Unassociated Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal years ended December 31, 2009, 2008 and 2007 (Cumulative Filing)
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from ____________ to _____________
Commission file number: 002-76219NY
VICTORY ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
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Nevada
(State or other jurisdiction of incorporation or organization)
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87-0564472
(I.R.S. Employer Identification No.)
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20341 Irvine Avenue, Newport Beach, California
(Address of principal executive offices)
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92660
(Zip Code)
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Registrant’s telephone number, including area code: (714) 480-0305
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $0.001 par value
(Title of class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ¨ No x
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No x
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
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Large Accelerated Filer ¨
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Accelerated Filer ¨
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Non-Accelerated Filer (do not check if Smaller Reporting Company) ¨
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Smaller Reporting Company x
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The aggregate market value of the voting common equity held by non-affiliates of the registrant, computed by reference to the closing price of such stock on March 28, 2011 was approximately was $2,324,233 based on the closing price of such stock and such date of $0.017.
The number of shares outstanding of the Registrant’s common stock, $0.001 par value, as of March 28, 2011 was 136,719,608.
VICTORY ENERGY CORPORATION
ANNUAL REPORT ON
FORM 10-K
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
TABLE OF CONTENTS
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Page
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PART I
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Item 1.
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Business
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3
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Risk Factors.
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11
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Item 1B.
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Unresolved Staff Comments.
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23
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Item 2.
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Properties.
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24
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Item 3.
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Legal Proceedings.
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30
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Item 4.
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Removed and Reserved
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31
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PART II
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Item 5.
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Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
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32
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Item 6.
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Selected Financial Data.
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36
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Item 7.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations.
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36
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Item 7A.
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Quantitative and Qualitative Disclosures About Market Risk.
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51
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Item 8.
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Financial Statements and Supplementary Data.
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52
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Item 9.
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Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
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53
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Item 9A
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Controls and Procedures.
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54
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Item 9B.
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Other Information.
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57
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PART III
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Item 10.
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Directors, Executive Officers and Corporate Governance.
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57
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Item 11.
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Executive Compensation.
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60
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Item 12.
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Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
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63
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Item 13.
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Certain Relationships and Related Transactions, and Director Independence.
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66
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Item 14.
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Principal Accounting Fees and Services.
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68
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PART IV
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Item 15.
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Exhibits and Financial Statement Schedules
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69
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Explanatory Note
Since the filing of its Annual Report on Form 10-K for the period ended December 31, 2007, and the filing of its Quarterly Report on Form 10-Q for the interim period ended September 30, 2008, Victory Energy Corporation has not filed with the Commission an Annual Report on Form 10-K or Quarterly Report on Form 10-Q for any subsequent annual or quarterly period. Furthermore, due to certain financial irregularities identified during an internal investigation, Victory Energy Corporation has stated that its 2007 Form 10-K and interim 2008 Forms 10-Q as previously filed should not be relied upon and must be restated.
This 2009 Annual Report on Form 10-K is designed to be comprehensive in nature and includes audited financial statements for the 2007 (restated), 2008 and 2009 fiscal years and unaudited quarterly financial statements for 2008 (restated) and 2009. In addition, it includes all material information that would have been available and disclosed in its December 31, 2009, 2008 and 2007 Forms 10-K and interim 2009 and 2008 Forms 10-Q had they been timely filed.
Cautionary Notice Regarding Forward Looking Statements
Victory Energy Corporation desires to take advantage of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. This report contains a number of forward-looking statements that reflect management's current views and expectations with respect to business, strategies, future results and events and financial performance. All statements made in this Annual Report other than statements of historical fact, including statements that address operating performance, events or developments that management expects or anticipates will or may occur in the future, including statements related to revenues, cash flow, profitability, adequacy of funds from operations, statements expressing general optimism about future operating results and non-historical information, are forward looking statements. In particular, the words “believe,” “expect,” “intend,” “anticipate,” “estimate,” “may,” “will,” variations of such words, and similar expressions identify forward-looking statements, but are not the exclusive means of identifying such statements and their absence does not mean that the statement is not forward-looking.
Readers should not place undue reliance on these forward-looking statements, which are based on management’s current expectations and projections about future events, are not guarantees of future performance, are subject to risks, uncertainties and assumptions and apply only as of the date of this report. Victory Energy Corporation’s actual results, performance or achievements could differ materially from the results expressed in, or implied by, these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below in “Risk Factors” as well as those discussed elsewhere in this report, and the risks discussed in press releases and other communications to stockholders issued by Victory Energy Corporation from time to time which attempt to advise interested parties of the risks and factors that may affect the business. Except as may be required under the federal securities laws, Victory Energy Corporation undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
Part I
General Background
Victory Energy Corporation, formerly known as All Things, Inc. (“Victory,” the “Company” or “We”), was organized under the laws of the State of Nevada on January 7, 1982. We were formed for the purpose of engaging in all lawful businesses. Our Company is authorized to issue 490,000,000 shares of $0.001 par value common stock.
On March 21, 1985, we changed our name to New Environmental Technologies Corporation, and on April 28, 2003 we changed our name again to Victory Capital Holdings Corporation. On May 3, 2006, we changed our name to Victory Energy Corporation.
Copies of the initial Articles of Incorporation of our Company and the Certificates of Amendment to the Articles of Incorporation are attached hereto and incorporated by reference. See Part IV Item 15.
From our inception to 2004, we had no material business operations. In 2004, we began the search for the acquisition of assets, property or businesses that could benefit the Company and its shareholders.
Management determined that we should focus on projects in the oil and gas industry. Based upon a belief that this industry is an economically viable sector in which to conduct business operations, we targeted specific prospects and joint venture opportunities engaged in the drilling for oil and natural gas.
Company Overview
We are an oil and natural gas exploration, development and production (E&P) company geographically focused on the onshore United States. We are headquartered in Newport Beach, California. We seek to identify proven development prospects, conduct thorough geological and engineering evaluations and then target suitable farm-in partners for long term development of additional prospects. Our operational focus is the acquisition, through the most cost effective means possible, of production or near production of oil and natural gas field assets. Targeted fields generally have existing wells that are often past primary energy recovery, but whose enhancement through secondary and possibly tertiary recovery methods could revitalize them. Targeted fields also have the availability of additional drilling sites. Our goal is to have an inventory of existing wells to enhance and a number of new drilling sites to maintain growth, while increasing reserves and cash flow.
Depending upon the specific terms and development opportunities of a given oil & gas project, we acquire our interests directly or indirectly through joint ventures, partnerships, or joint operating agreements. We currently serve as managing partner of Aurora Energy Partners, a Texas General Partnership (“Aurora”). We own a fifteen percent (15%) general partnership interest in Aurora and share fifteen percent (15%) in the profits and losses of Aurora. We manage all business operations of Aurora including project analysis, acquisition, finance and accounting, drilling operations, and production management.
During 2009 and 2008, Aurora acquired a one hundred percent (100%) working and seventy-four percent (74%) net revenue interest in eleven (11) natural gas wells. Aurora also acquired a fifty percent (50%) working and thirty-seven percent (37%) net revenue interest in two (2) gas wells. These gas wells are located in Crockett County, Texas. As of the date of this filing, nine (9) of these natural gas wells are producing natural gas and four (4) of the wells are drilled but not completed. Aurora is in process of completing these four (4) wells in order to bring them into production.
On December 31, 2010, we directly acquired a one (1) year option to acquire leases and available oil and gas mineral rights within a 1,000 acre tract on South Padre Island, Texas. Depending on the financing needs to develop this project, we may develop this project directly or indirectly through Aurora or other joint venture partners.
On February 18, 2011, Aurora entered into an agreement to acquire a 2.5% working interest in a producing wildcat well that is producing 300 barrels of oil (BOPD) and 100 thousand cubic feet (MCF) of natural gas per day.
Business Strategy
Our business strategy includes the acquisition, financing, improvement, exploration, and development drilling of existing and/or new oil and gas opportunities.
Acquisition and Financing
During our acquisition stage we identify, assess, and evaluate the geological opportunities of low risk, mature fields that have proven and probable reserves. During 2009 and 2008, Aurora secured $11.4 million of funding from one of Aurora’s general partners, James Capital Energy, LLC (“JCE”). JCE is an Alaska limited liability company that is comprised of forty (40) accredited investors. JCE is managed by Dr. Ronald Zamber, a major shareholder of the Company and member of our board of directors. The capital raised through Aurora was earmarked for the Adams-Baggett natural gas project in Crockett County, Texas. A portion of the funds we used to initially acquire interests in six (6) producing wells at a cost of $3.0 million. The remaining $8.1 million of capital was earmarked for a drilling program to develop additional natural gas wells on the Adams-Baggett ranch.
In buying existing oil and natural gas fields, we set out to extensively study the fields, the formations in which oil and natural gas were found, the history of sales from the field and the history of all surrounding fields, and their production. From this information, a better assessment could be made as to the value of the target property.
Improvement of Existing Wells
In collaboration with our business partners, we seek to improve the performance of our fields by investing in low risk work-over programs on existing wells and monetization of significant upside in work-over wells on already proved assets. We also seek to develop proved non-producing wells (PDNP) into proved developed and producing (PDP) assets with no associated exploration risk.
Currently, we have active operations on Aurora’s fields located in Crockett County, Texas and our fields located in South Padre Island, Texas. Aurora has working and net revenue interests in nine (9) productive natural gas wells in the Crockett County field in Texas. We began a four (4)-well work over program in the Crockett County project. The Company recently purchased an option to acquire leases and mineral interest on South Padre Island, Texas. Our management is extensively studying the fields, the formations in which oil and natural gas may be found, the history of sales from the field and the history of all surrounding fields, and their production. From this information, an assessment can be made as to the value of the target property.
Development Drilling on Proved Assets
Another aspect of our business strategy is to execute infill drilling of Aurora’s oil and gas assets and our oil and gas assets. We seek to develop proved undeveloped (PUD’s) assets into PDP assets with no associated exploration risk.
All of the planned development drilling and enhancements assume that we are successful in securing our 2011 funding that will support a drilling and development budget. The actual number of wells drilled will vary depending upon various factors, including the availability and cost of drilling rigs, any working interest partner issues, our ability to raise additional capital, the success of our drilling programs, weather delays and other factors. Our ability to drill the number of wells we have budgeted for 2011 and 2012 is heavily dependent upon the timely access to oilfield services, particularly drilling rigs.
We also seek to expand our oil and natural gas reserves through the acquisition of fields, wells, or working interests in oil and gas assets.
Current Operations
Adams-Baggett Ranch, Crockett County, Texas
In January, 2008, Aurora acquired mineral right leases on the Adams-Baggett Ranch that is located in southwest Texas. Aurora initially acquired a fifty percent (50%) Working Interest and thirty-seven percent (37%) Net Revenue Interest in six (6) producing gas wells at this location. In October 2008, Aurora acquired the remaining fifty percent (50%) Working Interest and thirty-seven percent (37%) Net Revenue Interest in three (3) of these producing gas wells. In February 2009, Aurora acquired an additional fifty percent (50%) Working Interest and thirty-seven percent (37%) Net Revenue Interest in one (1) of these producing gas wells. During 2008, we drilled and brought into production three (3) gas wells at this location. We also drilled four (4) additional wells that have not been completed as of the date of this report.
Aurora currently holds net revenue interest in nine (9) producing natural gas wells within the boundary of our currently held acreage. Four (4) additional wells have been drilled and are awaiting completion plans.
Padre Island Gas Fields, South Padre Island, Texas
On December 31, 2010, we entered into an option agreement to acquire an oil and gas lease in a 1,000 acre tract of South Padre Island, Texas. The option gives us exclusive right to acquire an oil and gas lease at the property for a period of one (1) year. Under the terms of the option, we will have full access to the land and may conduct geophysical or seismic testing of the land to ascertain the potential gas reserves.
Padre Island Gas Field is located 15 miles north of Port Isabel, Texas. The field was discovered by Gulf Oil in 1960 and produced approximately 3.8 billion cubic feet (BCF) to October 1, 1980 from two Miocene Sands at 6,000 feet and 6,500 feet. Three (3) wellbores are currently shut-in and will be re-evaluated for activation. These wells were producing 14 million cubic feet (MMCF) per month when they were shut-in in 2002. One of the wells could be recompleted at 6,000 feet, and another could be put on pump to flow gas up the backside. In addition, there is a 4-foot gas sand on water at 1,712 feet indicated by well logs and a gas core that has not been previously produced. A formation test of this sand had immediate pressure of 465 psi.
