopted the ASC standard related to stock compensation to account for its warrants and options issued to employees, directors, officers and directors. 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 ("EPS") is computed by dividing net income (loss) attributable to controlling interests by the weighted-average number of shares of common stock outstanding during the period. Diluted earnings per share takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with stock awards that have been granted to directors and employees. In accordance with ASC 260, Earnings Per Share, awards of nonvested shares shall be considered outstanding as of the respective grant dates for purposes of computing diluted EPS even though their exercise is contingent upon vesting.

Income Taxes

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

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 likely that the Company will not be able to realize the tax benefit of the carry forwards. ASC 740 requires that a valuation allowance be established when it is more likely than not that all or a portion of deferred tax assets will not be realized.

Accordingly, the Company has a full valuation allowance against its net deferred tax assets at December 31, 2014 and December 31, 2013. Upon the attainment of taxable income by the Company, management will assess the likelihood of realizing the deferred tax benefit associated with the use of the net operating loss carry forwards and will recognize a deferred tax asset at that time.

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. The recent drop in commodity prices has reduced our cash flows from operations.

Off-Balance Sheet Arrangements

For the years ended December 31, 2014 and 2013, 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.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk

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 thousand cubic feet (MCF) of gas which the Company received for the periods indicated:



Three Months Ending	Average Price per MCF
March 31, 2014	$	5.97
June 30, 2014	$	5.06
September 30, 2014	$	4.79
December 31, 2014	$	4.55

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, 2014	$	75.62
June 30, 2014	$	82.93
September 30, 2014	$	66.97
December 31, 2014	$	58.70

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.

None.

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, and Chief Financial Officer ("CFO"), the Company's principal financial 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, 2014. 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, 2014. Based on this assessment, our management concluded that our disclosure controls and procedures were

not effective as of December 31, 2014 at the reasonable assurance level due to material weaknesses in internal control over financial reporting we identified in connection with preparing this annual report and the quarterly reports during 2014.

The material weaknesses we identified relate to our inability to prepare accurate financial statements, resulting from a lack of reconciliations, a lack of detailed review, and the lack of a sufficient number of qualified personnel to timely and appropriately account for and disclose the impact of complex, non-routine transactions in accordance with GAAP. These non-routine transactions impacted the recording of equity-based compensation, cash flow presentation, revenue, expenses, business combinations, assets, accounts payable, classification of debt, and footnote disclosures. The material weaknesses resulted in the recording of adjustments identified by our independent registered public accounting firm to our consolidated financial statements for the periods ended June 30, September 30 and December 31, 2014. Notwithstanding the existence of the material weaknesses, management has concluded that the consolidated financial statements included in this report present fairly, in all material respects, our financial position, results of operations and cash flows for the periods presented in conformity with GAAP.

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. To address this material weakness, 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. In June 2014 a full-time employee serving as the Chief Financial Officer was hired. Effective July 2014, the Company began installing and or improving many internal control processes. This process is continuing during 2015.

This Annual Report on Form 10-K 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 on Form 10-K.

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:

While the Company is still small, we now have a full-time employee serving as the Chief Financial 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.	Effective July 2014, the Company began installing and or improving many internal control processes. This process is continuing during 2015.

Item 9B. Other Information

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

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The following table sets forth information regarding the names, ages (as of March 31, 2015) 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	51	Director, Chief Executive Officer, and President
David McCall	66	Director, General Counsel
Robert Grenley	58	Director
Ronald Zamber	55	Director, Board Chairman
Patrick Barry	53	Director, Audit Committee Chairman
Fred J. Smith, Jr.	63	Chief Financial Officer and Controller

Kenneth Hill – Chief Executive Officer and Director

Mr. 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 gas company on the Australian Stock Exchange.

Since 2001, Mr. 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 gas. Prior to 2001, Mr. Hill was employed for 16 years at Dell, Inc. As one of the first 20 employees at Dell he served in a variety of management positions including manufacturing, sales, marketing, and business development. Prior to joining Dell, Mr. 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 – Board Member, Director and General Counsel

Mr. McCall has over 35 years of experience in the oil and gas industry, and is currently a partner in The McCall Firm in Austin, Texas. Mr. McCall's law practice has centered on the upstream, midstream and downstream activities of major and independent oil companies.

His expertise encompasses all aspects of oil and gas operations. He has been instrumental in negotiating operating leases and agreements; production purchase and sale agreements; pipeline and exploration agreements.

He has been lead counsel on complex oil and gas litigation matters including disputes between interest holders in producing properties; contract and lease disputes; title controversies and other traditional oil and gas matters. He has represented clients in federal royalty valuation disputes and Minerals Management Service (MMS) administrative proceedings.

Mr. McCall is also experienced in the preparation of drilling title opinions, loan opinions, division order title opinions, and acquisition opinions. He is board-certified in oil, gas and mineral law. Mr. McCall is an author and has served as an expert witness in title matters involving oil and gas properties.

In 1971, Mr. McCall received a Bachelor of Arts in marketing from McMurry University, Abilene, Texas. 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 – Board Member, Director and Audit Committee Member

Mr. Grenley has over 25 years of experience in financial management, business development and entrepreneurial experience. This financial experience includes 12 years managing early stage organizations with equity capital.

Mr. Grenley's broader financial management experience includes over 10 years of direct portfolio management and investment expertise including common and preferred stock, stock options, corporate and municipal bonds as well as syndicated investments and private placements.

Mr. Grenley holds a BA in Economics from Duke University.

Ronald W. Zamber, M.D. Director – Chairman of the Board and Audit Committee Member

Dr. Zamber is founder, Managing Director and Chairman of Visionary Private Equity Group. He brings more than 20 years of experience in corporate management and business development extending across the public, private and non-profit arenas. Dr. Zamber has helped build profitable companies in healthcare, private and public petroleum E&P, consumer products and Internet technology industries. He is a Managing Director of Navitus Energy Group, Navitus Partners and James Capital Energy.

Dr. Zamber is a Board Certified Ophthalmologist and founder of International Vision Quest, a non-profit organization that performs humanitarian medical and surgical missions, builds water treatment facilities and supports food delivery programs to impoverished communities around the world. He has served as an examiner with the American Board of Ophthalmologists and Secretariat for State Affairs with the American Academy of Ophthalmology.

He is the 2009 recipient of Notre Dame’s prestigious Harvey Foster Humanitarian Award. He now serves on the advisory board of Feed My Starving Children, one of the highest rated and fastest growing charities in the country. 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.

Patrick Barry – Board Member, Director and Audit Committee Chairman

Prior to joining the Board, Mr. Barry served as a financial and operations consultant for the Company. He is an experienced general manager with strengths in financial management, profitability improvement, strategy development, and implementing disciplined operating processes in both public and private companies.

Mr. Barry has a Bachelor of Science in Mechanical Engineering from the University of Notre Dame and a MBA in Finance from Wharton. Mr. Barry is a principal in Visionary Private Equity, a major investor in the Company.

Mr. Barry is a former Managing Director of the Gigot Center for Entrepreneurial Studies at the University of Notre Dame where he was also an Adjunct Professor. Prior to Notre Dame, he spent eight years turning around Quality Dining, Inc., a publicly held restaurant company headquartered in South Bend, IN. Mr. Barry was a consultant with Andersen Consulting in their Strategic Service Group, focusing in strategy development and general management consulting.

Fred Smith - Chief Financial Officer and Controller

Mr. Smith, has served as the Company’s Chief Financial Officer and Controller since June 2014. Prior to his appointment as the Company’s Chief Financial Officer and Controller, he worked as an independent consultant since December 2013. Prior to that, Mr. Smith worked as Senior Vice President and Chief Accounting Officer of Magnum Hunter Resources from October 2012 to September 2013. Previously, Mr. Smith served as the Corporate Controller of Pioneer Natural Resources from November 2008 to October 2012, where he was responsible for financial reporting, capital and operating expense reporting and application process controls. Mr. Smith has worked for a variety of energy companies during his career ranging from small privately held companies to major upstream entities. Mr. Smith has a B.S. in Accounting from the University of New Orleans and is a CPA - having worked for Ernst & Young as a senior auditor from 1974 to 1978.

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 4 times during the year ended December 31, 2014.

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 directors and officers.

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.

Section 16(a) Beneficial Ownership Reporting Compliance:

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 on Form 10K 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 all such required reports during and with respect to our 2014 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 Fred J. Smith 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 Patrick Barry was 1.

Code of Ethics

As of December 31, 2014, the Company's board of directors consists of 5 members and it is anticipated that the board of directors will not expand to include any additional members.

The Company does not have any "independent directors" as that term is defined under independence standards used by any national securities exchange or an inter-dealer quotation system. The board of directors has not established any committees, and accordingly, the board of directors serves as the audit, compensation, and nomination committee.

We have not adopted a code of ethics that applies to our our principal executive officer, principal financial officer, principal accounting officer and controller, or persons performing similar functions during the year ended December 31, 2014, because of the small number of persons involved in the management of the Company.

Item 11. Executive Compensation

The following table sets forth information regarding compensation earned during the last two fiscal years by our Chief Executive Officer, our only executive officer during the year ended December 31, 2014 (the “ Named Executive Officer ”).



Name and Principal Position	Year	Salary ($)	Bonus ($)	Stock Awards ($)(1)	Warrant/Option Awards ($)(1)	Non-Equity Incentive Plan Compensation ($)	All Other Compensation ($)	Total ($)
Kenneth Hill - President and Chief Executive Officer	2014	211,667	—	34,500	17,250	—	—	263,417
Kenneth Hill - President and Chief Executive Officer	2013	180,000	—	—	5,412	—	—	185,412
Fred J. Smith, Jr. - Chief Financial Officer (2)	2014	105,000	10,000	—	8,750	—	50,000	173,750

(1)

These amounts shown represent the aggregate grant date fair value for stock awards, options and warrants granted to the Named Executive Officer computed in accordance with FASB ASC Topic 718. Assumptions used in the calculation of these amounts are included in “Note 7 – Stockholders’ Equity” to our audited financial statements for the fiscal year ended December 31, 2014 included in this Annual Report on Form 10-K. All outstanding stock awards were canceled as of the Emergence Date.


(2)	The annual salary for Fred J. Smith, Jr. is $180,000 per year. The effective date of his employment is June 2, 2014. Other compensation relates to relocation expenses.


(3)	The annual salary for Kenneth Hill is $225,000 per year. The effective date of this salary is April 1, 2014.

Narrative Disclosure to Summary Compensation Table

The Company has not historically adopted any formal policies or procedures regarding executive compensation. Instead, compensation decisions are made in accordance with the terms of employment agreements with the Company’s executive officers, or on an ad hoc basis and at the discretion of the Board. The Company has entered into an employment agreement with the Named Executive Officers.

On May 27, 2014, the Company entered into an Employment Agreement with Fred J. Smith, Jr., wherein Mr. Smith, Jr. agreed to serve as the Chief Financial Officer of the Company. The term of the employment agreement began on June 2, 2014, and will end upon notice by either party. Mr. Smith, Jr. will receive a base annual salary of $180,000 per year and he will participate in the Company's employee benefit plans made available to its executive officers generally.

The following details the terms of this employment agreement:

On January 7, 2011, the Company entered into an Employment Agreement with Kenneth Hill, wherein Mr. Hill agreed to serve as Vice President and Chief Operating Officer of the Company. The term of the employment agreement began on January 10, 2011, and will end upon notice by either party. Mr. Hill will receive a base annual salary of $180,000 per year and he will participate in the Company’s employee benefit plans made available to its executive officers generally.