A successful completion of this sand could have potential of 2 BCF proved undeveloped reserves (PUD) of natural gas. There is an intact pipeline available to transport gas to onshore facilities. Compression facilities could be installed to further recover gas. The wells are located on Padre Island and are accessible by road.
The optioned property contains three (3) previously producing gas wells and the delivery infrastructure to transport the gas to onshore facilities. We will have a one hundred percent (100%) working interest and seventy-five percent (75%) net revenue interest in this project.
Jones County, Texas Oil Well Interest
On February 28, 2011, Aurora acquired a 2.5 percent working interest in the Young No. 1 well located in Jones County, Texas. This “Glen Thomas” wildcat well was completed and tested January 14, 2011. The well is now on production at a rate of 300 barrels of oil per day (BOPD) and 100 MCF of natural gas per day. Interest assignment of this production is effective February 1, 2011, with Aurora expecting revenue during the second quarter of 2011. Oil production is from the Caddo formation. The agreement also includes a working interest of no less than 1.5 percent in a sixty-four (64) square mile (40,966 acres) 3-D seismic imaging supported development area. The well operator, C.O. Energy, envisions drilling one to two wells per month until the targeted area is fully developed. Aurora maintains a thirty (30)-day first right of refusal to participate in each development well.
Distribution Methods
Each of our fields that produce oil distributes all of the oil that it produces through one purchaser for each field. We do not have a written agreement with some of these oil purchasers. These oil purchasers pick up oil from our tanks and pay us according to market prices at the time the oil is picked up at our tanks. There is significant demand for oil and there are several companies in our operating areas that purchase oil from small oil producers.
Each of our fields that produce natural gas distributes all of the natural gas that it produces through one purchaser for each field. We have distribution agreements with these natural gas purchasers that provide us a tap into a distribution line of a natural gas distribution company. We are to be paid for our natural gas at either a market price at the beginning of the month or market price at the time of delivery, less any transportation cost charged by the natural gas distribution company. These charges can range widely from 2 percent to 20 percent or more of the market value of the natural gas depending on the availability of competition and other factors.
Competitive Business Conditions
We encounter competition from other oil and natural gas companies in all areas of our operations. Because of record high prices for oil and natural gas, there are many companies competing for the leasehold rights to good oil and natural gas prospects. And, because so many companies are again exploring for oil and natural gas, there is often a shortage of equipment available to do drilling and work over projects. Many of our competitors are large, well-established companies that have been engaged in the oil and natural gas business for much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. We may not be able to conduct our operations, evaluate and select properties and consummate transactions successfully in this highly competitive environment.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.
Source and Availability of Raw Materials
We have no significant raw materials. However, we make use of numerous oil field service companies in the drilling and work over of wells. We currently operate in areas where there are numerous oil field service and drilling companies that are available to us.
Dependence on One or a Few Customers
There is a ready market for the sale of crude oil and natural gas. Each of our fields currently sells all of its oil production to one purchaser for each field and all of its natural gas production to one purchaser for each field. However, because alternate purchasers of oil and natural gas are readily available at similar prices, we believe that the loss of any of our purchasers would not have a material adverse effect on our financial results.
We sold oil and natural gas production representing more than 10% of our oil and natural gas revenues as follows:
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Years Ended December 31:
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2009
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2008
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2007
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Eagle Rock Natural Gas, LLC (1)
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100 |
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100 |
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None
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(1) We do not have a formal purchase agreement with this customer, but sell production on a month-to-month basis at spot prices adjusted for field differentials
Government Regulations
Our facilities in the United States are subject to federal, state and local environmental laws and regulations. Compliance with these provisions has not had, and we do not expect such compliance to have, any material adverse effect upon our capital expenditures, net earnings or competitive position.
Regulation of Transportation of Oil
Sales of crude oil, condensate, natural gas and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
Regulation of Transportation and Sale of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act. The Decontrol Act removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.
The FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued Order No. 636 and a series of related orders to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect.
Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states on shore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase our costs of getting gas to point of sale locations.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Regulation of Production
The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. Such regulations govern conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Environmental, Health and Safety Regulation
Our operations are subject to stringent and complex federal, state, local and provincial laws and regulations governing environmental protection, health and safety, including the discharge of materials into the environment. These laws and regulations may, among other things:
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require the acquisition of various permits before drilling commences;
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restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production and transportation activities;
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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
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require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.
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These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs.
The following is a summary of the material existing environmental, health and safety laws and regulations to which our business operations are subject.
Waste handling. The Resource Conservation and Recovery Act, or “RCRA”, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or “EPA”, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.
Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA”, also known as the Superfund law, imposes joint and several liabilities, without regard to fault or legality of conduct, in connection with the release of a hazardous substance into the environment. Persons potentially liable under CERCLA include the current or former owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance to the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources and the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
We own and lease, and may in the future operate, numerous properties that have been used for oil and natural gas exploitation and production for many years. Hazardous substances may have been released on, at or under the properties owned, leased or operated by us, or on, at or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been or are operated by third parties or by previous owners or operators whose handling, treatment and disposal of hazardous substances were not under our control. These properties and the substances disposed or released on, at or under them may be subject to CERCLA, RCRA and analogous state laws. In certain circumstances, we could be responsible for the removal of previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination. In addition, federal and state trustees can also seek substantial compensation for damages to natural resources resulting from spills or releases.
Water discharges. The Federal Water Pollution Control Act, or the “Clean Water Act”, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil and other substances generated by our operations, into waters of the United States or state waters. Under these laws, the discharge of pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
The Safe Drinking Water Act, or “SDWA”, and analogous state laws impose requirements relating to underground injection activities. Under these laws, the EPA and state environmental agencies have adopted regulations relating to permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as prohibitions against the migration of injected fluids into underground sources of drinking water.
Air emissions. The Federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, EPA and certain states have developed and continue to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and analogous state laws and regulations.
The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has not acted upon recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and natural gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations.
National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or “NEPA”. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All exploration and production activities on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects on federal lands.
Health safety and disclosure regulation. We are subject to the requirements of the federal Occupational Safety and Health Act, or “OSHA” and comparable state statutes. The OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and similar state statutes require that we organize and/or disclose information about hazardous materials stored, used or produced in our operations.
We expect to incur capital and other expenditures related to environmental compliance. Although we believe that our compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial position or results of operation.
Intellectual Property
We do not have any trademarks, patents or other intellectual property.
Employees
As of December 31, 2009, 2008, and 2007, we had no employees, one employee, and one employee, respectively. During 2009 and 2008, we contracted for the services of our CFO and CEO through Miranda & Associates, A Professional Accountancy Corporation. During 2008 and 2009, we contracted for gas well operator services from Remuda Operating Company and Cambrian Management, LTD.
Item 1A. Risk Factors
We have incurred operating losses, expect continued losses and may never achieve profitability.
We have operated at a loss each year since inception. Net losses for the fiscal years ended December 31, 2009; 2008; and 2007 were $465,746, $11,498,157 and $10,326,689, respectively. We have a history of modest revenues, have not been profitable and expect continued near term losses. Historically, we have relied upon cash from financing activities to fund substantially all of the cash requirements of our activities and have incurred significant losses and experienced negative cash flow. We cannot predict when we will become profitable or if we ever will become profitable, we may continue to incur losses for an indeterminate period of time and may never achieve or sustain profitability. An extended period of losses and negative cash flow may prevent us from successfully producing gas or developing additional gas wells and operating or expanding our business. As a result of our financial condition, our independent auditors have issued a report questioning our ability to continue as a going concern.
Our losses have resulted largely from the negligence and/or financial malfeasance of our former drilling contractor and other related parties, and from costs associated with our administrative activities. We expect our operating expenses to increase as a result of our planned operational activities. Since we have no significant operating history, we cannot assure you that our business will ever become profitable or that we will ever generate sufficient revenues to meet our expenses and support our planned activities. Even if we are able to achieve profitability, we may be unable to sustain or increase our profitability on a quarterly or annual basis.
Our ability to generate net income will be strongly affected by, among other factors, our ability to successfully drill undeveloped reserves as well as the market price of crude oil and natural gas. If we are unsuccessful in drilling productive wells or the market price of crude oil and natural gas declines, we may report additional losses in the future. Consequently, future losses may adversely affect our business, prospects, financial condition, results of operations and cash flows.
Our independent auditors have issued a report questioning our ability to continue as a going concern.
The report of our independent auditors contained in our financial statements for the years ended December 31, 2009; 2008; and 2007, includes a paragraph that explains that we have incurred substantial losses. These reports will raise substantial doubt about our ability to continue as a going concern. Reports of independent auditors questioning a company’s ability to continue as a going concern are generally viewed unfavorably by analysts and investors. This report may make it difficult for us to raise additional debt or equity financing necessary to continue the development of our oil and gas projects.
A decline in the price of our common stock could affect our ability to raise further working capital and adversely impact our operations.
A prolonged decline in the price of our common stock could result in a reduction in the liquidity of our common stock and a reduction in our ability to raise capital. Because our operations have been primarily financed through the sale of equity securities, a decline in the price of our common stock could be especially detrimental to our liquidity and our continued operations. Any reduction in our ability to raise equity capital in the future would force us to reallocate funds from other planned uses and would have a significant negative effect on our business plans and operations, including our ability to develop new projects and continue our current operations. If our stock price declines, we may not be able to raise additional capital or generate funds from operations sufficient to meet our obligations.
If we are not successful in continuing to grow our business, then we may have to scale back or even cease our ongoing business operations.
Our success is significantly dependent on a successful acquisition, drilling, completion and production program. We may be unable to locate recoverable reserves or operate on a profitable basis. If our business plan is not successful, and we are not able to operate profitably, investors may lose some or all of their investment in us.
Trading of our stock may be restricted by the SEC's "Penny Stock" regulations which may limit a stockholder's ability to buy and sell our stock.
The U.S. Securities and Exchange Commission has adopted regulations that generally define "penny stock" to be any equity security that has a market price (as defined) less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities are covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers or "accredited investors." The term "accredited investor" refers generally to institutions with assets in excess of $5,000,000 or individuals with a net worth in excess of $1,000,000 or annual income exceeding $200,000 or $300,000 jointly with his or her spouse. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC that provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer's account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer's confirmation. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from these rules; the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser's written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability of broker-dealers to trade our securities. We believe that the penny stock rules discourage investor interest in and limit the marketability of, our common stock.
NASD sales practice requirements may also limit a stockholder’s ability to buy and sell our stock.
In addition to the “penny stock” rules described above, the NASD has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, the NASD believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. The NASD requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.
Trading in our common shares has been volatile, making it more difficult for our stockholders to sell their shares or liquidate their investments with predictability.
Our common shares are currently quoted on the OTC Markets. The trading price of our common shares has been subject to wide fluctuations. Trading prices of our common shares may fluctuate in response to a number of factors, many of which will be beyond our control. The stock market has generally experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of companies with no current business operation. There can be no assurance that trading prices and price earnings ratios previously experienced by our common shares will be matched or maintained. These broad market and industry factors may adversely affect the market price of our common shares, regardless of our operating performance. In the past, following periods of volatility in the market price of a company's securities, securities class-action litigation has often been instituted. Such litigation, if instituted, could result in substantial costs for us and a diversion of management's attention and resources.
Our securities are considered highly speculative.
Our securities must be considered highly speculative, generally because of the nature of our business and the early stage of our exploration and development operations. We are engaged in the business of exploring and, if warranted, developing commercial reserves of oil and gas. Our properties are in the exploration stage only and are without known reserves of oil and gas. Accordingly, we have neither generated any material revenues nor realized a profit from our operations to date and there is little likelihood that we will generate any material revenues or realize any profits in the short term. Any profitability in the future from our business will be dependent upon locating and developing economic reserves of oil and gas, which itself is subject to numerous risk factors as set forth herein. Since we have not generated any material revenues, we expect that we will need to raise additional monies through the sale of our equity securities or debt in order to continue our business operations.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce.
On December 15, 2009, the U.S. Environmental Protection Agency, or EPA, published its findings that emissions of carbon dioxide, or CO2, methane, and other greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the Federal Clean Air Act. The EPA has adopted two sets of regulations under the existing Clean Air Act that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. In addition, in April 2010, the EPA proposed to expand its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. If the proposed rule is finalized as proposed, reporting of GHG emissions from such facilities would be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. The adoptions of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirement also could adversely affect demand for the oil and natural gas that we produce.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is a process used by oil and natural gas exploration and production operators in the completion or re-working of certain oil and natural gas wells, whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate natural gas and, to a lesser extent, oil production. This process is typically regulated by state oil and natural gas agencies and has not been subject to Federal regulation. However, due to concerns that hydraulic fracturing may adversely affect drinking water supplies, the EPA has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, and a committee of the U.S. House of Representatives has commenced its own investigation into hydraulic fracturing practices. Additionally, legislation has been introduced in Congress to amend the Federal Safe Drinking Water Act to subject hydraulic fracturing processes to regulation under that Act and to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. If enacted, such a provision could require hydraulic fracturing activities to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping requirement, and meet plugging and abandonment requirements. In unrelated oil spill legislation being considered by the U.S. Senate in the aftermath of the April 2010 Macondo well release in the Gulf of Mexico, Senate Majority Leader Harry Reid has added a requirement that natural gas drillers disclose the chemicals that are pumped into the ground as part of the hydraulic fracturing process. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. Adoption of legislation or of any implementing regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on our exploration and production activities, which could make it more difficult to perform hydraulic fracturing, resulting in reduced amounts of oil and natural gas being produced, as well as increase our costs of compliance and doing business.
The current global financial crisis and uncertainty in global economic conditions may have significant negative effects on our liquidity and financial condition.
The global financial and credit crisis has and may continue to impact our liquidity and financial condition. The continued credit crisis and related turmoil in the global financial system may have a material impact on our liquidity and our financial condition, and we may ultimately face major challenges if conditions in the financial markets do not improve. Our ability to access the capital markets or borrow money may be restricted at a time when we would like, or need, to raise capital, which could have an adverse impact on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. Additionally, the current economic situation could lead to reduced demand for natural gas and oil, or further reductions in the prices of natural gas and oil, or both, which could have a negative impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of the current financial crisis cannot be predicted, it may have a material adverse effect on our future liquidity, results of operations and financial condition.
We have substantial capital requirements that, if not met, may hinder operations.
We have and expect to continue to have substantial capital needs as a result of our active exploration, development, and acquisition programs. We expect that additional external financing will be required in the future to fund our growth. We may not be able to obtain additional financing, and we have no financing under existing or new credit facilities and these may not be available in the future. Without additional capital resources, we may be forced to limit or defer our planned natural gas and oil exploration and development program and this will adversely affect the recoverability and ultimate value of our natural gas and oil properties, in turn negatively affecting our business, financial condition, and results of operations.
Natural gas and oil prices are highly volatile, and lower prices will negatively affect our financial results.
Our revenue, profitability, cash flow, oil and natural gas reserves value, future growth, and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of natural gas and oil. Historically, the markets for natural gas and oil have been volatile, and those markets are likely to continue to be volatile in the future. It is impossible to predict future natural gas and oil price movements with certainty. Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty, and a variety of additional factors beyond our control. These factors include:
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the level of consumer product demand;
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the domestic and foreign supply of oil and natural gas;
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overall economic conditions;
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domestic and foreign governmental regulations and taxes;
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the price and availability of alternative fuels;
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political conditions in or affecting oil and natural gas producing regions;
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the level and price of foreign imports of oil and liquefied natural gas; and
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the ability of the members of the Organization of Petroleum Exporting Countries and other state controlled oil companies to agree upon and maintain oil price and production controls.
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Declines in natural gas and oil prices may materially adversely affect our financial condition, liquidity, and ability to finance planned capital expenditures and results of operations and may reduce the amount of oil and natural gas that we can produce economically.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our success largely depends on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control; including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are a common risk that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling operations, including the following:
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delays imposed by or resulting from compliance with regulatory requirements;
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pressure or irregularities in geological formations;
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shortages of or delays in obtaining equipment and qualified personnel;
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equipment failures or accidents;
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adverse weather conditions;
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reductions in oil and natural gas prices; and
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oil and natural gas property title problems.
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Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reported reserves. In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires that economic assumptions be made about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.
Actual future production, oil and natural gas prices received, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reported reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Our drilling prospects are in various stages of evaluation. There is no way to predict in advance of drilling and testing whether any particular drilling prospect will yield oil or natural gas in sufficient quantities to recover drilling and completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.
The near-term focus of our development activities will be concentrated in three core asset areas, which exposes us to risks associated with prospect concentration. The relative concentration of our near-term activities in three core asset areas means that any impairments or material reductions in the expected size of the reserves attributable to our wells, any material harm to the producing reservoirs or associated surface facilities from which these wells produce or any significant governmental regulation with respect to any of these fields, including curtailment of production or interruption of transportation of production, could have a material adverse effect on our financial condition and results of operations.
Seismic studies do not guarantee that hydrocarbons are present or, if present, will produce in economic quantities.
We may rely on seismic studies to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or if present will produce in economic quantities.
We depend on successful exploration, development and acquisitions to maintain revenue in the future.
In general, the volume of production from natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent that we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. Additionally, the business of exploring for, developing, or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired. In addition, we may be required to find partners for any future exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we will be adversely affected.
Our future acquisitions may yield revenues and/or production that vary significantly from our projections.
In acquiring producing properties we assess the recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities and other factors relating to such properties. Our assessments are necessarily inexact and their accuracy is inherently uncertain. Our review of a subject property in connection with our acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities.
We may not inspect every well, and we may not be able to identify structural and environmental problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial condition and future results of operations.
We cannot assure you that:
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we will be able to identify desirable natural gas and oil prospects and acquire leasehold or other ownership interests in such prospects at a desirable price;
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any completed, currently planned, or future acquisitions of ownership interests in natural gas and oil prospects will include prospects that contain proved natural gas or oil reserves;
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we will have the ability to develop prospects which contain proven natural gas or oil reserves;
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we will have the financial ability to consummate additional acquisitions of ownership interests in natural gas and oil prospects or to develop the prospects which we acquire to the point of production; or
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that we will be able to consummate such additional acquisitions on terms favorable to us.
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Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management has specifically identified and preliminarily scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These scheduled drilling locations represent a significant component of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
We may experience difficulty in achieving and managing future growth.
Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:
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our ability to obtain leases or options on properties;
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our ability to acquire geological & geophysical data;
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our ability to identify and acquire new development prospects;
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our ability to develop existing prospects;
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our ability to continue to retain and attract skilled personnel;
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our ability to maintain or enter into new relationships with project partners and independent contractors;
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the results of our drilling program;
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hydrocarbon prices; and
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We may not be successful in upgrading our technical, operations, and administrative resources or in increasing our ability to internally provide certain of the services currently provided by outside sources, and we may not be able to maintain or enter into new relationships with project partners and independent contractors. Our inability to achieve or manage growth may adversely affect our financial condition and results of operations.
We face strong competition from other natural gas and oil companies.
We encounter competition from other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proved properties. Our competitors include major integrated natural gas and oil companies and numerous independent natural gas and oil companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies that have been engaged in the natural gas and oil business much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. These companies may be able to pay more for productive natural gas and oil properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. We may not be able to conduct our operations, evaluate, and select suitable properties and consummate transactions successfully in this highly competitive environment.
Our business may suffer if we lose our Chairman, CEO, and CFO.
Our success will be dependent on our ability to continue to employ and retain experienced skilled personnel. We depend to a large extent on the services of Robert J. Miranda, our Chairman, Chief Executive Officer and Chief Financial Officer. Mr. Miranda has been managing the turnaround of the Company and is extremely valuable to the overall management of the Company. Although we have entered into an engagement agreement with Mr. Miranda’s firm, Miranda & Associates, the agreement does not guarantee the service of Mr. Miranda for a specified period of time. The loss of Mr. Miranda could significantly delay or prevent the achievement of our business objectives and adversely affect our business, financial condition and results of operations.
The unavailability or high cost of drilling rigs, equipment, supplies or personnel could affect adversely our ability to execute on a timely basis our exploration and development plans within budget, which could have a material adverse effect on our financial condition and results of operations.
Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or affect adversely our exploration and development operations, which could have a material adverse effect on our financial condition and results of operations. Demand for drilling rigs, equipment, supplies, and personnel are currently very high in the areas in which we operate. An increase in drilling activity in the areas in which we operate could further increase the cost and decrease the availability of necessary drilling rigs, equipment, supplies and personnel.
We cannot control activities on properties that we do not operate and are unable to ensure their proper operation and profitability.
We may not operate certain of the properties in the future in which we obtain an interest. As a result, we would have a limited ability to exercise influence over, and control the risks associated with, the operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator’s:
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timing and amount of capital expenditures;
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expertise and financial resources;
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inclusion of other participants in drilling wells; and
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The marketability of our natural gas production depends on facilities that we typically do not own or control, which could result in a curtailment of production and revenues.
The marketability of our natural gas production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. We generally deliver natural gas through gas gathering systems and gas pipelines that we may not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our gas may be interrupted due to capacity constraints on the applicable system, due to maintenance or repair of the system, or for other reasons as dictated by the particular agreements. Our ability to produce and market natural gas on a commercial basis could be harmed by any significant change in the cost or availability of such markets, systems or pipelines.
We may not be able to keep pace with technological developments in our industry.
The natural gas and oil industry is characterized by rapid and significant technological advancements and introduction of new products and services which utilize new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other natural gas and oil companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we are able to. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, and results of operations could be materially adversely affected.
If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting the trading value of our securities.
Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. Because our properties serve as collateral for advances under our existing credit facility, a write down in the carrying values of our properties could require us to repay debt earlier than would otherwise be required. A write-down would also constitute a non-cash charge to earnings. It is likely that the effect of such a write-down could also negatively impact the trading price of our securities.
We account for our oil and gas properties using the successful efforts method of accounting. Under this method, all development costs and acquisition costs of proved properties are capitalized and amortized on a units-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively. Costs of drilling exploratory wells are initially capitalized, but charged to expenses if and when a well is determined to be unsuccessful. We evaluate impairment of our proved oil and gas properties whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and gas prices are low or volatile. In addition, write-downs would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues.
We are subject to complex laws that can affect the cost, manner or feasibility of doing business.
The exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with such governmental regulations. Matters subject to regulation include:
|
|
•
|
permits for drilling operations;
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|
•
|
drilling and plugging bonds;
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|
•
|
reports concerning operations;
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|
|
•
|
the spacing and density of wells;
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•
|
unitization and pooling of properties;
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•
|
environmental maintenance and cleanup of drill sites and surface facilities; and
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•
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Protection of human health.
|
From time to time, regulatory agencies have also imposed price controls and limitations on production by restricting the rate of flow of natural gas and oil wells below actual production capacity in order to conserve supplies of natural gas and oil.
Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.
Our operations may cause us to incur substantial liabilities for failure to comply with environmental laws and regulations.
Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit or other authorizations before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, require permitting or authorization for release of pollutants into the environment, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, areas inhabited by endangered or threatened species, and other protected areas, and impose substantial liabilities for pollution resulting from historical and current operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition as well as on the industry in general. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed.
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities, some of which may be owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business.
Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas may have several adverse affects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.
The financial condition of our operators could negatively impact our ability to collect revenues from operations.
We may not operate all of the properties in the future in which we have working interests. In the event that an operator of our properties experiences financial difficulties, this may negatively impact our ability to receive payments for our share of net production that we are entitled to under our contractual arrangements with such operator. While we seek to minimize such risk by structuring our contractual arrangements to provide for production payments to be made directly to us by first purchasers of the hydrocarbons, there can be no assurances that we can do so in all situations covering our non-operated properties.