The Company made the following grants of awards under the Victory Energy Corporation 2014 Long Term Incentive Plan (the “Incentive Plan”) to the Name Executive Officers:

On April 23, 2014, Mr. Hill was granted an award (the “April Stock Grant”) of 300,000 shares of Company common stock under the Incentive Plan. The 300,000 shares of Company common stock granted to Mr. Hill in the April Stock Grant are 100% vested as of the date of grant.

On April 23, 2014, the Company granted Mr. Hill an option, under the Incentive Plan, to purchase 150,000 shares of the Company’s common stock at an option price of $0.35, which was the fair market value as of the date of grant. The option was 100% vested on the date of grant. The option will terminate on April 23, 2020.

On June 1, 2014, Mr. Hill was also granted an award (the “June Stock Grant”) of 20,000 shares of Company common stock under the Incentive Plan. The 20,000 shares of Company common stock granted to Mr. Hill in the June Stock Grant are 100% vested as of the date of grant.

On June 2, 2014, Mr. Smith was granted a Nonstatutory Stock Option covering 150,000 shares of the Company’s common stock under the Incentive Plan. The option granted to Mr. Smith will have a price of $.30 and will vest over a 3-year period on each anniversary of the date of grant with 100% vesting accelerated for certain events such as a change in control of the Company.

Potential Payments upon Termination or Change in Control

The Named Executive Officers are not entitled to any payments upon his termination or upon a change in control.

The employment agreements with Messrs. Hill and Smith do not provide for any payments upon the termination of their employment or a change of control. All of the awards granted to Mr. Hill were 100% vested as of the time of grant and are therefore not subject to any accelerated vesting provisions upon a change of control or the termination of his employment. As such, Mr. Hill is not entitled to any payments upon a termination of his employment or a change of control.

The Nonstatutory Stock Option granted to Mr. Smith under the Incentive Plan will automatically vest in its entirety upon certain events such as a change of control or a termination of his employment due to death, disability or without cause.

The following table further describes the potential payments upon termination or a change in control for Mr. Smith.

Fred Smith

Chief Financial Officer



Executive Benefits and Payments Upon Termination	Voluntary Termination ($)		For cause terminated ($)		Involuntary Not for Cause Termination ($)		Death or Disability ($)		Retirement ($)		After a Change in Control ($)
Long-Term Equity Incentives
Nonstatutory Stock Option (Unvested and Accelerated)(2)		0		0		0		0		0		150,000
Total		0		0		0		0		0		150,000

Outstanding Equity Awards at Fiscal Year-End

The following table sets forth certain information concerning outstanding stock awards held by the Named Executive Officer as of December 31, 2014.



	OPTION AWARDS					STOCK AWARDS
Name - Year	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options (#) Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	Warrant/ Option Exercise Price ($)	Warrant/ Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)	Market Value of Shares or Units of Stock That Have Not Vested ($)	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)
Kenneth Hill - President and Chief Executive Officer	90,000	—	—	$.50-$1.00	12/31/2016	—	—	—	—
Kenneth Hill - President and Chief Executive Officer	50,000	—	—	$.35	5/23/2017	—	—	—	—
Fred J. Smith, Jr. - Chief Financial Officer	29,167	—	—	$.30	7/2/2017	—	—	—	—

Director Compensation

The following table sets forth the total compensation awarded to, earned by, or paid to each person who served as a director during the year ended December 31, 2014, other than a director who also served as a named executive officer. Our directors who are not executive officers do receive any cash compensation for serving on our Board. We have a policy of reimbursing our directors for their reasonable out-of-pocket expenses incurred in attending Board and committee meetings. Each director is paid for his or her director services in the form of 20,000 stock awards granted quarterly for each quarter of service. These stock awards and vest immediately, at fair market value, upon date of issuance.



	Fees Earned or Paid in Cash	Stock Awards	Warrant/Option Awards	Total
Name	($)	($)(1)	($)(1)	($)
Ronald Zamber	—	97,550	—	97,550
David McCall	281,585	95,825	—	377,410
Robert Grenley	—	44,075	—	44,075
Patrick Barry	12,600	26,825	—	39,425
Ralph Kehle (2)	—	32,200	—	32,200

(1) These amounts shown represent the aggregate grant date fair value for stock awards, options and warrants granted to the directors computed in accordance with FASB ASC Topic 718. Assumptions used in the calculation of these amounts are included in “Note 7 – Stockholders’ Equity” to our audited financial statements for the fiscal year ended December 31, 2014 included in the Company’s Annual Report on Form 10-K filed with on November 12, 2013. All outstanding stock awards were canceled as of the Emergence Date.

(2) Mr. Kehle resigned from the board of directors and as Board Chairman, effective December 18, 2014.

Narrative Disclosure of Compensation Policies and Practices as Related to Risk Management

In accordance with the requirements of Regulation S-K, Item 402(s), to the extent that risks may arise from our compensation policies and practices that are reasonably likely to have a material adverse effect on us, we are required to discuss those policies and practices for compensating our employees (including employees that are not named executive officers) as they relate to our risk management practices and the possibility of incentivizing risk-taking. We have determined that the compensation policies and practices established with respect to our employees are not reasonably likely to have a material adverse effect on us and, therefore, no such disclosure is necessary.

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

As of December 31, 2014



Equity Compensation Plan Information

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights⁽¹⁾	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)	(b)	(c)

Equity compensation plans approved by security holders	4,134,542		2,034,542

Equity compensation plans not approved by security holders	0	0	0

Total	4,134,542	—	2,034,542

(1) Includes options outstanding under the 2014 Long Term Incentive Plan. The total number of shares of common stock initially available for issuance under the 2014 Long Term Incentive Plan was 4,134,542. As of December 31, 2014, 350,000 shares of restricted stock, and 1,350,000 shares of unrestricted common stock and 400,000 options were issued under the 2014 Long Term Incentive Plan.

Security Ownership of Certain Beneficial Owners

Beneficial ownership is determined in accordance with the rules of the SEC, and generally includes voting power and/or investment power with respect to the securities held. Shares of common stock subject to options or warrants currently exercisable or exercisable within 60 days of December 31, 2014, are deemed outstanding and beneficially owned by the person holding such options or warrants for purposes of computing the number of shares and percentage beneficially owned by such person, but are not deemed outstanding for purposes of computing the percentage beneficially owned by any other person. Except as indicated in the footnotes to these tables, and subject to applicable community property laws, the persons or entities named have sole voting and investment power with respect to all shares of our common stock shown as beneficially owned by them.

The following table sets forth, as of December 31, 2014, certain information with respect to the Company’s equity securities owned or record or beneficially by (i) each officer and director of the Company; (ii) each person who owns beneficially more than 5% of each class of the Company’s outstanding equity securities; and (iii) all directors and executive officer as a group:



Name and Position	Business Address	Common Stock	Vested Options	Warrants (1)	Total	Percent of Class (2)
Kenneth Hill,	3355 Bee Caves Rd., Ste 608
President and Chief	Austin, TX 78746
Executive Officer		573,020	140,000	143,900	856,920	2.9	%
David McCall,	3660 Stoneridge Blvd., Ste.F-102
General Counsel,	Austin TX 78746
Director (3)		430,233	—	244,150	674,383	2.3	%
Robert Grenley,	40 Loch Lane SW,
Director	Lakewood, WA 98499	178,934	—	118,600	297,534	1.0	%
Ronald Zamber,	1919 Lathrop Suite
Director (4),	Fairbanks, AK 99701
Interim Board Chairman		5,397,210	—	2,191,281	7,588,491	26.0	%
Patrick Barry	51551 Norwich Dr.
Audit Committee Chairman	Granger, IN 46530	572,320	—	98,400	670,720	2.3	%
All Officers and Directors As a Group (5 Persons)		7,151,717	140,000	2,697,931	10,088,048	34.5	%


(1)	All warrants are exercisable immediately


(2)	Based on total shares outstanding which consists of 29,202,826 shares of common stock outstanding, 262,500 vested options, and 6,071,386 unexercised warrants.


(3)	Includes 145,233 shares owned by 1519 Partners LLC; David McCall is the controlling partner and of 1519 Partners LLC.


(4)	Includes 2,468,138 shares owned by Visionary Investments, LLC of which Ronald Zamber is sole member; 2,437,481 shares owned by Visionary Private Equity Group I, LP of which Ronald Zamber is chairman, and managing director, and 104,845 shares owned by James Capital Consulting of which Ronald Zamber is the managing member.

There are no classes of stock other than common stock issued or outstanding.

The Company is not aware of any current arrangements which will result in a change in control.

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

Related Party Transactions

During the year ended December 31, 2014 we incurred a total of $281,585 in legal fees with The McCall Firm. David McCall, our general counsel and a director, is a partner in The McCall Firm. The fees are attributable to litigation involving the Company’s oil and natural gas operations in Texas. As of December 31, 2014, the Company owed The McCall Firm approximately $82,934 for these professional services.

During the year ended December 31, 2014 we incurred a total of $12,600 in consulting fees with Patrick Barry for which there was no balance owed as of the end of the year 2014.

During the year ended December 31, 2014, a member of management made a $5,000 temporary advance to the Company.

During the year ended December 31, 2014, the following temporary capital advances totaling $390,000 had been made by Navitus Energy Group Partnership:



November 30, 2014	$250,000
December 9, 2014	$40,000
December 31, 2014	$100,000
Total Advances	$390,000

As of July 1, 2014, Ralph Kehle was appointed as a Board of Director for the Company. During this time, Mr. Kehle was also the Chairman of the Board for TELA (USA), Inc.. Aurora and TELA entered into a letter of intent on May 8, 2014 and followed by entering into a Purchase and Sale Agreement dated June 30, 2014 for the Fairway Acquisition. Mr. Kehle received 95,000 shares of common stock, valued at $32,200, for his board services as of December 31, 2014. Mr. Kehle resigned from our Board of Directors in December 2014.

The Company’s securities are not listed on a national securities exchange or interdealer quotation system that has requirements as to board composition. As the securities are not so listed, the board of directors has made no determination as to whether or not any of its directors are independent directors as defined in the regulations of NASDAQ or the NYSE.

Item 14. Principal Accounting Fees and Services

Audit Fees

For the years ended December 31, 2014 and 2013 respectively, we paid $142,600 and $51,677, respectively, in fees to our principal accountants.

Tax Fees

For the fiscal years ended December 31, 2014 and 2013, our principal accountants did not render any services for tax compliance, tax advice, and tax planning work.

All Other Fees

None.

All fees described above for the years ended December 31, 2014 and 2013, were approved by the entire board of directors.

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a) (1) and (2) Consolidated financial statements and Schedules

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



	Page

Report of Independent Registered Public Accounting Firm	F-1

Consolidated Balance Sheets as of December 31, 2014 and 2013	F-2

Consolidated Statements of Operations for the Years Ended December 31, 2014 and 2013	F-3

Consolidated Statements of Cash Flows for the Years Ended December 31, 2014 and 2013	F-4

Consolidated Statement of Stockholders Deficit for the Years Ended December 31, 2014 and 2013	F-6

Notes to Consolidated Financial Statements for the Years Ended December 31, 2014 and 2013	F-7

(a)(3) Exhibits

Refer to (b) below.



(b)	Exhibits

2.1	Purchase and Sale Agreement dated as of June 30, 2014 between TELA Garwood Limited, LP and Aurora Energy Partners. Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed with the SEC on July 8, 2014.