We may not have enough insurance to cover all of the risks that we face and operations of prospects in which we participate may not maintain or may fail to obtain adequate insurance.
In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. The impacts of Hurricanes Katrina, Rita and Ike have resulted in escalating insurance costs and less favorable coverage terms.
Oil and natural gas operations are subject to particular hazards incident to the drilling and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. We do not operate all of the properties in which we have an interest. In the projects in which we own a non-operating interest directly or own an equity interest in a limited partnership which in turn owns a non- operating interest, the operator for the prospect maintains insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event that is not fully covered by insurance could result in the loss of our total investment in a particular prospect which could have a material adverse effect on our financial condition and results of operations.
Terrorist attacks aimed at our energy operations could adversely affect our business.
The continued threat of terrorism and the impact of military and other government action have led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or the financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected our oil and natural gas operations to increased risks. Any future terrorist attack on our facilities, those of our customers, the infrastructure we depend on for transportation of our products, and, in some cases, those of other energy companies, could have a material adverse effect on our business.
Any failure to meet our debt obligations could harm our business, financial condition, results of operations or cash flows.
We face significant interest expenses as a result of our outstanding notes and we are in default on an unsecured note payable to Wells Fargo Bank that has an unpaid balance of $85,444 as of December 31, 2009. We have arranged an informal payment agreement with the lender to continue paying $2,200 monthly toward the balance owed on this loan. However, the lender has called the loan and may not extend credit terms beyond an additional six months. Our ability to generate cash flows from operations and to make scheduled payments on our indebtedness, including the notes, will depend on our future financial performance. Our future performance will be affected by a range of economic, competitive, legislative, operating and other business factors, many of which we cannot control, such as general economic and financial conditions in our industry or the economy at large. A significant reduction in operating cash flows resulting from changes in economic conditions, increased competition, or other events could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations and prospects and our ability to service our debt, including the notes, and other obligations.
If we are unable to service our indebtedness, we will be forced to adopt an alternative strategy that may include actions such as reducing or delaying acquisitions and capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking equity capital. We cannot assure you that any of these alternative strategies could be effected on satisfactory terms, if at all, or that they would yield sufficient funds to make required payments of interest on and principal of our debt in the future, including payments on the notes, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and impair our liquidity. Failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms.
We may issue additional shares of capital stock that could adversely affect holders of shares of our common stock and, as a result, holders of our notes convertible into shares of common stock.
Our board of directors is authorized to issue additional classes or series of shares of our capital stock without any action on the part of our stockholders. Our board of directors also has the power, without stockholder approval, to set the terms of any such classes or series of shares of our capital stock that may be issued, including voting rights, dividend rights, conversion features, preferences over shares of our existing class of common stock with respect to dividends or if we liquidate, dissolve or wind up our business and other terms. If we issue shares of our capital stock in the future that have preference over shares of our existing class of common stock with respect to the payment of dividends or upon our liquidation, dissolution or winding up, or if we issue shares of capital stock with voting rights that dilute the voting power of shares of our existing class of common stock, the rights of holders of shares of our common stock or the trading price of shares of our common stock and, as a result, the market value of the notes convertible into shares of common stock could be adversely affected.
The market price of our common stock may be volatile.
As we are in the early stages of being a publicly traded stock, the trading price of our common stock and the price at which we may sell common stock in the future are subject to large fluctuations in response to any of the following:
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•
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limited trading volume in our common stock;
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•
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quarterly variations in operating results;
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•
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our involvement in litigation;
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•
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general financial market conditions;
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•
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the prices of natural gas and oil;
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•
|
announcements by us and our competitors;
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•
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our ability to raise additional funds;
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•
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changes in government regulations; and
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Moreover, our common stock does not have substantial trading volume. As a result, relatively small trades of our common stock may have a significant impact on the price of our common stock and, therefore, may contribute to the price volatility of our common stock.
Because of the possibility of limited trading volume of our common stock and the price volatility of our common stock, you may be unable to sell your shares of our common stock when you desire or at the price you desire. The inability to sell your shares of our common stock in a declining market because of such illiquidity or at a price you desire may substantially increase your risk of loss.
We have not previously paid cash dividends on the shares of our common stock and do not anticipate doing so in the foreseeable future.
We have not in the past paid any cash dividends on the shares of our common stock and do not anticipate that we will pay any cash dividends on our common stock in the foreseeable future. Any future decision to pay a dividend on our common stock and the amount of any dividend paid, if permitted, will be made at the discretion of our board of directors.
If we fail to meet our payment obligations under our secured indebtedness, the note holders could foreclose on and acquire control of our assets.
The lenders under the 10% Senior Secured Convertible Debentures have a lien on substantially all our assets. As a result of this lien, if we fail to meet our payments or other obligations under this secured indebtedness, the note holders will be entitled to foreclose on our assets and liquidate those assets. As a result, you may lose a portion of or the entire value of your investment.
Our results of operations could be adversely affected as a result of impairments of drilling costs and other intangible assets.
In connection with the acquisition of producing gas wells and the drilling of additional gas wells, Aurora has approximately $11.4 million of investments in gas leases, tangible and intangible drilling costs. While we provide that our drilling costs be depleted over the estimated productive reserves of the gas wells, these assets must also be tested at least annually for impairment. Management makes certain estimates and assumptions when determining the fair value of net assets and liabilities, including, among other things, an assessment of market conditions, projected cash flows, investment rates, cost of capital and growth rates, which could significantly impact the reported value of drilling costs and other intangible assets. Fair value is determined using a combination of the discounted cash flow, market multiple and market capitalization valuation approaches. Absent any impairment indicators, we perform our impairment tests annually during the fourth quarter. Any future impairment, including impairments of the carrying values of drilling costs and other intangible assets, would negatively impact our results of operations for the period in which the impairment is recognized.
Pending litigation may place a severe financial burden on our resources and the outcome of the litigation may not be favorable to the Company.
We are currently defending two lawsuits filed against us by landowners for trespass. We are prosecuting a lawsuit against our former drilling contractor former operator, and other related parties. We are also prosecuting a lawsuit against our former independent auditor. The outcome of this pending litigation is uncertain and we may incur substantial legal fees to defend and prosecute these lawsuits.
Our plan to recover a substantial portion of our assets is dependent on our ability to obtain additional drilling sites from the Adams-Baggett Ranch landowners at favorable option prices.
Aurora is currently negotiating with the landowner to secure proper title to its gas leases and obtain fifty (50) to one hundred (100) future drilling sites at favorable pricing to the Company. These negotiations are based on allegations made by us against the landowners that title to our leases was defective and, thus, the landowner owes us restitution. There is no assurance that these negotiations will be successful thereby potentially impeding our ability to execute on our business turnaround plan.
The absence of current, publicly-available information about our Company can affect the market for our common stock.
We have not filed an Annual Report on Form 10-K since 2007 and a Quarterly Report on Form 10-Q since 2008. In addition, we provide very limited information about our Company to the public through other sources. The absence of current, publicly-available information makes it difficult for the marketplace to make an informed investment decision about our common stock. As a result, market makers, brokers, analysts and investors cannot adequately evaluate our Company which leads to a less active trading market in our common stock. Additionally, the absence of current, publicly-available information concerning our Company can affect the ability of certain restricted shareholders to trade their shares further limiting the market activity of our common stock. These factors can also contribute to a depressed price for our common stock.
Item 1B. Unresolved Staff Comments
None
Office Space Leases.
During 2009 and 2008, we leased 1,250 square feet of executive offices located in Solana Beach, California. The lease commenced on June 15, 2008, and terminated on June 14, 2010. The monthly lease cost was $3,625, subject to adjustment for cost of living and common area charges.
On January 25, 2011, we entered into a one (1)-year lease of approximately 1,200 square feet of executive office space located in Austin, Texas. The lease commenced on January 25, 2011, and expires on January 31, 2012. The monthly lease cost is $1,750.
Adams-Baggett Ranch, Crockett County, Texas.
In January, 2008, Aurora acquired mineral right leases on the Adams-Baggett Ranch that is located in southwest Texas. Aurora initially acquired a fifty percent (50%) Working Interest and thirty-seven percent (37%) Net Revenue Interest in six (6) producing gas wells at this location. In October 2008, Aurora acquired the remaining fifty percent (50%) Working Interest and thirty-seven percent (37%) Net Revenue Interest in three (3) of these producing gas wells. In February 2009, Aurora acquired an additional fifty percent (50%) Working Interest and thirty-seven percent (37%) Net Revenue Interest in one (1) of these producing gas wells. During 2008, we drilled and brought into production three (3) gas wells at this location. We also drilled four (4) additional wells that have not been completed as of the date of this report.
Aurora currently holds net revenue interest in nine (9) producing natural gas wells within the boundary of our currently held acreage. Four (4) additional wells have been drilled and are awaiting completion plans. Current interest and first production dates for these wells are as follows:
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Well Name
|
|
Working
Interest
|
|
|
Revenue
Interest
|
|
|
Net Revenue
Interest (NRI)
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|
Beginning
Production Date
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|
Date(s) Interests
Acquired by Aurora
|
|
Adams #127-11
|
|
|
100 |
% |
|
|
74 |
% |
|
|
74 |
% |
April 1, 2007
|
|
January 1 and October 3, 2008
|
|
Adams #127-12
|
|
|
100 |
% |
|
|
74 |
% |
|
|
74 |
% |
April 1, 2007
|
|
January 1 and October 3, 2008
|
|
Adams #127-13
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|
|
100 |
% |
|
|
74 |
% |
|
|
74 |
% |
August 1, 2007
|
|
January 1 and October 3, 2008
|
|
Adams #127-14
|
|
|
100 |
% |
|
|
74 |
% |
|
|
74 |
% |
October 1, 2007
|
|
January 1, 2008 and February 28, 2009
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|
Adams #127-15
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|
|
50 |
% |
|
|
37 |
% |
|
|
37 |
% |
December 1, 2007
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|
January 1, 2008
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|
Adams #155-2
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|
|
50 |
% |
|
|
37 |
% |
|
|
37 |
% |
December 1, 2007
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|
January 1, 2008
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|
Adams #166-8
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|
100 |
% |
|
|
74 |
% |
|
|
74 |
% |
May 1, 2008
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|
May 1, 2008
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|
Adams #166-9
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|
100 |
% |
|
|
74 |
% |
|
|
74 |
% |
May 1, 2008
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|
May 1, 2008
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|
Adams #115-8
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|
|
100 |
% |
|
|
74 |
% |
|
|
74 |
% |
September 1, 2008
|
|
September 1, 2008
|
Canyon sandstones are the primary hydrocarbon target within this prospect and they form a prolific low-permeability gas play located in the famous Val Verde Basin of Southwest Texas.
Natural gas from the Canyon Sandstone generally receives a twenty percent (20%) or more premiums in price above the standard market price for natural gas due to its higher BTU content per cubic foot.
The Canyon Sandstone gas play is part of the large prolific Adams-Baggett Canyon Sandstone gas field. The Canyon Sandstone formation is found at a depth of 4,300 feet to 4,900 feet. Initial flow test for these wells is approximately 250,000 cubic feet of gas per day per well. The average life span of a Canyon Sandstone gas well is approximately 30 years, the decline production curve starting during the second year.
These Canyon intervals are composed of thinly interbedded sandstone and mudstone, which formed in slope and basin depositional systems. The more tabular Ozona interval occupies a basin-floor position adjacent to the south margins of the Ozona Arch and the Central Basin Platform.
Padre Island Gas Fields, South Padre Island, Texas.
On December 31, 2010, we entered into an option agreement to acquire an oil and gas lease in a 1,000 acre tract of South Padre Island, Texas. The option gives us exclusive right to acquire an oil and gas lease at the property for a period of one (1) year. Under the terms of the option, we will have full access to the land and may conduct geophysical or seismic testing of the land to ascertain the potential gas reserves.
Padre Island Gas Field is located 15 miles north of Port Isabel, Texas. The field was discovered by Gulf Oil in 1960 and produced approximately 3.8 billion cubic feet (BCF) to October 1, 1980 from two Miocene Sands at 6,000 feet and 6,500 feet. Three (3) wellbores are currently shut-in and will be re-evaluated for activation. These wells were producing 14 thousand cubic feet (MCF) per month when they were shut-in in 2002. One of the wells could be recompleted at 6,000 feet, and another could be put on pump to flow gas up the backside. In addition, there is a 4-foot gas sand on water at 1,712 feet indicated by well logs and a gas core that has not been previously produced. A formation test of this sand had immediate pressure of 465 psi.
A successful completion of this sand could have potential of 2 BCF proved undeveloped reserves (PUD) of natural gas. There is an intact pipeline available to transport gas to onshore facilities. Compression facilities could be installed to further recover gas. The wells are located on Padre Island and are accessible by road.
The optioned property contains three (3) previously producing gas wells and the delivery infrastructure to transport the gas to onshore facilities. The Company will have a one hundred percent (100%) working interest and seventy-five percent (75%) net revenue interest in this project.
Jones County, Texas Oil Well Interest
On February 28, 2011, Aurora acquired a 2.5 percent working interest in the Young No. 1 well located in Jones County, Texas. This "Glen Thomas" wildcat well was completed and tested January 14, 2011. The well is now on production at a rate of 300 barrels of oil per day (BOPD) and 100 MCF of natural gas per day. Interest assignment of this production is effective February 1, 2011, with Aurora expecting revenue during the second quarter of 2011. Oil production is from the Caddo formation. The agreement also includes a working interest of no less than 1.5 percent in a sixty-four (64) square mile (40,966 acres) 3-D seismic imaging supported development area. The well operator, C.O. Energy, envisions drilling one to two wells per month until the targeted area is fully developed. Aurora maintains a thirty (30) day first right of refusal to participate in each development well.
Developed and Undeveloped Lease Acreage
The following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31, 2009. “Developed Acreage” refers to acreage on which wells have been drilled or completed to a point that would permit production of oil and natural gas in commercial quantities. “Undeveloped Acreage” refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and natural gas in commercial quantities whether or not the acreage contains proved reserves.
|
As of December 31, 2009
|
|
Average
Working
|
|
|
Developed Acreage
|
|
|
Undeveloped Acreage
|
|
|
Total Acreage
|
|
|
and 2008
|
|
Interest
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Adams-Baggett Ranch, TX
|
|
|
100 |
% |
|
|
180 |
|
|
|
160 |
|
|
|
80 |
|
|
|
80 |
|
|
|
260 |
|
|
|
240 |
|
|
Total
|
|
|
|
|
|
|
180 |
|
|
|
160 |
|
|
|
80 |
|
|
|
80 |
|
|
|
260 |
|
|
|
240 |
|
Summary of Oil and Gas Reserves as of Year-End 2009, 2008, and 2007
The reserves as of December 31, 2009, 2008, and 2007 were derived from reserve estimates prepared by an independent reserve engineer, Mr. James Nicolson. James A. Nicholson is an engineering consultant who specializes in preparing reservoir studies, reserve estimates, and property evaluations. Mr. Nicolson, a Registered Professional Engineer, is a member of the Society of Petroleum Engineers. He is former chairman of the Permian Basin Oil & Gas Recovery Conference. He holds a PhD ME from the University of Texas at Austin, an MSME from the University of Texas at Austin, and a BSME from Lamar University.
The reserve reports prepared by Mr. Nicolson were reviewed and approved by our independent consultants, including a geologist and an oil & gas operations professional. The PV-10 value was derived using average prices throughout the calendar year, discounted at 10% per annum on a pretax basis, and is not intended to represent the current market value of the estimated oil and natural gas reserves owned by us.
The following table sets forth our estimated net proved oil and natural gas reserves and the PV-10 value of such reserves as of December 31, 2009, 2008, and 2007.
|
Proved Reserves Developed
|
|
| |
|
Years Ended December 31:
|
|
| |
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Oil and condensate (Bbls)
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
Natural gas (MMcf)
|
|
|
748.7 |
|
|
|
824.5 |
|
|
|
— |
|
|
PV-10 Value
|
|
$ |
817,120 |
|
|
$ |
1,031,740 |
|
|
$ |
— |
|
|
(1)
|
The PV 10% Value as of December 31, is pre-tax and was determined by using the average of the preceding, 12-month-first-of-month product prices, which were $61.80 per Bbl for Oil and $4.21 MCF for gas pursuant to SEC guidelines. Management believes that the presentation of PV-10 value may be considered a non-GAAP financial measure. Therefore, we have included a reconciliation of the most directly comparable GAAP financial measure (standard measure of discounted net cash flows in Note 2 below). Management believes that the presentation of PV-10 value provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because many factors that are unique to each individual company may impact the amount of future income taxes to be paid, the use of the pre-tax measure provides greater comparability when evaluating companies. It is relevant and useful to investors for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies.
|
|
(2)
|
Management also uses this pre-tax measure when assessing the potential return on investment related to its oil and natural gas properties and in evaluating acquisition candidates. The PV-10 value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of the estimated oil and natural gas reserves owned by us. The PV-10 value should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
|
Productive Wells
Productive wells are producing wells or wells capable of production. This does not include water source wells, water injection wells or water disposal wells. Productive wells do not include any wells in the process of being drilled and completed that are not yet capable of production, but does include old productive wells that are currently shut-in, because they are still capable of production. The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2009, 2008, and 2007, respectively.
| |
|
2009
|
|
|
2008
|
|
|
2007
|
|
| |
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Natural Gas
|
|
|
9 |
|
|
|
8 |
|
|
|
8 |
|
|
|
7 |
|
|
|
- |
|
|
|
- |
|
|
Oil
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Totals
|
|
|
9 |
|
|
|
8 |
|
|
|
8 |
|
|
|
7 |
|
|
|
- |
|
|
|
- |
|
Technologies Used in Establishing Proved Reserves in 2009, 2008, and 2007
Our proved reserves in 2009, 2008, and 2007 were based on estimates generated through the integration of available and appropriate data, utilizing well established technologies that have been demonstrated in the field to yield repeatable and consistent results.
Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements, including high-quality 2-D and 3-D seismic data, calibrated with available well control. Where applicable, surface geological information was also utilized. The tools used to interpret the data included proprietary seismic processing software, proprietary reservoir modeling and simulation software, and commercially available data analysis packages.
Proved Undeveloped Reserves
At year end 2009, 2008, and 2007, our proved undeveloped reserves were none.
Oil and Gas Production, Production Prices and Production Costs
|
|
A.
|
Oil and Gas Production
|
The table below summarizes production by final product sold and by geographic area as of December 31, 2009, 2008, and 2007.
| |
|
2009
|
|
|
2008
|
|
2007
|
| |
|
|
|
Crude oil and natural gas production
|
|
|
|
|
|
|
|
|
United States (natural gas only, thousand cubic feet)
|
|
|
106,469,000 |
|
|
|
139,949,000 |
|
none
|
| |
|
|
|
|
|
|
|
|
|
|
Total crude oil and natural gas liquids production
|
|
|
106,469,000 |
|
|
|
139,949,000 |
|
none
|
| |
|
|
|
|
|
|
|
|
|
|
Natural gas production available for sale
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
United States (natural gas only, thousand cubic feet)
|
|
|
748,700,000 |
|
|
|
824,460,000 |
|
none
|
| |
|
|
|
|
|
|
|
|
|
|
Total natural gas production available for sale
|
|
|
748,700,000 |
|
|
|
824,460,000 |
|
none
|
|
|
B.
|
Sales Prices and Production Costs
|
The table below summarizes average sales prices and average production costs by geographic area and by product type for the years ended December 31, 2009, 2008, and 2007.
| |
|
United
|
|
|
|
|
| |
|
States
|
|
|
Total
|
|
| |
|
|
|
|
|
|
|
During 2009
|
|
|
|
|
|
|
|
Average Sales Prices
|
|
|
|
|
|
|
|
Crude Oil and NGL, per barrel
|
|
none
|
|
|
none
|
|
|
Natural gas, per thousand cubic feet
|
|
$ |
0.0047 |
|
|
$ |
0.0047 |
|
|
Average Production Costs
|
|
|
|
|
|
|
|
|
|
Crude Oil and NGL, per barrel
|
|
none
|
|
|
none
|
|
|
Natural gas, per thousand cubic feet
|
|
$ |
0.0016 |
|
|
$ |
0.0016 |
|
| |
|
|
|
|
|
|
|
|
|
During 2008
|
|
|
|
|
|
|
|
|
|
Average Sales Prices
|
|
|
|
|
|
|
|
|
|
Crude Oil and NGL, per barrel
|
|
none
|
|
|
none
|
|
|
Natural gas, per thousand cubic feet
|
|
$ |
0.0100 |
|
|
$ |
0.0100 |
|
|
Average Production Costs
|
|
|
|
|
|
|
|
|
|
Crude Oil and NGL, per barrel
|
|
none
|
|
|
none
|
|
|
Natural gas, per thousand cubic feet
|
|
$ |
0.0067 |
|
|
$ |
0.0067 |
|
| |
|
|
|
|
|
|
|
|
|
During 2007
|
|
|
|
|
|
|
|
|
|
Average Sales Prices
|
|
|
|
|
|
|
|
|
|
Crude Oil and NGL, per barrel
|
|
none
|
|
|
none
|
|
|
Natural gas, per thousand cubic feet
|
|
none
|
|
|
none
|
|
|
Average Production Costs
|
|
|
|
|
|
|
|
|
|
Crude Oil and NGL, per barrel
|
|
none
|
|
|
none
|
|
|
Natural gas, per thousand cubic feet
|
|
|
|
|
|
|
|
|
Drilling and Other Exploratory and Development Activities
The table below summarizes the number of net productive and dry exploratory wells and net productive and dry development wells drilled by geographic area as of December 31, 2009, 2008, and 2007.
| |
|
2009
|
|
2008
|
|
2007
|
|
Net Productive Exploratory Wells Drilled
|
|
|
|
|
|
|
|
United States
|
|
none
|
|
none
|
|
none
|
| |
|
|
|
|
|
|
|
Total productive exploratory wells drilled
|
|
none
|
|
none
|
|
none
|
|
Net Dry Exploratory Wells Drilled
|
|
|
|
|
|
|
|
United States
|
|
none
|
|
none
|
|
none
|
| |
|
|
|
|
|
|
|
Total dry exploratory wells drilled
|
|
none
|
|
none
|
|
none
|
|
Net Productive Development Wells Drilled
|
|
|
|
|
|
|
|
United States
|
|
none
|
|
3 |
|
none
|
| |
|
|
|
|
|
|
|
|
Total productive development wells drilled
|
|
none
|
|
3 |
|
none
|
|
Net Dry Development Wells Drilled
|
|
|
|
|
|
|
|
|
United States
|
|
0.5
|
|
10 |
|
none
|
| |
|
|
|
|
|
|
|
|
Total dry development wells drilled (1)
|
|
0.5
|
|
10 |
|
none
|
|
|
(1)
|
During 2009 and 2008, we incurred drilling costs on development wells of $290,665 and $4,942,579, respectively. We subsequently discovered that these drilling funds had been misappropriated and were expensed as “Loss from Malfeasance” during 2009 and 2008. Based upon the contract drilling cost of $500,000 per well, we have estimated the number of dry productive wells that were supposed to have been drilled for the amount of funds incurred.
|
Present Activities
The table below summarizes the number of wells in the process of being drilled by geographic area as of December 31, 2009, 2008, and 2007.
|
Wells Drilling
|
|
2009
|
|
2008
|
|
2007
|
| |
|
Gross
|
|
Net
|
|
Gross
|
|
|
Net
|
|
Gross
|
|
Net
|
|
United States
|
|
none
|
|
none
|
|
1.0 |
|
|
0.5 |
|
none
|
|
none
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross and net wells drilling
|
|
none
|
|
none
|
|
1.0 |
|
|
0.5 |
|
none
|
|
none
|
Item 3. Legal Proceedings
We are subject to litigation and claims that have arisen in the ordinary course of business, the majority of which have resulted from our thorough restructuring and turnaround efforts. Many of these claims have been resolved. Management believes individually such litigation and claims will not have a material adverse impact on our financial position or our results of operations but these matters are subject to inherent uncertainties and management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position and the results of operations for the period in which the effect becomes reasonably estimable.
The following describes the material legal action by and against the Company.