2.2	Purchase and Sale Agreement dated as of April 30, 2014 by and among Hannathon Petroleum, LLC and the other seller parties thereto and MDC Texas Energy, LLC. Incorporated by reference to Exhibit 2.1 of the Company’s Amendment No. 1 to Quarterly Report on Form 10-QA for the quarterly period ended June 30, 2014, filed with the SEC on August 28, 2014.

3.1	Amended and Restated Articles of Incorporation of Victory Energy Corporation.*

3.11	Bylaws of Victory Energy Corporation. Incorporated by reference to Exhibit 3.10 of the Company’s Annual Report on Form 10-K filed with the SEC on March 30, 2011.

4.1	Form of the Company’s Common Stock Certificate.*

10.1	Unsecured Promissory Notes (Zamber). Incorporated by reference to Exhibit 10.1 of the Company’s Annual Report on Form 10-K filed with the SEC on March 30, 2011.

10.2	Separation Agreement by and between Victory Energy Corporation and Jon Fullenkamp dated May 15, 2009. Incorporated by reference to Exhibit 10.4 of the Company’s Annual Report on Form 10-K filed with the SEC on March 30, 2011.

10.3	The Victory Energy Corporation/James Capital Energy, LLC, Joint Venture Partnership Agreement by and between Victory Energy Corporation, James Capital Energy, LLC and James Capital Consulting dated January 1, 2008. Incorporated by reference to Exhibit 10.2 of the Company’s Annual Report on Form 10-K filed with the SEC on March 30, 2011.

10.4	Settlement Agreement and Mutual General Release dated March 24, 2011 by and between Jon Fullenkamp and Xploration, on the one hand; and Victory Energy Corporation, James Capital Energy, LLC, James Capital Consulting, LLC, James Capital, LLC, Aurora Energy Partners, Zamber Energy Investments, LLC, International Vision Quest, Miranda & Associates, Ronald Zamber, Robert Miranda, Richard May, and Tom Konz, on the other hand. Incorporated by reference to Exhibit 10.5 of the Company’s Annual Report on Form 10-K filed with the SEC on March 30, 2011.

10.5	Consulting Services Agreement by and between Victory Energy Corporation and Miranda & Associates, A Professional Accountancy Corporation dated November 16, 2008. Incorporated by reference to Exhibit 10.6 of the Company’s Annual Report on Form 10-K filed with the SEC on March 30, 2011.

10.6	Consulting Services Agreement by and between the Victory Energy Corporation and Miranda & Associates, A Professional Accountancy Corporation, dated August 1, 2009. Incorporated by reference to Exhibit 10.7 of the Company’s Annual Report on Form 10-K filed with the SEC on March 30, 2011.

10.7	First Amendment to The Victory Energy Corporation/James Capital Energy, LLC, Joint Venture Partnership Agreement, changing the name of the Partnership to “Aurora Energy Partners, A Texas General Partnership”, dated January 1, 2008. Incorporated by reference to Exhibit 10.3 of the Company’s Annual Report on Form 10-K filed with the SEC on March 30, 2011.



10.8	Option Agreement by and among Victory Energy Corporation, Santiago Resources, LP, 1519 Partners, LP, Via Fortuna Minerals, LLC, Wesley G. Ritchie, and Barrier Island Minerals, LLC dated December 20, 2010. Incorporated by reference to Exhibit 99.1 of the Company’s Amendment No. 1 to Form 8-KA filed with the SEC on January 5, 2011.

10.9	Second Amendment to The Victory Energy Corporation/James Capital Energy, LLC, Joint Venture Partnership Agreement, In which the Company agreed with The Navitus Energy Group (“Navitus”), James Capital Consulting, LLC (“JCC”), and James Capital Energy, LLC (“JCE”) to amend certain terms of the Aurora Energy Partners partnership (“Aurora”) and to substitute Navitus, a Texas general partnership composed of JCC, JCE, Rodinia Partners, LLC, and Navitus Partners, LLC, as partner for JCC and JCE in Aurora. The effective date of the Second Amended Partnership Agreement is October 1, 2011. In addition, the Second Amendment effectively increases the Company’s interest in the profits and losses of Aurora from 15% to 50%. Incorporated by reference to Exhibit 99.1 of the Company’s Form 8-K filed with the SEC on December 9, 2011.

10.10	Credit Agreement dated as of February 20, 2014 between Aurora Energy Partners and Texas Capital Bank, National Association. Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the SEC on February 26, 2014.

10.11	Employment Agreement dated May 27, 2014 between Victory Energy Corporation and Fred Smith. Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the SEC on June 3, 2014.




10.12	Stock Award with Kenneth Hill dated August 13, 2014. Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the SEC on August 18, 2014.

10.13	Award Notice of Nonstatutory Stock Option with Kenneth Hill dated August 13, 2014. Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed with the SEC on August 18, 2014.

10.14	Nonstatutory Stock Option Agreement with Kenneth Hill dated August 13, 2014. Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed with the SEC on August 18, 2014.

10.15	Stock Award with Kenneth Hill dated August 13, 2014. Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K filed with the SEC on August 18, 2014.

10.16	Victory Energy Stock Award (Director) with Ralph Kehle dated August 14, 2014. Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the SEC on August 18, 2014.

10.17	Pre-Merger Collaboration Agreement among the Company, Lucas Energy, Inc., Aurora Energy Partners, Navitus Energy Group and Aurora Energy Holdings LLC, dated February 26, 2015. Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the SEC on March 3, 2015.

10.18	Pre-Merger Loan and Funding Agreement between the Company and Lucas Energy, Inc. dated February 26, 2015. Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed with the SEC on March 3, 2015.

10.19	Pledge Agreement between Lucas Energy, Inc., as pledgor, and the Company, as secured party, dated February 26, 2015. Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed with the SEC on March 3, 2015.

10.20	Contingent Pay Note by the Company in favor of Louise H. Rogers dated March 3, 2015. Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K filed with the SEC on March 3, 2015.

10.21	Amendment No. 1 to Pre-Merger Collaboration Agreement dated March 2, 2015. Incorporated by reference to Exhibit 10.5 of the Company’s Current Report on Form 8-K filed with the SEC on March 3, 2015.

10.22	Employment Agreement dated January 7, 2011 between Victory Energy Corporation and Kenny Hill.*

21.1	Subsidiaries of the Registrant.*

23.1	Consent of Marcum LLP*

23.2	Consent of Weaver & Tidwell LLP*

23.3	Consent of Independent Petroleum Engineer and Geologists*

31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350.*

32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350.*

99.1	Oil and natural gas Reserves Report prepared by Cambrian Management, Ltd. dated February 12, 2015*



101.INS		Instance Document**

101.SCH		Taxonomy Extension Schema Document**

101.CAL		XBRLTaxonomy Extension Calculation Linkbase Document**

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document**

101.LAB		XBRL Taxonomy Extension Label Linkbase Document**

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document**

* Filed herewith.

** XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

SIGNATURES

In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Austin, State of Texas, on this 31st day of March, 2015.



	VICTORY ENERGY CORPORATION

	By:	/s/ Kenneth Hill
		Kenneth Hill
		Chief Executive Officer and Director

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



Signature	Title	Date

/s/ Kenneth Hill	Chief Executive Officer and Director (Principal Executive Officer )
Kenneth Hill
/s/ Fred J. Smith, Jr.	Chief Financial Officer (Principal Financial Officer)
Fred J. Smith, Jr.
/s/ Ronald W. Zamber	Director
Ronald W. Zamber
/s/ David B. McCall	Director
David B. McCall
/s/ Patrick Barry	Director
Patrick Barry
/s/ Robert Grenley	Director
Robert Grenley

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

Victory Energy Corporation

We have audited the accompanying consolidated balance sheets of Victory Energy Corporation (the Company) as of December 31, 2014 and 2013, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2014. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Victory Energy Corporation as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America.

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

WEAVER AND TIDWELL, L.L.P.

March 31, 2015

Houston, Texas

F-1

VICTORY ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31, 2014 and 2013



ASSETS	12/31/2014			12/31/2013
Current Assets
Cash and cash equivalents	$	2,941		$	20,858
Accounts receivable - less allowance for doubtful accounts of $200,000, and $200,000 for 2014 and 2013, respectively	41,565			116,542
Accounts receivable - affiliate	124,367			18,571
Prepaid expenses	21,846			38,663
Total current assets	190,719			194,634
Fixed Assets
Furniture and equipment	46,883			43,173
Accumulated depreciation	(17,965		)	(11,597		)
Total furniture and fixtures, net	28,918			31,576
Oil gas properties, net of impairment (successful efforts method)	2,838,573			3,715,648
Accumulated depletion, depreciation and amortization	(1,942,380		)	(1,517,836		)
Total oil and gas properties, net	896,193			2,197,812
Other Assets
Deferred debt financing costs	87,883			—
Total Assets	$	1,203,713		$	2,424,022
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	1,119,896		$	351,435
Accrued liabilities	221,209			196,913
Accrued liabilities - related parties	477,934			118,542
Liability for unauthorized preferred stock issued	9,283			9,283
Note payable	800,000			—
Asset retirement obligation	3,721			—
Total current liabilities	2,632,043			676,173
Other Liabilities
Asset retirement obligations	40,493			51,954
Total long term liabilities	40,493			51,954
Total liabilities	$	2,672,536		$	728,127
Stockholders' Equity (Deficit)
Common stock, $0.001 par value, 47,500,000 shares authorized, 29,202,826 shares and 27,563,619 shares issued and outstanding for 2014 and 2013, respectively	$	29,203		$	27,564
Additional paid-in capital	34,974,441			34,404,239
Accumulated deficit	(40,111,826		)	(36,901,894		)
Total Victory Energy Corporation stockholders' deficit	(5,108,182		)	(2,470,091		)
Non-controlling interest	3,639,359			4,165,986
Total stockholders' equity (deficit)	(1,468,823		)	1,695,895
Total Liabilities and Stockholders' Equity	$	1,203,713		$	2,424,022

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

F-2

VICTORY ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

For the years ended December 31, 2014 and 2013



	12/31/2014			12/31/2013
Revenues
Oil and gas sales	$	695,318		$	735,413
Total revenues	695,318			735,413
Operating Expenses:
Lease operating costs	190,207			203,132
Exploration and dry hole cost	56,351			112,123
Production taxes	34,867			44,218
General and administrative	2,687,405			1,507,740
Impairment of oil and natural gas properties	3,721,042			640,583
Depreciation/depletion/amortization	430,912			378,398
Total operating expenses	7,120,784			2,886,194
Loss from operations	(6,425,466		)	(2,150,781		)
Other Income (Expense):
Gain on sale of oil and gas properties	2,170,725			20,765
Management fee income	90,785			14,708
Interest expense	(65,181		)	(830		)
Total other income and expense	2,196,329			34,643
Loss before Tax Benefit	(4,229,137		)	(2,116,138		)
Tax benefit	—			—
Net loss	(4,229,137		)	(2,116,138		)
Less: Net loss attributable to non-controlling interest	(1,019,205		)	(429,511		)
Net loss attributable to Victory Energy Corporation	$	(3,209,932	)	$	(1,686,627	)


Weighted average shares, basic and diluted	28,453,976			27,563,619
Net income (loss) per share, basic and diluted	$	(0.11	)	$	(0.06	)

The accompanying notes are an integral part of the consolidated financial statements

F-3

VICTORY ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31, 2014 and 2013



	12/31/2014			12/31/2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(4,229,137	)	$	(2,116,138	)
Adjustments to reconcile net loss to net cash used in operating activities
Accretion of asset retirement obligations	3,360			3,119
Amortization of debt discount and financing warrants	34,586			—
Depletion, depreciation, and amortization	430,912			378,398
Gain from sale of oil and gas properties	(2,170,725		)	(20,765		)
Impairment of oil and natural gas properties	3,721,042			640,583
Stock based compensation	490,174			52,106
Stock grants in exchange for services	81,667			—
Warrants for services	—			27,060
Change in operating assets and liabilities
Accounts receivable	74,977			40,939
Accounts receivable - affiliate	(105,796		)	(18,571		)
Prepaid expense	16,817			30,030
Accounts payable	131,213			347,096
Accounts liabilities - related parties	359,392			101,038
Accrued interest	—			(25,639		)
Accrued liabilities	24,296			(19,531		)
Net cash used in operating activities	(1,137,222		)	(580,275		)

CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling costs	(841,270		)	(2,346,482		)
Sale-farm out of leaseholds	—			160,000
Acquisition of oil and gas properties	(3,214,872		)	—
Proceeds from sale of oil and gas properties	4,031,625			375,000
Renewal of leasehold costs	(22,577		)	(81,550		)
Purchase of furniture and fixtures	(3,710		)	—
Net cash used in investing activities	(50,804		)	(1,893,032		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Non-controlling interest contributions	1,140,000			2,336,000
Non-controlling interest distributions	(647,422		)	—
Debt financing costs	(122,469		)	—
Proceeds from debt financing	1,233,000			—
Principal payments on debt financing	(433,000		)	—
Net cash provided by financing activities	1,170,109			2,336,000
Net Change in Cash and Cash Equivalents	(17,917		)	(137,307		)
Beginning Cash and Cash Equivalents	20,858			158,165
Ending Cash and Cash Equivalents	$	2,941		$	20,858

Supplemental cash flow information:
Cash paid for:
Interest	$	30,595		$	—
Non-cash investing and financing activities:
Drilling Costs	$	637,248		$	—
Acquisition of oil and gas properties	$	182,250		$	—

The accompanying notes are an integral part of the consolidated financial statements

F-4

VICTORY ENERGY CORPORATION AND SUBSIDARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS DEFICIT

For the years ended December 31, 2014 and 2013



	Common Stock $0.001 Par Value					Additional Paid		Accumulated			Non- controlling			Total Equity
	Number		Amount			In Capital		Deficit			Interest			(Deficit)
Balance, December 31, 2012	27,563,619		$	27,564		$	34,325,073	$	(35,215,267	)	$	2,409,497		$	1,546,867
Contributions from noncontrolling interest owners	—		—			—		—			2,336,000			2,336,000
Stock based compensation	—		—			52,106		—			—			52,106
Beneficial conversion feature on convertible debentures	—		—			27,060		—			—			27,060
Reclassification to redesignate to investor loan from contributions	—		—			—		—			(150,000		)	(150,000		)
Net loss	—		—			—		(1,686,627		)	(429,511		)	(2,116,138		)
Balance December 31, 2013	27,563,619		$	27,564		$	34,404,239	$	(36,901,894	)	$	4,165,986		$	1,695,895
Contributions from noncontrolling interest owners	—		—			—		—			1,140,000			1,140,000
Distributions to noncontrolling interest owners	—		—			—		—			(647,422		)	(647,422		)
Stock awards	1,350,000		1,350			90,885		—			—			92,235
Stock based compensation	—		—			397,939		—			—			397,939
Stock in exchange for services	350,000		350			81,317		—			—			81,667
Shares canceled	(60,793	)	(61		)	61		—			—			—
Net loss	—		—			—		(3,209,932		)	(1,019,205		)	(4,229,137		)
Balance December 31, 2014	29,202,826		29,203			34,974,441		(40,111,826		)	3,639,359			(1,468,823		)

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

F-5

Victory Energy Corporation and Subsidiaries

Notes to the Consolidated Financial Statements

Note 1 – Organization and Summary of Significant Accounting Policies:

Victory Energy Corporation (Victory or the Company) is an independent, growth oriented oil and natural gas company engaged in the acquisition, exploration and production of oil and natural gas properties, through its partnership with Aurora Energy Partners. In this report, “the Company” refers to the consolidated accounts and presentation of Victory and Aurora, with the equity of non-controlling interests stated separately. The Company is engaged in the exploration, acquisition, development, and production of domestic oil and natural gas properties. Current operations are primarily located onshore in Texas and New Mexico. The Company 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, and has 29,202,826 shares of common stock outstanding as of December 31, 2014. Our corporate headquarters are located at 3355 Bee Caves Rd. Ste. 608, Austin, TX 78746.

A summary of significant accounting policies followed in the preparation of the accompanying consolidated financial statements is set forth below.

Basis of Presentation and Consolidation:

Victory is the managing partner of Aurora, and holds a 50% partnership interest in Aurora. Aurora, a subsidiary of the Company, is consolidated with Victory for financial statement reporting purposes, as the terms of the partnership agreement that governs the operations of Aurora give Victory effective control of the partnership. The consolidated financial statements include the accounts of Victory and the accounts of Aurora. The Company’s management, in considering accounting policies pertaining to consolidation, has reviewed the relevant accounting literature. The Company follows that literature, 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 determined 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. All intercompany balances have been eliminated in consolidation.

Non-controlling Interests:

The Navitus Energy Group is a partner with Victory in Aurora. The two partners each own a 50% interest in Aurora. Victory is the Managing partner and has contractual authority to manage the business affairs of Aurora. The Navitus Energy Group currently has four partners. They are James Capital Consulting, LLC ("JCC"), James Capital Energy, LLC ("JCE"), Rodinia Partners, LLC and Navitus Partners, LLC. Although this partnership has been in place since January 2008, its members and other elements have changed since that time.

The non-controlling interest in Aurora is held by Navitus Energy Group ("Navitus"), a Texas general partnership. As of December 31, 2014, $3,639,359 was recorded as the equity of the non-controlling interest in our consolidated balance sheet representing the third-party investment in Aurora, with losses attributable to non-controlling interests of $1,019,205 for the year ended December 31, 2014. As of December 31, 2013, $4,165,986 was recorded as the equity of the non-controlling interest in our consolidated balance sheet representing the third-party investment in Aurora, with losses attributable to the non-controlling interests of $429,511 for the year ended December 31, 2013. A total of $150,000 of previously designated capital contributions by Navitus were redesignated as temporary advances in December 31, 2014 and are included in the related party payable total as of December 31, 2014.

Reclassifications:

Certain reclassifications have been made to accounts receivable - affiliates (reduction of $50,000); accrued liabilities - related parties (increase of $100,000); and additional paid in capital (reduction of $150,000) on the December 31, 2013 Consolidated Balance Sheet to conform to the presentation on the current period Consolidated Balance Sheet and reflect the proper classification of working capital advances from a member of the Navitus Energy Group. The total $100,000 advance was repaid in January 2015. These reclassifications had no impact on the net income for the year ended December 31, 2013.

Use of Estimates:

F-6

The preparation of our consolidated financial statements in conformity with U.S. Generally Accepted Accounting Principles (“GAAP”) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates are used primarily when accounting for depreciation, depletion, and amortization (“DD&A”) expense, property costs, estimated future net cash flows from proved reserves, cost to abandon oil and natural gas properties, taxes, accruals of capitalized costs, operating costs and production revenue, capitalized general and administrative costs and interest, insurance recoveries, effectiveness and estimated fair value of derivative positions, the purchase price allocation on properties acquired, various common stock, warrants and option transactions, and contingencies.

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 reserves and calculated on a by well basis, based upon reserve reports prepared by an independent petroleum engineer in accordance with SEC rules.

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

The Company recorded impairment expense of $3,721,042 and $640,583 for 2014 and 2013 respectively, upon determining that the oil and natural gas properties were impaired.

Long-lived Assets

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

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

Asset Retirement Obligations:

The Company records the estimate of the fair value of liabilities related to future asset retirement obligations (“ARO”) in the period the obligation is incurred. Asset retirement obligations relate to the removal of facilities and tangible equipment at the end of an oil and natural gas property’s useful life. The application of this rule requires the use of management’s estimates with respect

F-7

to future abandonment costs, inflation, market risk premiums, useful life and cost of capital and required government regulations. U.S. GAAP requires that our estimate of our asset retirement obligations does not give consideration to the value the related assets could have to other parties.

The following table is a reconciliation of the ARO liability for the twelve months ended December 31, 2014 and 2013.



	Years Ended December 31,
	2014			2013
Asset retirement obligation at beginning of period	$	51,954		$	39,905
Liabilities incurred	3,721			8,930
Revisions to previous estimates and sales of properties	(14,821		)	—
Accretion expense	3,360			3,119
Asset retirement obligation at end of period	$	44,214		$	51,954

Other Property and Equipment:

Our office equipment in Austin, Texas is being depreciated on the straight-line method over the estimated useful life of five to seven years.

Cash and Cash Equivalents:

The Company considers all liquid investments with original maturities of three months or less from the date of purchase that are readily convertible into cash to be cash equivalents. The Company had no cash equivalents at December 31, 2014 and 2013 respectively.

Accounts Receivable:

Our accounts receivable are primarily from purchasers of natural gas and oil and exploration and production companies which own an interest in properties we operate.

Allowance for Doubtful Accounts:

The Company recognizes an allowance for doubtful accounts to ensure trade receivables are not overstated due to uncollectibility. Allowance for doubtful accounts are maintained for all customers based on a variety of factors, including the length of time receivables are past due, macroeconomic conditions, significant one-time events and historical experience. An additional allowance for individual accounts is recorded when they become aware of a customer’s inability to meet its financial obligations, such as in the case of bankruptcy filings or deterioration in the customer’s operating results or financial position. If circumstances related to customers change, estimates of the recoverability of receivables would be further adjusted. As of December 31, 2014 and 2013, the Company has deemed 200,000 from the sale of oil and gas properties associated with the Jones County prospect, to be doubtful and thus, has recorded this amount as an allowance for doubtful accounts.

Fair Value:

At December 31, 2014 and 2013, the carrying value of the Company's financial instruments such as prepaid expenses and payables approximated their fair values based on the short-term maturities of these instruments. The carrying value of other liabilities approximated their fair values because the underlying interest rates approximate market rates at the balance sheet dates. Management believes that due to the Company's current credit worthiness, the fair value of debt could be less than the book value; however, due to current market conditions and available information, the fair value of such debt is not readily determinable. Financial Accounting Standard Board ("FASB") ASC Topic 820 established a hierarchical disclosure framework associated with the level of pricing observability utilized in measuring fair value. This framework defined three levels of inputs to the fair value measurement process and requires that each fair value measurement be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. The three broad levels of inputs defined by FASB ASC Topic 820 hierarchy are as follows:

Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;

F-8

Leve1 2 - inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Leve1 2 input must be observable for substantially the full term of the asset or liability; and

Leve1 3 - unobservable inputs for the asset or liability. These unobservable inputs reflect the entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability and are developed based on the best information available in the circumstances (which might include the reporting entity's own data).

The initial measurement of asset retirement obligations is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with proved oil and gas properties. Inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of Victory’s asset retirement obligations is presented in Note 1.