Victory Energy Corporation vs. Jim Dial, Remuda Operating Company, and Jon Fullenkamp
Victory Energy Corporation and James Capital Energy, LLC filed a lawsuit in Midland County, Texas, under Cause No. CV-47230, against Jim Dial, Jon Fullenkamp, Remuda Operating Company and other parties related to Jim Dial. Defendant Jon Fullenkamp is our former CEO and a former member of our board of directors. The lawsuit alleges fraud, breach of fiduciary duty, and other claims that Victory and JCE allege against these parties. This lawsuit seeks to recover damages in excess of $10.0 million, plus punitive damages.
On December 9, 2010, the Superior Court for the State of Texas entered a final judgment against the following defendants: Jim Dial; 1st Texas Natural Gas Company, Inc.; Universal Energy Resources, Inc.; Grifco International, Inc.; and Precision Drilling & Exploration, Inc. The court held that each of these defendants knowingly and intentionally perpetuated a fraud on the plaintiffs. Additionally, the court found that each defendant breached their contract with the plaintiffs, breached their fiduciary duty to the plaintiffs, and committed acts in violation of the Texas Oil and Gas Proceeds Payment Act.
The final judgment awards us and James Capital Energy, LLC, the plaintiffs, compensatory damages against five of the defendants in the amount of $5.6 million, jointly. The court also awarded punitive damages against each of these defendants in the amount of $2.2 million per defendant, for a total punitive damage award of $11.2 million. Additionally, the court awarded the plaintiffs pre-judgment interest and attorney fees.
Since the entering of the final judgment, we have not recovered any monies from the defendants. We intend to pursue available collection efforts to recover under the judgment in the event the defendants do not voluntary make payment as awarded.
On March 24, 2011 the Company, James Capital Energy, LLC and other related parties entered into a comprehensive Settlement Agreement with Jon Fullenkamp. Under the Settlement Agreement, Victory agreed to i) dismiss Jon Fullenkamp from the Texas lawsuit with prejudice, ii) provide him with a general release from all acts related thereto, and iii) pay him $30,000 over 70 days. In turn, Jon Fullenkamp agreed to i) dismiss with prejudice the lawsuit he filed against the Company and others in California; ii) transfer to Victory 2,000,000 shares of Victory preferred stock; iii) transfer to Victory 400,000 warrants for Victory common stock; iv) transfer to James Capital Energy, LLC 16,144,563 shares of Victory common stock; v) voluntarily appear for his deposition to discuss events that occurred at the Adams-Baggett Ranch; vi) waive the claim he had to the $430,000 severance payment under the May 15, 2009 Separation Agreement; and vii) provide Victory James Capital Energy, LLC and other related parties with a general release.
We intend to continue to pursue our claims against the remaining defendants, Remuda Operating Company, Ozona Natural Gas, LLC, Taylor Drilling, and Ronnie Taylor
Oz Gas Corporation vs. Universal Energy Resources, Inc., et al
We are an Intervener in a case pending in Crockett County, Texas under Cause No. 08-04-07047-CV, and styled Oz Gas Corporation vs. Universal Energy Resources, Inc., et al, in which the plaintiff is seeking to establish ownership of the 155-2 well on the grounds that the well was illegally drilled on property belonging to the plaintiff. We intervened in this action to protect our interests in the 155-2 well and to recover our share of suspended money now being held in the court’s registry. On information and belief the court is holding funds in excess of $100,000 from the 155-2 well pending the outcome of this action.
Jon Fullenkamp vs. Victory Energy Corporation, et. al.
On November 25, 2009, Jon Fullenkamp filed a lawsuit in California against us, James Capital Energy, LLC, Bob Miranda, Ron Zamber, Tom Konz and other parties alleging fraud, breach of contract, libel, slander and other claims. The plaintiff, Jon Fullenkamp, is our former CEO and a former member of our board of directors. On August 11, 2010, Mr. Fullenkamp filed an amended complaint, which now alleges additional causes of action. After several successful challenges to the complaint based on procedural grounds, on February 17, 2011, the Court finally accepted Jon Fullenkamp’s third amended complaint. . Subsequent thereto, and before any of the defendants in the action had to file a responsive pleading, the Company and other related parties entered into a comprehensive Settlement Agreement that resolved this matter. Under the Settlement Agreement, Victory agreed to i) dismiss Jon Fullenkamp from the Texas lawsuit with prejudice, ii) provide him with a general release from all acts related thereto, and iii) pay him $30,000 over 70 days. In turn, Jon Fullenkamp agreed to i) dismiss with prejudice the California lawsuit; ii) transfer to Victory 2,000,000 shares of Victory preferred stock; iii) transfer to Victory 400,000 warrants for Victory common stock; iv) transfer to James Capital Energy, LLC 16,144,563 shares of Victory common stock; v) voluntarily appear for his deposition to discuss events that occurred at the Adams-Baggett Ranch; vi) waive the claim he had to the $430,000 severance payment under the May 15, 2009 Separation Agreement; and vii) provide Victory James Capital Energy, LLC and other related parties with a general release.
Perry Howell, et. al. vs. Victory Energy Corporation, et.al.
On September 6, 2010, we were named in a lawsuit, together with our operator, Cambrian Management, Ltd. (“Cambrian”), pending in Midland, Texas under case No. 10-09-07213. The plaintiffs allege that we, along with other defendants, were trespassers on their land and drilled a well (#115-8) on land belonging to the plaintiffs. The plaintiffs are claiming trespass and unjust enrichment because of the drilling of the well #115-8.
Discovery is ongoing on this matter and a trial has not been set at this time. We, along with Cambrian, are in the process of completing some title work to decide how to proceed in this case. If we are not victorious in this case, we risk losing our investment in the well #115-8.
Victory Energy Corporation vs. John Kinross-Kennedy, CPA
On March 18, 2011, the Company filed a lawsuit against its former independent auditor, John Kinross-Kennedy, CPA, for professional negligence in the audits of the company’s 2006 through 2007 financial statements, and the preparation of the 2008 quarterly forms 10Q. The lawsuit seeks compensatory damages, costs of suit, and other relief as may be deemed just and proper by the Court.
Item 4. (Removed and Reserved).
Part II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer
Our common stock is currently quoted on the OTC Markets under the symbol “VYEY.” The following table sets forth the high and low bid information for each quarter for the years ended December 31, 2009, 2008, and 2007. The information reflects prices between dealers, and does not include retail markup, markdown, or commission, and may not represent actual transactions.
|
Fiscal Year
|
|
|
|
Bid Prices
|
|
|
Ended
December 31,
|
|
Period
|
|
High
|
|
|
Low
|
|
| |
|
|
|
|
|
|
|
|
|
2007
|
|
First Quarter
|
|
$ |
0.95 |
|
|
$ |
0.27 |
|
| |
|
Second Quarter
|
|
$ |
0.50 |
|
|
$ |
0.15 |
|
| |
|
Third Quarter
|
|
$ |
0.16 |
|
|
$ |
0.05 |
|
| |
|
Fourth Quarter
|
|
$ |
0.13 |
|
|
$ |
0.035 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
First Quarter
|
|
$ |
0.39 |
|
|
$ |
0.037 |
|
| |
|
Second Quarter
|
|
$ |
0.25 |
|
|
$ |
0.045 |
|
| |
|
Third Quarter
|
|
$ |
0.065 |
|
|
$ |
0.021 |
|
| |
|
Fourth Quarter
|
|
$ |
0.019 |
|
|
$ |
0.008 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
First Quarter
|
|
$ |
0.01 |
|
|
$ |
0.004 |
|
| |
|
Second Quarter
|
|
$ |
0.009 |
|
|
$ |
0.003 |
|
| |
|
Third Quarter
|
|
$ |
0.006 |
|
|
$ |
0.003 |
|
| |
|
Fourth Quarter
|
|
$ |
0.005 |
|
|
$ |
0.003 |
|
Holders
As of December 31, 2009 and 2008, there were 136,719,608 shares of our common stock issued and outstanding and held by 1,016 holders of record, 136,719,608 shares of our common stock issued and outstanding and held by 1,010 holders of record, respectfully. As of December 31, 2007 there were and 42,395,366 shares of our common stock issued and outstanding and held by 896 holders of record, respectively. The number of record holders was determined from the records of our transfer agent and does not include beneficial owners of common stock whose shares are held in the names of various security brokers, dealers, and registered clearing agencies.
The transfer agent for our common stock is Transfer Online, Inc., 512 SE Salmon Street, Portland, Oregon 97214.
Dividend Policy
We have not paid any cash dividends on our common stock and do not expect to do so in the foreseeable future. We intend to apply our earnings, if any, in expanding our operations and related activities. The payment of cash dividends in the future will be at the discretion of the board of directors and will depend upon such factors as earnings levels, capital requirements, our financial condition and other factors deemed relevant by the board of directors.
Recent Sales of Unregistered Securities
For the Year Ended December 31, 2007:
On February 5, 2007, we issued 435,000 shares of common stock to one business entity in exchange for services.
On February 5, 2007, we issued 5,946,466 shares of common stock to a trust, the beneficiary of which was a former board member and officer of the Company, in exchange for services.
On February 6, 2007, we issued 1,627,000 shares of common stock to two business entities in exchange for services.
On February 14, 2007, we issued 520,000 shares of common stock to one business entity.
On February 21, 2007, we issued 90,000 shares of common stock to three individuals.
On February 23, 2007, we issued 590,000 shares of common stock to one business entity.
On March 6, 2007, we issued 80,000 shares of common stock to one individual in exchange for services.
On March 9, 2007, we issued 1,300,000 shares of common stock to one business entity in exchange for services.
On March 13, 2007, we issued 40,000 shares of common stock to one former board member of the Company in exchange for services.
On March 13, 2007, we issued 36,000 shares of common stock to one individual in exchange for services.
On March 29, 2007, we issued 1,480,000 shares of common stock to two business entities.
On May 7, 2007, we issued 420,000 shares of common stock to one business entity and one individual in exchange for services.
On May 7, 2007, we issued 40,000 shares of common stock to two individuals in exchange for services.
On May 7, 2007, we issued 1,250,000 shares of common stock to a trust, the beneficiary of which was a former board member and officer of the Company, in exchange for services.
On May 9, 2007, we issued 9 shares of common stock to two business entities.
On May 14, 2007, we issued 1,600,000 shares of common stock to one business entity.
On June 4, 2007, we issued 1,900,000 shares of common stock to two business entities.
On June 5, 2007, we issued 1,037,591 shares of common stock to one individual.
On June 13, 2007, we issued a total of 8,500,000 shares of common stock to four business entities pursuant to their conversion of 85,000 shares of preferred stock
On June 13, 2007, we issued 40,000 shares of common stock to one individual in exchange for services.
On October 22, 2007, we issued warrants to purchase a total of 800,000 shares of common stock to one business entity at an exercise price of $0.25 per share in exchange for services.
On December 12, 2007, we issued 300,000 shares of common stock to one beneficial owner.
On December 29, 2007, we issued warrants to purchase a total of 600,000 shares of common stock to one business entity at an exercise price of $0.25 per share in exchange for services.
On December 31, 2007, we issued 1,060,000 shares of common stock to two individuals in exchange for services.
On December 31, 2007, we issued 9,750,000 shares of common stock to three former board members of the Company in exchange for services.
Unless otherwise indicated, we relied on the exemption from registration relating to offerings that do not involve any public offering pursuant to Section 4(2) under the Securities Act of 1933 (the “Act”) and/or Rule 506 of Regulation D of the Act. We believe that each investor had adequate access to information about us through the investor’s relationship with us.
For the Year Ended December 31, 2008:
On January 23, 2008, we issued 400,000 shares of common stock to two individuals in exchange for services.
On January 29, 2008, we issued 200,000 shares of common stock to one individual in exchange for services.
On February 22, 2008, we issued 2,000,000 shares of common stock to one individual.
On February 22, 2008, we issued warrants to purchase a total of 2,000,000 shares of common stock to one individual at an exercise price of $0.05 per share in exchange for services.
On February 25, 2008, we issued 4,275,000 shares of common stock to one business entity.
On February 29, 2008, we issued 4,275,000 shares of common stock to one business entity.