During 2014, proved oil and gas properties with a carrying value of $792,530 were written down, based upon engineering estimates, to their fair value of $658,509 as a result of $3,721,041 in impairment charges. Of this amount, additional impairment charges of $3,587,020 were taken on the Fairway properties, which were written down from a carrying value of $3,826,525 to the fair value of $239,505. During 2013, proved oil and gas properties with a carrying value of $890,818 were written down, based upon engineering estimates, to their fair value of $250,055 resulting from $640,583 of impairment charges. Impairment charges for 2013 were specifically related to the Lightnin' property. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include Victory’s estimate of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data, primarily derived from a third party independent reserve report.

Revenue Recognition:

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

Concentrations:

There is a ready market for the sale of crude oil and natural gas. During 2014 and 2013, our gas field and our producing wells sold their respective gas and oil production to one purchaser for each field or well. However, because alternate purchasers of oil and natural gas are readily available at similar prices, we believe that the loss of any of our purchasers would not have a material adverse effect on our financial results. A majority of the Company’s production and reserves are from the Permian Basin of West Texas.

Earnings per Share:

Basic earnings per share are computed using the weighted average number of common shares outstanding at December 31, 2014. The weighted average number of common shares outstanding was 28,453,976 at December 31, 2014. Diluted earnings per share reflect the potential dilutive effects of common stock equivalents such as options, warrants and convertible securities. Given the historical and projected future losses of the Company, all potentially dilutive common stock equivalents are considered anti-dilutive.

The following table outlines outstanding common stock shares and common stock equivalents.

F-9



	Years Ended December 31,
	2014	2013
Common Stock Shares Outstanding	29,202,826	27,563,619
Common Stock Equivalents Outstanding
Warrants	5,933,454	4,793,454
Stock Options	610,000	150,000
Unconverted Class B Shares	137,932	137,932
Total Common Stock Equivalents Outstanding	6,681,386	5,081,386

Income Taxes:

Stock-Based Compensation:

The Company applies ASC 718, “Compensation-Stock Compensation” to account for the issuance of options and warrants to employees, key partners, directors, officersand Navitus investors. The standard requires all share-based payments, including employee stock options, warrants and restricted stock, be measured at the fair value of the award and expensed over the requisite service period (generally the vesting period). The fair value of options and warrants granted to employees, directors and officers is estimated at the date of grant using the Black-Scholes option pricing model by using the historical volatility of the Company’s stock price. The calculation also takes into account the common stock fair market value at the grant date, the exercise price, the expected term of the common stock option or warrant, the dividend yield and the risk-free interest rate.

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

The Company recognized stock-based directors compensation expense from warrants and stock awards granted to directors for services of $383,674 and $27,060 , for the years ended December 31, 2014 and 2013, respectively.

The Company recognized stock-based incentive compensation expense from stock options granted to officers and employees of the company of $106,500 and $52,106 for the twelve months ended December 31, 2014 and 2013, respectively.

The Company also recognized stock-based general and administrative expense of $81,667 and $0 for the twelve months ended December 31, 2014 and 2013, respectively.

Going Concern:

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. As presented in the consolidated financial statements, the Company has incurred a net loss of $4,229,137 and $2,116,138 during the years ended December 31, 2014 and 2013, respectively. Though non-cash expenses and allowances were significant during the years ended December 31, 2014 and December 31, 2013, the net cash used in operating activities, or negative cash flows from operating activities, were $1,137,222 and $580,275, respectively.

The cash proceeds from the sale of the Company’s Lightnin Property in June 2014 and new contributions to the Aurora partnership by The Navitus Energy Group (“Navitus”) have allowed the Company to continue operations and invest in new oil and natural

F-10

gas properties. See Note 3. Management anticipates that operating losses will continue in the near term until new wells are drilled, successfully completed and incremental production increases revenue. On a year to date basis, as of December 31, 2014 the Company has invested $841,270 in the drilling of wells and $3,214,872 in the acquisition of oil and gas properties.

The Company remains in active discussions with Navitus and others related to longer term financing required for our capital expenditures planned for 2015. Without additional outside investment from the sale of equity securities and/or debt financing, our capital expenditures and overhead expenses must be reduced to a level commensurate with available cash flows.

Note 2 – Recent Accounting Pronouncements

Recently Issued Accounting Standards

Note 3 – Oil and natural gas properties

During 2014 and 2013, the Navitus Energy Group, through its investment in Aurora, contributed $1,140,000 and $2,336,000, respectively. These funds were used primarily for exploration and development of oil and natural gas properties, as well as for other partnership purposes.

Oil and natural gas properties are comprised of the following:

F-11



	December 31,
	2014			2013
Proved property	$	8,903,060		$	7,694,412
Unproved property	1,365,951			321,124
Work in process	—			25,897
Total oil and natural gas properties, at cost	10,269,011			8,041,433
Less: accumulated impairment	(7,430,438		)	(4,325,785		)
Oil and natural gas properties, net of impairment	2,838,573			3,715,648
Less: accumulated depletion	(1,942,380		)	(1,517,836		)
Oil and natural gas properties, net	896,193			2,197,812

Depletion, depreciation, and amortization expense for the years ended December 31, 2014 and 2013 was $430,912 and $378,398, respectively. During the years ended December 31, 2014 and 2013, the Company recorded impairment losses of $3,721,042 and $640,583, respectively.

Note 4 - Acquisitions and Dispositions

Dispositions

On June 5, 2014, Victory, through its controlling interest and as managing partner in Aurora , sold certain leasehold properties and all of Aurora’s related interests in approximately 640 gross and 128 net mineral acres located in Glascock County, Texas (the “Lightnin' Assets”) to an unrelated third party (the “Lightnin' Buyer”) for approximately $4 million in cash gross to Aurora. The sale was made pursuant to a Purchase and Sale Agreement dated as of April 30, 2014 by and among the working interest owner/sellers, including Aurora, and the Lightnin' Buyer. The effective date for the transaction was April 1, 2014. Aurora held a 20% working and 15% net revenue interest in the Lightnin' Assets which were operated by a third party. Estimated daily net production to Aurora's interest was approximately 36 BOEPD (barrels of oil equivalent per day) at the time of the sale from the 3 producing wells. The Company recognized a gain on the sale of the Lightnin' Assets of $2,160,099 in its consolidated statement of operations for the year ended December 31, 2014.

Acquisitions

On June 30, 2014, Aurora completed the First Closing of a purchase of a 10% working and 7.5% net revenue interest in the proved and unproved Permian Basin Fairway Operations from TELA for an initial payment of $2,491,888 in cash, subject to customary purchase price adjustments ( the "Fairway Acquisition"), pursuant to the terms and conditions of the Purchase and Sale Agreement dated June 30, 2014 between Aurora and TELA (the "Fairway PSA"). On the First Closing, TELA assigned certain assets in its Permian Basin Fairway Operation (the “First Closing Assets”) to Aurora. The second closing (the “Second Closing”) was planned to follow the completion of curative title work and was expected in August 2014. On July 31, 2014, the Company made an additional payment related to its Fairway Property acquisition. The payment of $558,246 to the seller of the Fairway properties was a purchase price adjustment made in accordance with the purchase and sale agreement related thereto. On the Second Closing,TELA was to assign the remainder of its assets in its Permian Basin Fairway Operations to Aurora. The Effective Date for the transfer of all assets was May 1, 2014. The acquisition of the First Closing Assets included seven producing wells and four wells completed and awaiting production start-up.

On September 23, 2014, the Company mutually agreed to the termination of the Fairway PSA. Pursuant to the termination of the Fairway PSA, the Second Closing did not occur as the result of certain title impairment issues that were uncovered during the due diligence process and that were not remedied to the satisfaction of the Company and TELA. No penalties or payments were due as a result of the termination of the Fairway PSA. See footnote 14 for further discussion.

In the fourth quarter of 2014, the Company made a final determination as to the purchase price resulting in a final purchase price of $3,214,872. The amount of the total purchase price allocated to undeveloped oil and gas properties was reduced by these adjustments. The adjusted purchase price was allocated as follows:

F-12



	Purchase Price Allocation
Fair Value of Assets Acquired - Tangible and Intangible Well costs	$	2,240,530
Fair Value of Assets Acquired - Proved Producing Leasehold Costs		197,654
Fair Value of Assets Acquired Unproved Leasehold Costs		776,688
Net Asset Fair Value Final	$	3,214,872

The acquisitions qualified as a business combination under ASC 805. The valuation to determine the fair values were principally based on the discounted cash flows of the producing and undeveloped properties, including projected drilling and equipment costs, recoverable reserves, production streams, future prices and operating costs, and risk-adjusted discount rates reflective of the market at the time of acquisition. These measurements of fair value are considered Level 3 measurements because of the significance of unobservable inputs.

Note 5 – Liability for Unauthorized Preferred Stock Issued

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

The Company’s legal counsel determined that the preferred shares had not been duly authorized by the State of Nevada. Since the Company had issued and received consideration for the preferred stock, notwithstanding that the stock was not legally authorized, the Company has presented the preferred stock as a liability in the consolidated balance sheets. The Company has offered to settle the debt with the remaining holders of the unauthorized preferred stock by honoring the terms of conversion of two shares of preferred stock into 100 shares of common stock. The Company intends to cancel the preferred stock once all remaining preferred stockholders have converted.

There were 68,966 and 68,966 shares of unconverted preferred stock outstanding at December 31, 2014 and 2013, respectively. The Company needs approximately 138,000 common shares in order to settle the outstanding debt as stated below.

The remaining liability for the unconverted preferred stock is based on the original cash tendered and consisted of the following as of:



	December 31,
	2014		2013
Liability for unauthorized preferred stock	$	9,283	$	9,283

F-13

Note 6 - Revolving Credit Agreement

On February 20, 2014, Aurora, as borrower, entered into the Credit Agreement with Texas Capital Bank (“the Lender”). Guarantors on the Credit Agreement are Victory and Navitus, the two partners of Aurora. Pursuant to the Credit Agreement, the Lender agreed to extend credit to Aurora in the form of (a) one or more revolving credit loans (each such loan, a “Loan”) and (b) the issuance of standby letters of credit, of up to an aggregate principal amount at any one time not to exceed the lesser of (i) $25,000,000 or (ii) the borrowing base in effect from time to time (the “Commitment”). The initial borrowing base on February 20, 2014 was set at $1,450,000. The borrowing base is determined by the Lender, in its sole discretion, based on customary lending practices, review of the oil and natural gas properties included in the borrowing base, financial review of Aurora, the Company and Navitus and such other factors as may be deemed relevant. The borrowing base is re-determined (i) on or about March 31 of each year based on the previous December 31 reserve report prepared by an independent reserve engineer, and (ii) on or about September 30 of each year based on the previous June 30 reserve report prepared by Aurora’s internal reserve engineers or an independent reserve engineer and certified by an officer of Aurora. The Credit Agreement will mature on February 20, 2017. Amounts borrowed under the Credit Agreement will bear interest at rates equal to the lesser of (i) the maximum rate of interest which may be charged or received by the Lender in accordance with applicable Texas law and (ii) the interest rate per annum publicly announced from time to time by the Lender as the prime rate in effect at its principal office plus the applicable margin. The applicable margin is, (i) with respect to Loans, one percent (1.00%) per annum, (ii) with respect to letter of credit fees, two percent (2.00%) per annum and (iii) with respect to commitment fees, one-half of one percent (0.50%) per annum. Loans made under the Credit Agreement are secured by (i) a first priority lien in the oil and gas properties of Aurora, the Company and Navitus, and (ii) a first priority security interest in substantially all of the assets of Aurora and its subsidiaries, if any, as well as in 100% of the partnership interests in Aurora held by the Company and Navitus. Loans made under the Credit Agreement to Aurora are fully guaranteed by the Company and Navitus.

The Credit Agreement contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, additional liens and transactions with affiliates. Among the covenants contained in the Credit Agreement are financial covenants that Aurora will maintain a minimum EBITDAX to Cash Interest Ratio of 3.5 to 1.0 and a minimum Current Ratio of not less than 1.0 to 1.0. The Current Ratio is defined under the covenants to include, as a current asset, the revolving credit availability. At September 30, 2014, Aurora's Current Ratio was 0.10 to 1 and it was therefore not in compliance with the aforementioned Current Ratio covenant requiring a ratio of current assets to current liabilities of not less than 1 to 1. Aurora notified the Lender of its noncompliance with the Current Ratio covenant and the Lender instructed the Company to fully explain its plans to come back into compliance with the Current Ratio covenant in the September 30, 2014 Compliance Certificate, which is made upon filing of the Company’s September 30, 2014 SEC Form 10-Q filing.

On November 19, 2014, Aurora entered into a Waiver of Event of Default (the “Waiver Agreement”) with the Lender. Under the terms of the Waiver Agreement, the Lender agreed to waive an event of default under the Loan Agreement resulting from Aurora’s failure to maintain a current ratio of at least 1.00 to 1.00 as of the end of the fiscal quarter ending September 30, 2014 subject to certain conditions set forth therein, including the receipt by Aurora by December 1, 2014 of Navitus of at least $1.5 million to be used to reduce Aurora's outstanding liabilities. As of December 1, 2014, the required equity contributions from Navitus had not been received by Aurora, therefore the Lender had the right but not the obligation to elect certain remedies, including, among other things, the acceleration of all amounts due under the Credit Agreement. As a result, the $800,000 outstanding balance of the Credit Agreement was classified as a current liability in accordance with GAAP. As of December 31, 2014, the Company remained out of compliance with the current ratio covenant noted previously and has notified the Lender of such. As of March 17, 2015, Texas Capital Bank has waived the Existing Events of Default.

The Company has fully utilized its borrowing base as of December 31, 2014. During the first quarter ended March 31, 2014 and second quarter ended June 30, 2014, Aurora drew $868,000, and $365,000 respectively, of the initial $1,450,000 borrowing base. In May 2014, revisions to the Credit Agreement lowered the borrowing base from $1,450,000 to $800,000 due to the sale of the Lightnin’ properties. In effect, Victory was obligated to pay $433,000 of the $1.23 million in credit loans utilized to meet the requirements of the new borrowing base.

Amortization of debt financing costs on this debt for the twelve months ended December 31, 2014, was $34,586. Interest expense for the twelve months ended December 31, 2014, was $30,595.

Note 7 – Income Taxes

There was no provision for (benefit of) income taxes for the years ended December 31, 2014 and 2013, after the application of ASC 740 “Income Taxes.”

The Internal Revenue Code of 1986, as amended, imposes substantial restrictions on the utilization of net operating losses in the event of an “ownership change” of a corporation. Accordingly, a company’s ability to use net operating losses may be limited as

F-14

prescribed under Internal Revenue Code Section 382 (“IRC Section 382”). Events which may cause limitations in the amount of the net operating losses that the company may use in any one year include, but are not limited to, a cumulative ownership change of more than 50% over a three-year period. There have been transactions that have changed the Company’s ownership structure since inception that may have resulted in one or more ownership changes as defined by the IRC section 382. The Company’s stock issuance arising from convertible debt in 2012 has resulted in a limitation of net operating loss carry forward for the Company of $15,100,156 over a 20 year period.

At December 31, 2014, the Company had available Federal operating loss carry forwards to reduce future taxable income. Additional Federal net operating loss carry forward of $2,655,792 for 2014 would make available approximately $17,755,948 as of December 31, 2014. The Federal net operating loss carry forwards begin to expire in 2028. Capital loss carryovers may only be used to offset capital gains.

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 net operating loss carry forwards. ASC 740 requires that a valuation allowance be established when it is more likely than not that all or a portion of deferred tax assets will not be realized.

Accordingly, the Company has recorded a full valuation allowance against its net deferred tax assets at December 31, 2014 and 2013, respectively. Upon the attainment of taxable income by the Company, management will assess the likelihood of realizing the deferred tax benefit associated with the use of the net operating loss carry forwards and will recognize a deferred tax asset at that time.

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



	December 31, 2014			December 31, 2013
Net operating loss carryforward	$	6,037,022		$	5,134,053
Accounts payable and accrued expenses	894,895			195,899
Equity based expenses	1,912,720			1,727,412
Accounts receivable and prepaid expenses	(63,845		)	(76,017		)
Deferred taxes	8,780,792			6,981,347
Valuation allowance	(8,780,792		)	(6,981,347		)
Net Deferred Income Tax Assets	$	—		$	—

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



	12/31/2014		12/31/2013
Net operating loss	(34	)%	(34	)%
Meals and entertainment	0.15	%	0.05	%
Debt discount accretion	0.10	%	—	%
Net operating loss reduction due IRC 382	—		—	%
Change in valuation allowance	33.75	%	33.95	%
Effective income tax rate	—	%	—	%

ASC 740 provides guidance which addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the consolidated financial statements. Under the current accounting guidelines, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the consolidated financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. As of December 31, 2014 and 2013 the Company does not have a liability for unrecognized tax benefits.

The Company has elected to include interest and penalties related to uncertain tax positions as a component of income tax expense. To date, no penalties or interest has been accrued.

Tax years 2011 forward are open and subject to examination by the Federal taxing authority. The Company is not currently under examination and it has not been notified of a pending examination.

F-15

Note 8 – Stockholders’ Equity

Long-Term Incentive Plan

On February 24, 2014, the Board of Directors (the “Board”) of the Victory Energy Corporation (the “Company”) approved and adopted the Victory Energy Corporation 2014 Long Term Incentive Plan (the “LTIP”) for the employees, directors and consultants of the Company and its affiliates. The LTIP provides for the grant of all or any of the following components: (1) stock options, (2) restricted stock, (3) other stock-based awards, (4) performance awards and (6) dividends and dividend equivalents. Subject to adjustment in accordance with the LTIP, the maximum aggregate number of shares of the common stock of the Company, par value $0.001 per share (the “Common Stock”) that may be issued with respect to awards under the LTIP is fifteen percent (15%) of the outstanding shares of Common Stock at the end of the preceding calendar quarter, of which the maximum number of such shares that may be issued as incentive stock options, as defined in Section 422(b) of the Internal Revenue Code of 1986 is two million (2,000,000) shares of Common Stock. Common Stock withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIP will be administered by the Board, until such time as a compensation committee of the Board is established (the “Compensation Committee”), at which time the LTIP will be administered by the Compensation Committee. The total number of shares of common stock initially available for issuance under the LTIP was 4,134,542. As of December 31, 2014, 350,000 shares of restricted stock, 1,350,000 shares of unrestricted common stock and 400,000 options were issued under the LTIP. The maximum contractual term is five years. The Company values all grants using the Black Scholes pricing model.

Common stock

The Company estimates the fair value of employee stock options and warrants granted using the Black-Scholes Option Pricing Model. Key assumptions used to estimate the fair value of warrants and stock options include the exercise price of the award, the fair value of the Company’s common stock on the date of grant, the expected warrant or option term, the risk free interest rate at the date of grant, the expected volatility and the expected annual dividend yield on the Company’s common stock.

During the year ended December 31, 2014, the Company granted 1,350,000 stock awards to directors, officers, and employees using the Black Scholes Option Pricing Model, at $452,675.

During the year ended December 31, 2014, the Company granted 400,000 employee stock options and has valued the stock options using the Black Scholes Option Pricing Model, at $131,250.

During the year ended December 31, 2014, the Company granted 1,140,000 warrants for $1,140,000 in capital contributions through Navitus Partners, LLC.

During the year ended December 31, 2014, the Company granted 350,000 shares of stock for consulting services valued with the Black Scholes pricing model at $122,500.

Note 9 – Warrants for Stock

At December 31, 2014 and 2013 warrants outstanding for common stock of the Company were as follows:



	Number of Shares Underlying Warrants		Weighted Average Exercise Price
Balance at January 1, 2014	4,931,386		$	0.76
Granted	1,140,000		0.30
Exercised	—		—
Canceled	(134,000	)	1.10
Balance at December 31, 2014	5,937,386		$	0.66

F-16



	Number of Shares Underlying Warrants		Weighted Average Exercise Price
Balance at January 1, 2013	2,695,386		$	1.15
Granted	2,516,000		0.28
Exercised	—		—
Canceled	(280,000	)	0.83
Balance at December 31, 2013	4,931,386		$	0.76

The following table summarizes information about underlying outstanding warrants for common stock of the Company outstanding and exercisable as of December 31, 2014:



	Warrants Outstanding				Warrants Exercisable
Range of Exercise Prices	Number of Shares Underlying Warrants	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (in years)	Number of Shares Underlying Warrants	Weighted Average Exercise Price
$12.50 – $17.50	125,245	$	13.03	6.62	125,245	$	13.03
$0.13 – $2.50	5,812,141	$	0.39	3.17	5,812,141	$	0.31
	5,937,386				5,937,386

The following table summarizes information about underlying outstanding warrants for common stock of the Company outstanding and exercisable as of December 31, 2013:



	Warrants Outstanding				Warrants Exercisable
Range of Exercise Prices	Number of Shares Underlying Warrants	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (in years)	Number of Shares Underlying Warrants	Weighted Average Exercise Price
$12.50 – $17.50	125,245	$	13.03	7.60	125,245	$	13.03
$0.25 – $2.50	4,806,141	$	0.43	2.90	4,806,141	$	0.43
	4,931,386				4,931,386

These common stock purchase warrants do not trade in an active securities market, and as such, we estimate the fair value of these warrants using the Black-Scholes Option Pricing Model using the following assumptions:



	2014		2013
Risk free interest rates	0.77% – 1.73%		0.76% – 0.92
Expected life	5 years		5 years
Estimated volatility	629.8% – 788.7%		793.4% – 866.2%
Dividend yield	—	%	—	%

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

At December 31, 2014 and 2013 the aggregate intrinsic value of the warrants outstanding and exercisable was $5,295 and $17,850, respectively. The intrinsic value of a warrant is the amount by which the market value of the underlying warrant exercise price exceeds the market price of the stock at December 31 of each year.

Note 10 – Stock Options

The following table summarizes stock option activity in the Company’s stock-based compensation plans for the year ended December 31, 2014. All options issued were non-qualified stock options.



	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (1)		Number of Options Exercisable	Weighted Average Fair Value At Date of Grant
Outstanding at December 31, 2012	220,000		$	0.84	$	—	80,000
Granted at Fair Value	60,000		$	0.25			60,000	$	0.25
Exercised	—		—
Forfeited	(130,000	)	$	0.25			—
Outstanding at December 31, 2013	150,000		$	0.25	$	—	150,000
Granted at Fair Value	400,000		$	0.33			322,922
Exercised	—		—
Forfeited	—		$	—			—
Outstanding at December 31, 2014	550,000		$	0.41	$	—	472,922


(1)	The intrinsic value of a stock option is the amount by which the market value of the underlying stock exceeds the exercise price of the option at December 31, 2014. If the exercise price exceeds the market value, there is no intrinsic value.

The fair value of the stock option grants are amortized over the respective vesting period using the straight-line method and assuming no forfeitures and cancellations.