On March 12, 2008, we issued 1,400,000 shares of common stock to one individual in exchange for services.
On March 13, 2008, we issued a total of 4,482,758 shares of common stock to an individual pursuant to his conversion of 44,828 shares of preferred stock
On March 13, 2008, we issued 600,000 shares of common stock to one individual in exchange for cash.
On March 31, 2008, we issued warrants to purchase a total of 500,000 shares of common stock to one business entity at an exercise price of $0.25 per share in exchange for services.
On April 3, 2008, we issued a total of 4,482,758 shares of common stock to a business entity pursuant to its conversion of 44,828 shares of preferred stock.
On April 8, 2008, we issued 2,000,000 shares of common stock to one business entity and two individuals as a lawsuit settlement.
On April 28, 2008, we issued 115,000 shares of common stock to one individual in exchange for cash.
On April 28, 2008, we issued 100,000 shares of common stock to one individual in exchange for services.
On April 30, 2008, we issued a total of 2,000,000 shares of common stock to one individual pursuant to his exercise of 2,000,000 warrants at an exercise price of $0.05 per share.
On April 30, 2008, we issued 200,000 shares of common stock to one individual in exchange for cash.
On April 30, 2008, we issued a total of 1,000,000 shares of common stock to one business entity pursuant to its exercise of 1,000,000 warrants at an exercise price of $0.25 per share.
On April 30, 2008, we issued a total of 6,896,552 shares of common stock to one individual pursuant to his conversion of 68,966 shares of preferred stock.
On May 2, 2008, we issued 1,000,000 shares of common stock to one business entity in exchange for services.
On May 2, 2008, we issued 1,250,000 shares of common stock to one former board member of the Company in exchange for services.
On May 5, 2008, we issued a total of 8,689,655 shares of common stock to two individuals pursuant to their conversion of 86,897 shares of preferred stock.
On June 27, 2008, we issued a total of 8,500,000 shares of common stock to a business entity pursuant to its conversion of 85,000 shares of preferred stock.
On June 30, 2008, we issued warrants to purchase a total of 858,000 shares of common stock to one business entity at an exercise price of $0.25 per share in exchange for services.
On July 1, 2008, we issued a total of 19,767,863 shares of common stock to the stockholders of record as of May 2, 2008 pursuant to an extraordinary dividend of 1 share of common stock for every 4 shares of common stock held of record. Two (2) shares of common stock held by a beneficial owner were subsequently retired.
On July 28, 2008, we issued 4,482,758 shares of common stock to a business entity pursuant to its conversion of 44,828 shares of preferred stock.
On September 30, 2008, we issued warrants to purchase a total of 1,040,000 shares of common stock to one business entity at an exercise price of $0.25 per share in exchange for services.
On October 20, 2008, we issued 16,206,900 shares of common stock to one individual pursuant to his conversion of 162,069 shares of preferred stock.
On December 30, 2008, we issued warrants to purchase a total of 895,557 shares of common stock to one business entity at an exercise price of $0.25 per share in exchange for services.
Unless otherwise indicated, we relied on the exemption from registration relating to offerings that do not involve any public offering pursuant to Section 4(2) under the Securities Act of 1933 (the “Act”) and/or Rule 506 of Regulation D of the Act. We believe that each investor had adequate access to information about us through the investor’s relationship with us.
For the Year Ended December 31, 2009:
On January 31, 2009, we issued warrants to purchase a total of 500,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services.
On February 27, 2009, we issued warrants to purchase a total of 500,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services.
On March 31, 2009, we issued warrants to purchase a total of 500,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services.
On March 31, 2009, we issued warrants to purchase a total of 356,000 shares of common stock to a business entity, which is owned and controlled by a board member of the Company, at an exercise price of $0.25 per share in exchange for services.
On April 30, 2009, we issued warrants to purchase a total of 500,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services.
On May 29, 2009, we issued warrants to purchase a total of 400,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services.
On June 30, 2009, we issued warrants to purchase a total of 400,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services.
On June 30, 2009, we issued warrants to purchase a total of 80,000 shares of common stock to a business entity, which is owned and controlled by a board member of the Company, at an exercise price of $0.25 per share in exchange for services.
On July 31, 2009, we issued warrants to purchase a total of 400,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services.
On August 31, 2009, we issued warrants to purchase a total of 400,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services.
On September 30, 2009, we issued warrants to purchase a total of 400,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services.
On September 30, 2009, we issued warrants to purchase a total of 15,200 shares of common stock to a business entity, which is owned and controlled by a board member of the Company, at an exercise price of $0.25 per share in exchange for services.
On October 30, 2009, we issued warrants to purchase a total of 400,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services.
On November 30, 2009, we issued warrants to purchase a total of 400,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services.
On December 31, 2009, we issued warrants to purchase a total of 300,000 shares of common stock to board members of the Company at an exercise price of $0.01 per share in exchange for services.
On December 31, 2009, we issued warrants to purchase a total of 97,469 shares of common stock to a business entity, which is owned and controlled by a board member of the Company, at an exercise price of $0.25 per share in exchange for services.
Unless otherwise indicated, we relied on the exemption from registration relating to offerings that do not involve any public offering pursuant to Section 4(2) under the Securities Act of 1933 (the “Act”) and/or Rule 506 of Regulation D of the Act. We believe that each investor had adequate access to information about us through the investor’s relationship with us.
Item 6. Selected Financial Data
Not applicable
Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations
The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our consolidated financial statements and the accompanying notes included elsewhere in this Annual Report. Statements in our discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations.
The following is management’s discussion and analysis of certain significant factors that have affected certain aspects of our financial position and results of operations during the periods included in the accompanying audited consolidated financial statements. You should read this in conjunction with the discussion under “Financial Information” and the audited consolidated financial statements included in our Annual Report on Form 10-K, for the years ended December 31, 2009, 2008 and 2007 and the unaudited consolidated financial statements included elsewhere herein.
Forward Looking Statements
This Annual Report on Form 10-K contains forward-looking statements concerning our beliefs, plans, objectives, goals, expectations, anticipations, estimates, intentions, operations, future results and prospects, including statements that include the words “may,” “could,” “should,” “would,” “believe,” “expect,” “will,” “shall,” “anticipate,” “estimate,” “intend,” “plan” and similar expressions. These forward-looking statements are based upon current expectations and are subject to risk, uncertainties and assumptions. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated, estimated, expected, projected, intended, committed or believed. We provide the following cautionary statement identifying important factors (some of which are beyond our control) which could cause the actual results or events to differ materially from those set forth in or implied by the forward-looking statements and related assumptions.
General Overview
We are an independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties geographically focused on the onshore United States. Our operational focus is the acquisition, through the most cost effective means possible, of production or near production oil and natural gas field assets. Our areas of operation include Crockett County and South Padre Island, Texas.
Our revenue, profitability, cash flow, oil and natural gas reserves value, future growth, and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of natural gas and oil. Historically, the markets for natural gas and oil have been volatile, and those markets are likely to continue to be volatile in the future. It is impossible to predict future natural gas and oil price movements with certainty. Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty, and a variety of additional factors beyond our control.
Going Concern
As presented in the consolidated financial statements, we have incurred a net loss of $385,139 during the twelve months ended December 31, 2009, and losses are expected to continue in the near term. Current liabilities exceeded current assets by $1,090,297 and the accumulated deficit is $31,704,879 at December 31, 2009. Amounts outstanding and payable to creditors are in arrears and we are in negotiations with certain creditors to obtain extensions and settlements of outstanding amounts. We are currently in default on one of our debt obligations and we have no future borrowings or funding sources available under existing financing arrangements. Management anticipates that significant additional capital expenditures will be necessary to develop our oil and natural gas properties, which consist primarily of proved reserves that are non-producing, before significant positive operating cash flows will be achieved.
Management's plans to alleviate these conditions include the renegotiation of certain trade payables, settlements of debt amounts with stock, deferral of certain scheduled payments, as considered necessary. In addition, management is pursuing business partnering arrangements for the acquisition and development of its properties as well as debt and equity funding through private placements. Without outside investment from the sale of equity securities, debt financing or partnering with other oil and natural gas companies, operating activities and overhead expenses will be reduced to a pace that available operating cash flows can support.
The accompanying consolidated financial statements are prepared as if we will continue as a going concern. The consolidated financial statements do not contain adjustments, including adjustments to recorded assets and liabilities, which might be necessary if we were unable to continue as a going concern.
Twelve Months Ended December 31, 2009 Compared to the Twelve Months Ended December 31, 2008
Our revenue, operating expenses, and net loss from operations for the year ended December 31, 2009 as compared to the year ended December 31, 2008 are as follows:
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Percentage
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Year Ended December 31,
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Change
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2009
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2008
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Inc (Dec)
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REVENUES
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$ |
512,607 |
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$ |
1,642,631 |
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-68.8 |
% |
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COSTS AND EXPENSES
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Costs of production
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196,520 |
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934,534 |
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-79.0 |
% |
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General and administrative expense
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935,983 |
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3,519,409 |
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-73.4 |
% |
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Depletion and accretion
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291,867 |
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564,377 |
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-48.3 |
% |
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Malfeasance losses
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280,647 |
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4,955,793 |
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-94.3 |
% |
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Impairment of oil and natural gas properties
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342,366 |
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2,775,696 |
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-87.7 |
% |
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Loss (gain) on settlement with former officer
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(1,199,748 |
) |
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390,000 |
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-407.6 |
% |
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Total expenses
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847,635 |
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13,139,809 |
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-93.5 |
% |
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LOSS FROM OPERATIONS
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(335,028 |
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(11,497,178 |
) |
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-97.1 |
% |
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OTHER INCOME AND EXPENSE
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Interest expense
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50,111 |
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979 |
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5018.6 |
% |
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Total other expense
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50,111 |
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979 |
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5018.6 |
% |
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NET LOSS
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$ |
(385,139 |
) |
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$ |
(11,498,157 |
) |
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-96.7 |
% |
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Weighted average shares, basic and diluted
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136,719,608 |
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95,529,303 |
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Net loss per share, basic and diluted
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$ |
(0.00 |
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$ |
(0.12 |
) |
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Revenues: All of our revenue was derived from the sale of oil and natural gas. Our revenues for the twelve months ended December 31, 2009 and 2008 were $512,607 and $1,642,631, respectively, a decrease of 68.8%. This decrease was attributed to gas prices being approximately 53% higher in 2008 and a production decline of 33% between 2008 and 2009.
Costs of Production: Our cost of production, including royalties, lease operating, production taxes and expenses for the twelve months ended December 31, 2009 and 2008 were $196,520 and $934,534, respectively. The decrease of $738,014 is largely attributable to the 68.8% decrease in revenues between 2009 and 2008.
Cost of production as a percentage of revenue decreased to 38.2% from 56.3% reflecting substantial improvements in efficiency in production activities as a result of the increased management attention by the new investor groups.
Depletion and Accretion: Depletion and accretion expenses for the twelve months ended December 31, 2009 and 2008 were $291,867 and $564,377, respectively, a decrease of $272,510. The decrease was due to the lower amount of asset cost basis available to deplete following the impairment adjustment of 2008.
General and Administrative Expense: General and administrative expenses for the twelve months ended December 31, 2009 and 2008 were $935,983 and $3,519,409, respectively. The net decrease of $2,583,426 in general and administrative expenses between 2009 and 2008, is due primarily to the discontinuance of the stock based compensation programs of the former executive officer of the Company which reduced stock and warrant based compensation to $27,791 in 2009 from $2,424,855 in 2008.
Malfeasance losses: Malfeasance losses for the years ended December 31, 2009 and 2008 were $280,647 and $4,955,793 respectively. During the year ended December 31, 2009, we incurred approximately $472,622 of legal, accounting, and internal audit fees to investigate and prosecute this malfeasance. We are continuing to litigate to recover these malfeasance losses; however, recovery of these funds is uncertain.
Impairment of Oil and Natural Gas Properties: Impairment of oil and natural gas properties for 2009 and 2008 was $342,366 and $2,775,696, respectively. The decrease of impairment during 2009 is attributable to the reduced basis available to impair during 2009 following the significant 2008 impairment.