Compensation expense related to stock options included in Exploration Expense and General and Administrative Expense in the accompanying consolidated statements of operations for the years ended December 31, 2014 and December 31, 2013, was $490,174, and $52,106, respectively.

Stock options are granted at the fair market value of the Company’s common stock on the date of grant. Options granted to officers and other employees vest immediately or over 36 months as provided in the option at the date of grant.

The fair value of each option granted in 2014 and 2013 was estimated using the Black-Scholes Option Pricing Model. The following assumptions were used to compute the weighted average fair value of options granted during the periods presented.



	2014		2013
Expected term of option	3 to 5 years		5 years
Risk free interest rates	0.8	%	0.8	%
Estimated volatility	629.8 - 785.7		817.60
Dividend yield	—	%	—	%

The following table summarizes information about stock options outstanding at December 31, 2014:



Range of Exercise Prices	Number of Options	Weighted Average Remaining Contractual Life (Years)	Weighted Average Exercise Price		Aggregate Intrinsic Value (1)		Number Exercisable	Weighted Average Exercise Price of Exercisable Options		Aggregate Intrinsic Value (1)
$0.30 - $1.00	550,000	2.00	$	0.49	$	—	472,922	$	0.41	$	—


(1)	The intrinsic value of a stock option is the amount by which the market value of the underlying stock exceeds the exercise price of the option at December 31, 2013. If the exercise price exceeds the market value, there is no intrinsic value.

F-17

The following table summarizes information about options outstanding at December 31, 2013:



Range of Exercise Prices	Number of Options	Weighted Average Remaining Contractual Life (Years)	Weighted Average Exercise Price		Aggregate Intrinsic Value (1)		Number Exercisable	Weighted Average Exercise Price of Exercisable Options		Aggregate Intrinsic Value
$0.35 - 1.00	150,000	3.60	$	0.64	$	—	150,000	$	0.64	$	—

A summary of the Company’s non-vested stock options at December 31, 2014 and December 31, 2013 and changes during the years are presented below.



Non-Vested Stock Options	Options	Weighted Average Grant Date Fair Value
Non-Vested at December 31, 2013	—	$	0.35
Granted	400,000	$	0.35
Vested	14,378	$	0.35
Forfeited	—	$	—
Non-Vested at December 31, 2014	—	$	0.35

Note 11 – Commitments and Contingencies

Leases

Rent expense for the years ended December 31, 2014 and 2013 was $28,500 and $27,750, respectively. Future annual minimum payments under non-cancellable operating leases are $0 and $0 for the years ending December 31, 2015 and 2016, respectively.

Partnership Distributions

Under terms of the Second Amended Partnership Agreement of Aurora, Navitus Energy Group earns a net profit interest respective to its 50% partnership interest. In addition, Navitus Energy Group is entitled to a respective proportion of proceeds from the sale of Aurora assets. Any distributions of the net profits interest or asset sale proceeds to partners are at the discretion of Victory, as managing partner, together with 100% of the partnership interests. The accumulated net deficits of Navitus, along with historical contributions, net of paid distributions, are reported as non-controlling interests in the equity section of the condensed consolidated financial statements.

The table below summarizes the net profit distributions, proceeds of asset sales and preferred return distributions earned by Navitus Energy Group during the years ended December 31, 2014 and 2013, respectively.



Navitus Energy Group Distribution Earned	The Year Ended December 31,
	2014		2013
Aurora Net Profit Interests	$	41,895	$	58,397
Proceeds from the Sale of Aurora Assets	1,824,398		220,772
Preferred Distributions Due to Navitus Partners, LLC	401,081		232,373
Total Distributions Earned By Navitus Energy Group	$	2,267,374	$	511,542

F-18



Payments Made to Navitus Energy Group	The Year Ended December 31,
	2014		2013
Distributions of Aurora Net Profits	$	86,517	$	—
Proceeds from the Sale of Aurora Assets	219,029		—
Preferred Distributions Due to Navitus Partners, LLC	341,876		—
Total Distributions Paid By Navitus Energy Group	$	647,422	$	—

Navitus Partners, LLC, a partner in Navitus, also receives warrants for Victory’s common stock, allocated as 50,000 warrants for every Unit purchased under the Navitus PPM (equivalent of 1 warrant for every $1.00 invested), exercisable under the terms of Aurora’s Second Amended Partnership Agreement and the Navitus PPM. Since August 23, 2012, $4,415,900 of capital contributions have resulted in issuance of 4,415,900 common stock warrants (1,089,900 in 2012, 2,186,000 in 2013, and 1,140,000 in 2014).

Litigation

Cause No. 8-4-7047-CV; Oz Gas Corporation v. Remuda Operating Company, et al. v. Victory Energy Corporation.; In the 112th District Court of Crockett County, Texas.

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.

Victory has added a few more parties to this lawsuit. Discovery is ongoing in this case and no trial date has been set at this time.

Victory believes they will be victorious against all the remaining Defendants in this case.

Cause No. 10-9-7213; Perry Howell, et al. v. Charles Gary Garlitz, et al.; In the 112th District Court of Crockett County, Texas.

F-19

Cause No. D-1-GN-13-44; Aurora Energy Partners and Victory Energy Corporation v. Crooked Oaks; In the 261st District Court of Travis County, Texas.

Victory Energy Corporation sued Crooked Oaks, LLC a/k/a Crooked Oak, LLC for breach of a purchase and sale agreement dated May 7, 2012 in which Victory sold certain assets to Crooked Oaks, LLC. The lawsuit seeks to recover $200,000.00 from Crooked Oaks, LLC in addition to attorney’s fees and all costs of court. Crooked Oaks, LLC has asserted a counterclaim for rescission of the underlying contract.

Victory believes it will ultimately recover this receivable.

Note 12 – Related Party Transactions

During the year ended December 31, 2014 and 2013, we incurred a total of $0 and $19,900, respectively, of accounting services with Miranda & Associates, a Professional Accountancy Corporation (“Miranda”). As of December 31, 2014 and 2013, Miranda was owed $0 and $6,000, respectively, for these professional services. One of our former directors, Robert J. Miranda, is the managing director of Miranda. Mr. Miranda resigned from our Board of Directors in October 2013.

During the year ended December 31, 2014 and 2013 we incurred a total of $281,585 and $206,456 in legal fees with The McCall Firm. David McCall, our general counsel and a director, is a partner in The McCall Firm. The fees are attributable to litigation involving the Company’s oil and natural gas operations in Texas. As of December 31, 2014, the Company owed The McCall Firm approximately $82,935 for these professional services.

During the year ended December 31, 2014 we incurred a total of $10,953 in consulting fees with Patrick Barry, for which there was no balance owed as of December 31, 2014.

During the year ended December 31, 2014, a member of management made a $5,000 temporary advance to the Company.

During the year ended December 31, 2014, the following temporary capital advances totaling $390,000 had been made by Navitus Energy Group Partnership:



November 30, 2014	$250,000
December 9, 2014	$40,000
December 31, 2014	$100,000
Total Advances	$390,000

As of July 1, 2014, Ralph Kehle was appointed as a Board of Director for the Company. During this time, Mr. Kehle was also the Chairman of the Board for TELA (USA), Inc. Aurora and TELA entered into a letter of intent on May 8, 2014 and followed by entering into a Purchase and Sale Agreement dated June 30, 2014 for the Fairway Acquisition. Mr. Kehle received 95,000 shares of common stock, valued at $32,200, for his board services as of December 31, 2014. Mr. Kehle resigned from our Board of Directors in December 2014.

Note 13 – Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited)

The following disclosures provide unaudited information required by ASC 932, “Extractive Activities – Oil and Gas” on oil and natural gas producing activities. These disclosures include non-controlling interests in Aurora which is managed and owned 50% by Victory.

Results of operations from oil and natural gas producing activities (Successful Efforts Method)

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

F-20



	Years Ended December 31,
	2014			2013
Revenues	$	695,318		$	735,413
Costs incurred:
Exploration and dry hole costs	56,351			112,123
Lease operating costs and production taxes	225,074			247,350
Impairment of oil and natural gas reserves	3,721,042			640,583
Depletion, depreciation and accretion	430,912			378,398
Totals, costs incurred	4,433,379			1,378,454
Pre-tax (loss) from producing activities	(3,738,061		)	(643,041		)
Results (loss) from of oil and natural gas producing activities (excluding overhead, income taxes, and interest costs)	$	(3,738,061	)	$	(643,041	)

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



	Years Ended December 31,
	2014		2013
Property acquisition and developmental costs:
Development	$	841,270	$	2,346,482
Property Acquisition	3,214,872		81,550
Undrilled leaseholds	22,577		—
Asset retirement obligations	3,721		8,930
Totals costs incurred	$	4,082,440	$	2,436,962

Oil and natural gas reserves

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

Proved oil and natural gas reserve quantities at December 31, 2014 and 2013 and the related discounted future net cash flows are based on estimates prepared by independent petroleum engineers. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission.

Standardized measure of discounted future net cash flows relating to proven oil and gas reserves (SMOG)

The following information has been prepared in accordance with SFAS 69 and the regulations of the Securities and Exchange Commission, which require the standardized measure of discounted future cash flows based on sales prices, costs and statutory interest rates. The standardized measure of oil and gas producing activities is the present value of estimated future cash inflow from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted to reflect timing of future cash flows.

The Company’s proved oil and natural gas reserves for the years ended December 31, 2014 and December 31, 2013 are shown below:

F-21



	Years Ended December 31,
Volumes	2014		2013
Natural gas:	(Mcfs)
Proved developed and undeveloped reserves (mcf):
Beginning of year	723,190		679,410
Purchase (sale) of natural gas properties in place	(46,770	)	(6,004	)
Discoveries and extensions	—		66,680
Revisions	(30,843	)	27,937
Production	(45,577	)	(44,833	)
Proved reserves, at end of year (a)	600,000		723,190



	Years Ended December 31,
	2014		2013
Oil:	(Bbls)
Proved developed and undeveloped reserves:
Beginning of year	49,020		24,290
Purchase (sale) of oil producing properties in place	(26,290	)	(2,430	)
Discoveries and extensions	1,175		30,550
Revisions	3,700		2,420
Production	(6,905	)	(5,810	)
Proved reserves, at end of year (a)	20,700		49,020


(a)	Includes 300,000 Mcf and 10,350 bbl and 361,595 Mcf and 24,510 bbl for the twelve months ended December 31, 2014 and 2013, respectively of proved reserves attributable to a consolidated subsidiary in which there is a 50% non-controlling interest.



	Years Ended December 31,
Values	2014			2013
Future cash inflows	$	4,920,190		$	8,174,120
Future costs:
Production	2,144,600			(3,387,700		)
Development	87,650			(555,650		)
Future cash flows	2,687,940			4,230,770
10% annual discount for estimated timing of cash flow	(1,223,370		)	1,808,670
Standardized measure of discounted cash flow (a)	$	1,464,570		$	2,422,100


(a)	Includes $732,285 and $1,211,050 for the twelve months ended December 31, 2014 and 2013, respectively of discounted cash flows attributable to a consolidated subsidiary in which there is a 50% non-controlling interest.

Using the SEC adjusted guidelines in place for 2014, the gas and oil prices for this analysis were set at the average price received on the “first-day-of-the-month” for 2014, for appropriate differentials. The “benchmark” prices are $94.99 per barrel and $4.35 per Mcf. The average quarterly quarterly price received for natural gas for 2014 ranged from $4.55 /Mcf to $5.97 /Mcf . The average quarterly price received oil for 2014 ranged from $58.70/bbl to $82.93/bbl.

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

The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair value may also take into account, among other things, the

F-22

recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and may require a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

Changes in standardized measure

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

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



	For the years ended December 31,
	2014			2013
Increase (decrease)
Sale of gas and oil, net of operating expenses	$	(470,244	)	$	(473,159	)
Discoveries, extensions and improved recovery, net of future production and development costs	—			888,160
Accretion of discount	242,210			261,779
Net increase (decrease)	$	(228,034	)	$	676,780
Standardized measure of discounted future cash flows:
Beginning of the year	$	2,422,100		$	1,745,320

Before Income Taxes	$	1,464,570		$	2,422,100
Income Taxes	(500,586		)	(823,500		)
End of the year (a)	$	963,984		$	1,598,600


(a)	Includes $481,992 and $799,300 for the twelve months ended December 31, 2014 and 2013, respectively of future net cash flows attributable to a consolidated subsidiary in which there is a 50% non-controlling interest.

Note 14 - Subsequent Events

On February 4, 2015, Victory Energy Corporation entered into a letter of intent relating to a proposed business combination with Lucas Energy, Inc. The business combination is contingent on the signing of a definitive merger agreement, which will contain customary terms and conditions. The business combination will involve the issuance of equity by Lucas to Victory’s shareholders with no cash payment being made. The parties also expect that upon completion of the business combination, the shareholders of Victory and Victory’s partner Navitus Energy Group will own more than a majority of outstanding Lucas shares.

The letter of intent contains a binding exclusivity provision that requires the two companies to work toward a definitive merger agreement to the exclusion of other potential merger partners. Victory and Lucas also entered into funding agreements, as noted below, to provide the capital necessary for Lucas to satisfy its obligations for several Eagle Ford wells, critical accounts payable and to provide Lucas with necessary working capital during the period prior to the consummation of the business combination. The funding is expected to come from a variety of sources, including certain affiliates of Victory. These sources anticipate total funding needs of approximately $12 million during the business combination with additional funding for post-closing debt reduction and expansion to exceed $8 million.

On February 26, 2015, Victory Energy Corporation entered into (a) the Pre-Merger Collaboration Agreement (the “Collaboration Agreement”) by and between Victory, Lucas Energy, Inc. (“Lucas”), Aurora Energy Partners (“Aurora”, of which the Company owns 50%), Navitus Energy Group (which owns the other 50% of Aurora) and AEP Assets, LLC, a wholly-owned subsidiary of Aurora (“Sub”); and (b) the Pre-Merger Loan and Funding Agreement between Victory and Lucas (the “Loan Agreement”). Subsequently the parties entered into Amendment No. 1 to the Pre-Merger Collaboration Agreement on March 3, 2015 (the “First Amendment to Collaboration Agreement”), which amendments affected thereby are included in the discussion of the Collaboration Agreement below. Victory and Lucas are parties to a letter of intent setting forth certain non-binding terms and conditions pursuant to which it is planned that the Company and Lucas will effectuate a business combination (the “Combination”), subject to among

F-23

other things, the parties completing due diligence, the mutual negotiation of definitive documents, regulatory approvals and the registration of the securities to be issued to the shareholders of the combined company resulting from the Combination (the “Combined Company”).

Pursuant to the Pre-Merger Loan and Funding Agreement, Victory agreed to loan Lucas up to $2 million, with $250,000 initially loaned and, pursuant to the Collaboration Agreement Lucas agreed to assign to the Company all right and interest to five (5) Penn Virginia wells that are scheduled to be funded in February through March 2015 and go into production in April 2015 and two (2) Earthstone Energy/Oak Valley Resources wells that are scheduled to be funded on or before April 1, 2015 and begin production in June or July of 2015, located in Karnes, Lavaca and Gonzales Counties, Texas (the “Well Rights”). Immediately upon the funding by Sub of certain funding requirements associated with the Well Rights (as set forth in greater detail in the Collaboration Agreement, the “Well Funding Requirements”), the Company is required to assign the Well Rights to Aurora, and Aurora is required to assign such Well Rights to Sub. On March 2, 2015, payments of $195,928 and $317,027 were made by Aurora Energy Partners, on behalf of the Sub, to Earthstone Energy/Oak Valley Resources and Penn Virginia, respectively, pursuant to the above mentioned Pre-Merger Collaboration Agreement.

If the Combination is consummated, then Sub shall become a direct or indirect subsidiary of the Combined Company. If the letter of intent is terminated and/or if a subsequent definitive agreement is entered into and thereafter terminated such that the Combination does not occur, then Sub shall retain ownership of the Well Rights and Lucas shall have no claim whatsoever to the Well Rights.

The Initial Draw, and any other amounts borrowed under the Pre-Merger Loan and Funding Agreement are evidenced by a Secured Subordinated Delayed Draw Term Note issued by Lucas in favor of Victory, which is in an initial amount of $250,000 (the “Draw Note”). Borrowings evidenced by the Draw Note accrue interest at 18%, with accrued interest payable in one lump sum on maturity. The maturity date of the Draw Note is February 26, 2016 and Lucas has the right to pre-pay any amounts owed under the Draw Note at any time with ten days prior written notice to the Victory. Upon the occurrence of an event of default (as described in the Draw Note), the interest rate increases by 5% per annum, Victory can declare the entire outstanding balance of the Draw Note immediately due and payable, and can further take actions to enforce its security interests in the Pledged Shares (as defined below).

Amounts owed under the Draw Note are secured by the pledge of shares of the Lucas’ common stock pursuant to the terms of a Pledge Agreement between the Lucas as pledgor and Victory as secured party (the “Pledge Agreement”). Shares pledged pursuant to the Pledge Agreement are to be issued from Lucas’ treasury in the name of Lucas and held by the Company to secure the repayment of the Draw Note. The number of shares required to be pledged by Lucas from time to time under the Pledge Agreement is equal to the amount of each draw under the Pre-Merger Loan and Funding Agreement divided by the volume weighted average closing stock price of Lucas common stock (the “VWAP”) on the twenty trading days prior to the closing date of each such draw. Based on the VWAP for the twenty trading days prior to the date of the Initial Draw, Lucas was required to pledge 1,100,655 restricted shares to Victory (the “Pledged Shares”) to secure the repayment of the $250,000 Initial Draw. Amounts owed under the Draw Note are also required to be guaranteed by any subsidiaries Lucas forms or acquires in the future pursuant to the terms of a Subsidiary Guaranty, provided that as of the date of this filing Lucas does not have any subsidiaries. The Pledged Shares constitute treasury shares and unless and until there is a default under the Loan Agreement or the Draw Note or a failure to satisfy any other obligation thereunder, the Pledged Shares may not be voted by Victory or Lucas.

Pursuant to the above a total of $250,000 was paid to Lucas through March 4, 2015.

Borrowings under the Pre-Merger Loan and Funding Agreement are at the discretion of Lucas, provided that the total number of shares of common stock of the Company issuable as collateral under the Pledge Agreement may not exceed 19.9% of the total number of outstanding shares of the Lucas’ common stock as of February 26, 2015, unless the Lucas receives shareholder approval consistent with the rules of the NYSE MKT. Notwithstanding the above, the Loan Agreement requires Lucas and Victory to operate in accordance with a mutually agreed to 12 month budget (the “Budget”), which governs the timing and use of amounts borrowed under the Loan Agreement. The Budget is intended to prioritize the payment of expenses in a manner designed to ensure that the Combination is consummated. The Budget governs the utilization of Lucas’ cash and credit during the period prior to the consummation of the Combination and provides a monthly breakdown of expenses and uses of cash and credit available to Lucas. Lucas is not allowed to use any of its cash or credit to make payments to any third parties except in accordance with the Budget.

The Collaboration Agreement also required us to provide Louise H. Rogers, Lucas’ senior lender, a Contingent Promissory Note in the amount of $250,000, which accrues interest at the rate of 18% per annum. The Contingent Promissory Note is due and

F-24

payable within ninety days following the earlier of (a) the date the letter of intent is terminated, or if a subsequent definitive agreement is entered into and thereafter terminated such that the Combination does not occur, the date ninety days from the termination date of such definitive agreement, or (b) the failure of the Sub to satisfy the Well Funding Requirements, which failure is not cured within sixty (60) days of Sub receiving written notice from the Company of such failure. In connection with the issuance of the Contingent Promissory Note, the lender agreed to release the Well Rights from its security interest in order to accommodate the transactions contemplated by the Collaboration Agreement and Loan Agreement.

The foregoing description of the Pre-Merger Collaboration Agreement, Pre-Merger Loan and Funding Agreement, Pledge Agreement, Contingent Pay Note, and First Amendment to Collaboration Agreement, are qualified in their entirety by reference to the full text thereof which are filed as Exhibits 10.1, 10.2, 10.3, 10.4, and 10.5, to the Company’s Form 8-K filed March 3, 2015.

During the period of January 1, 2015 through and March 31, 2015, additional capital investments of $1,875,000 were received. This resulted in the issuance of an additional 1,850,000 common stock warrants for the purchase of shares of common stock of the Company. Also during the period January 1, 2015, and February 28, 2015, related party payables were reduced by$360,000 by repayments with $150,000 still outstanding currently.

On January 9, 2015, Cause No. 50198, Trilogy Operating, Inc. v. Aurora Energy Partners, was filed in the 118th District Court of Howard County, Texas. This lawsuit alleges causes of action for declaratory judgment, breach of contract, and suit to quiet title regarding the drilling and completion of four wells. On or about February 12, 2015, the parties met at an informal settlement conference. At the adjournment of the meeting, Trilogy was to provide Aurora with a detailed accounting before proceeding forward. The accounting provided by Trilogy was not helpful and Aurora has asked for an audit under the terms set out in the Joint Operating Agreement. Discovery is ongoing in this case and no trial date has been set at this time. Victory does not believe that all of Plaintiff’s claims have merit, and thus an audit is needed before proceeding any further.

On January 30, 2015 and supplemented on March 4, 2015, Cause No. 2015-05280, TELA Garwood Limited, LP. v. Aurora Energy Partners, Victory Energy Corporation, Kenneth Hill, David McCall, Robert Miranda, Robert Grenley, Ronald Zamber and Patrick Barry, in the 164th District Court of Harris County, Texas. This lawsuit alleges breach of contract regarding a Purchase and Sale Agreement that TELA Garwood Limited, LP and Aurora Energy Partners entered into on June 30, 2014. A first closing was held on June 30, 2014 and a purchase price adjustment payment was made on July 31, 2014. Between these two dates Aurora paid TELA $3,050,133. A second closing was to take place in September, however several title defects were found to exist. The title defects could not be cured and a purchase price reduction could not be agreed upon by the parties in relation to the title defects, therefore, the second closing was terminated by TELA. Aurora and Victory have filed an answer in this case. Discovery is ongoing in this case and no trial date has been set. Aurora and Victory believe they will be successful in this suit as TELA was in breach of the Purchase and Sale Agreement during negotiations of and on the date of signing the agreement.

On February 12, 2015, the Company entered into a six month consulting agreement with Highgate Capital, LLC. to assist with corporate strategy. In conjunction with this agreement, the Company has agreed to issue 400,000 shares of restricted stock on a stipulated vesting schedule over a six month time period.

F-25

VICTORY OILFIELD TECH, INC. - FORM 10-K - March 31, 2015

Attached files

VICTORY OILFIELD TECH, INC. Reports