Interest Expense: Interest expense for the twelve months ended December 31, 2009 and 2008 was $50,111 and $979, respectively. Interest expense increased due to increased borrowings from related parties during 2009 over the same period in 2008.
Income Taxes: There is no provision for income tax recorded for either the 2009 or 2008 periods due to operating losses in both periods. We have available Federal income tax net operating loss (“NOL”) carry forwards of approximately $2,373,000 at December 31, 2009. Our NOL generally begins to expire in 2025. We recognize the tax benefit of NOL carry forwards as assets to the extent that management believes that the realization of the NOL carry forward is more likely than not. The realization of future tax benefits is dependent on our ability to generate taxable income within the carry forward period. This valuation allowance is provided for all deferred tax assets.
Net Loss: We had net loss for the twelve months ended December 31, 2009 of $385,139 and a net loss of $11,498,157 for the same period in 2008, specifically due to reasons discussed above.
Twelve Months Ended December 31, 2008 Compared to the Twelve Months Ended December 31, 2007
The Company has restated its December 31, 2007 financial statements. The restatements were mainly due to:
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The failure to properly value stock based compensation and warrants given for services in accordance with ASC 718. 505-50, Equity Based Payments to Non-Employees.
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Stock subscriptions recorded as assets with inadequate legal authority and valuation.
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Convertible preferred stock issued without adequate documentation or authority some of which subsequently converted to common stock.
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Joint venture assets recorded on the books of the Company that appear to be not longer in existence.
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·
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Sales of assets which were inappropriately classified.
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Our revenue, operating expenses, and net loss from operations for the year ended December 31, 2008 as compared to the year ended December 31, 2007 are as follows:
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Percentage
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Year Ending December 31,
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Change
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2008
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2007
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Inc (Dec)
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(As Restated)
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REVENUES
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$ |
1,642,631 |
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$ |
- |
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100.0 |
% |
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COSTS AND EXPENSES
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Costs of production
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934,534 |
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|
- |
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100.0 |
% |
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General and administrative expense
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3,519,409 |
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10,320,050 |
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-65.9 |
% |
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Depletion and accretion
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564,377 |
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- |
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100.0 |
% |
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Malfeasance losses
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4,955,793 |
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- |
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100.0 |
% |
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Impairment of oil and natural gas properties
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2,775,696 |
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- |
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100.0 |
% |
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Loss (gain) on settlement with former officer
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390,000 |
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- |
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100.0 |
% |
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Total expenses
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13,139,809 |
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10,320,050 |
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100.0 |
% |
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LOSS FROM OPERATIONS
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(11,497,178 |
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(10,320,050 |
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11.4 |
% |
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OTHER INCOME AND EXPENSE
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Interest expense
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979 |
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6,639 |
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-85.3 |
% |
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Total other expense
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979 |
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6,639 |
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-85.3 |
% |
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NET LOSS
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$ |
(11,498,157 |
) |
|
$ |
(10,326,689 |
) |
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11.3 |
% |
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Weighted average shares, basic and diluted
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95,529,303 |
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23,587,429 |
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Net loss per share, basic and diluted
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$ |
(0.12 |
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$ |
(0.44 |
) |
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Revenues: All of our revenue was derived from the sale of oil and natural gas. Revenues for the twelve months ended December 31, 2008 and 2007 were $1,642,631 and none, respectively. Neither Aurora nor the Company acquired any oil wells until January 2008, and we did not have natural gas revenues during 2007. The increase of $1,642,631 is attributable to the revenues associated with the wells purchased and drilled during 2008 as compared to no revenues during 2007.
Costs of Production: Our cost of production, including royalties, production taxes, production and lease operating expenses for the twelve months ended December 31, 2008 and 2007 were $934,534 and none, respectively. The increase of $934,534 is attributable to the wells purchased and drilled during 2008.
Depletion and Accretion: Depletion and accretion expenses for the twelve months ended December 31, 2008 and 2007 were $564,377 and none, respectively, and increase of $564,377. The increase was due to the applicable depletion of wells purchased and drilled during 2008.
General and Administrative Expense: General and administrative expenses for the twelve months ended December 31, 2008 and 2007 were $3,519,409 and $10,320,050, respectively. The net decrease of $6,800,641 in general and administrative expenses between 2008 and 2007, is due primarily to the discontinuance of the stock based compensation programs of the former executive officer of the Company which reduced stock based compensation to $2,424,855 in 2008 from $9,601,665 in 2007.
Malfeasance losses: Malfeasance losses for the years ended December 31, 2008 and 2007 were $4,955,793 and none, respectively. We are pursuing litigation to recover our malfeasance losses; however, recovery of these funds is uncertain.
Impairment of Oil and Natural Gas Properties: Impairment of oil and natural gas properties for 2008 and 2007 was $2,775,696 and none, respectively.
Interest Expense: Interest expense for the twelve months ended December 31, 2008 and 2007 was $979 and $6,639, respectively.
Income Taxes: There is no provision for income tax recorded for either the 2008 or 2007 periods due to operating losses in both periods. We have available Federal income tax net operating loss (“NOL”) carry forwards of approximately $1,700,000 at December 31, 2008. Our NOL generally begins to expire in 2025. We recognize the tax benefit of NOL carry forwards as assets to the extent that management believes that the realization of the NOL carry forward is more likely than not. The realization of future tax benefits is dependent on our ability to generate taxable income within the carry forward period. This valuation allowance is provided for all deferred tax assets.
Net Loss: We had net loss for the twelve months ended December 31, 2008 of $11,498,157 and a net loss of $10,326,689 for the same period in 2007 specifically due to reasons discussed above.
Liquidity and Capital Resources
The global financial and credit crisis may have impacts on our liquidity and financial condition that we currently cannot predict.
The continued credit crisis and related turmoil in the global financial system may have a material impact on our liquidity and our financial condition, and we may ultimately face major challenges if conditions in the financial markets do not improve. Our ability to access the capital markets or borrow money may be restricted at a time when we would like, or need, to raise capital, which could have an adverse impact on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. Additionally, the current economic situation could lead to reduced demand for natural gas and oil, or further reductions in the prices of natural gas and oil, or both, which could have a negative impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of the current financial crisis cannot be predicted, it may have a material adverse effect on our future liquidity, results of operations and financial condition.
During the year ended December 31, 2009, as with the year ended December 31, 2008, we did not generate positive cash flow. 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.
Our cash and cash equivalents, total current assets, total assets, total current liabilities, and total liabilities as of December 31, 2009 as compared to December 31, 2008, are as follows:
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December 31,
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December 31,
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2009
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2008
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Cash
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|
$ |
22,076 |
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$ |
166,189 |
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Total current assets
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169,213 |
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|
173,439 |
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Total assets
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|
989,600 |
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1,210,860 |
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Total current liabilities
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|
1,259,510 |
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|
2,185,088 |
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Total liabilities
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1,294,487 |
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|
2,205,208 |
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At December 31, 2009, we had a working capital deficit of $1,090,297 compared to a working capital deficit of $2,011,649 at December 31, 2008. Current liabilities decreased to $1,259,510 at December 31, 2009 from $2,185,088 at December 31, 2008 primarily due to a decrease of $1,231,866 in amounts due to a former officer of the Company.
Net cash used in operating activities totaled $757,339 and $5,334,073 for the twelve months ended December 31, 2009 and 2008, respectively. Net cash used in operating activities for the 2009 period consists of the net loss from continuing operations of $385,139 offset by non-cash items of $528,727 and changes in working capital of $156,527.
Net cash used in investing activities totaled $408,334 for the twelve months ended December 31, 2009, compared to $4,370,261 for the twelve months ended December 31, 2008. Net cash used by investing activities for 2009 and 2008 consist of the acquisition and drilling of gas wells at the Crockett County, Texas location.
Net cash provided by financing activities totaled $1,021,560 for the twelve months ended December 31, 2009, compared to $9,867,272 for the twelve months ended December 31, 2008. Net cash provided by financing activities for 2009 were the result of bank line of credit net repayments of $8,909, proceeds from notes payable to related parties of $325,000, proceeds from former officer of $19,838, proceeds from unauthorized preferred stock issued of $53,499, payments on notes payable to related parties of $353,673, payments to former officer of $61,004, and $1,046,809 of net funds provided to Aurora by JCE for the Crockett County project. Net cash provided by financing activities for 2008 were the result of bank line of credit net borrowings of $12,493, proceeds from notes payable to related parties of $383,673, proceeds from former officer of $300,412, payments to former officer of $41,758, $8,802,402 of net funds provided to Aurora by JCE for the Crockett County project, and $60,050 for sale of common stock.
Management Discussion and Analysis of the Restated Calendar Quarters Ending March 31, 2008, June 30, 2008, and September 30, 2008
The Company has restated its March 31, 2008, June 30, 2008, and September 30, 2008 financial statements. The restatements were mainly due to:
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The reported revenue cannot be confirmed in the amounts and in the periods reported. As a result, outstanding accounts receivable balances at the respective quarter ends have been reserved as part of the malfeasance loss.
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·
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The malfeasance and misdirection of funds along with poor record keeping makes the financial results as originally stated highly suspect.
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·
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Failure to properly record the value of common stock and warrants given for services throughout 2008 in accordance with ASC .505-50, Equity Based Payments to Non-Employees.
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·
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The financial results for each of the three quarters should have been consolidated with Aurora which provides the financial support for and management direction to the Company. Such consolidation is required by ASC 810-20,810-20, Control of Partnerships and Similar Entities.
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·
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Arithmetic errors in the reported financial statements.
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As a result of these deficiencies, it is not meaningful to provide a detailed discussion of the restated results for these quarterly results.
Three Months Ended March 31, 2008
For the three months ended March 31, 2008, the Company had, on a restated basis, revenues of $436,974 and incurred $287,422 in production costs, $2,010,029 in general and administrative costs, $59,511 in depletion and accretion expense and a net loss of $1,956,458. Although the full extent of the malfeasance loss did not become apparent until later, approximately $36,470 of the malfeasance loss has been traced to this period.
Aurora sold approximately 35,656 thousand cubic feet of gas (MCF) at an average price of approximately $12.26 per MCF. This was the first period of the Company’s drilling program in conjunction with Aurora.
Liquidity: At March 31, 2008, the Company had a working capital deficit of $1,756,542. The working capital deficit was primarily due to $1,421,368 in obligations to the then chief executive officer of the Company.
For the three months ended March 31, 2008, net cash used in provided by operating activities totaled $305,774. The loss of $1,956,458 for the period was offset by $1,916,136 in non-cash charges but decreased by $265,452 in the working capital accounts.
For the three months ended March 31, 2008, $2,556,599 was used in investing activities of which $1,120,000 was used to drill wells and $1,436,599 was used to purchase completed wells.
For the three months ended March 31, 2008, $2,859,122 provided by financing activities was the result of bank line of credit net repayments of $2,668, proceeds from notes payable to related parties of $300,000, proceeds from former officer of $210,715, payments to former officer of $167,225, $2,476,300 of net funds provided to Aurora by JCE for the Crockett County project, and $42,000 for sale of common stock.
Three and Six Months Ended June 30, 2008
For the three months ended June 30, 2008, the Company had, on a restated basis, revenues of $518,705 and incurred $303,790 in production costs, $691,946 in general and administrative costs, $115,294 in depletion expense and a net loss of $1,621,271. Although the full extent of the malfeasance loss did not become apparent until later, approximately $634,565 of the malfeasance loss has been traced to this period.
For the three months ended June 30, 2008, Aurora sold approximately 40,161 thousand cubic feet of gas (MCF) at an average price of approximately $12.92 per MCF.
For the six months ended June 30, 2008, the Company had, on a restated basis, revenues of $955,679 and incurred $591,212 in production costs, $2,701,975 in general and administrative costs, $174,805 in depletion and accretion expense and a net loss of $3,577,729. Although the full extent of the malfeasance loss did not become apparent until later, approximately $671,035 of the malfeasance loss has been traced to this period.
For the six months ended June 30, 2008, Aurora sold approximately 75,817 thousand cubic feet of gas (MCF) at an average price of approximately $12.61 per MCF.
Liquidity: At June 30, 2008, the Company had a working capital deficit of $5,331,906 due primarily to a declared but unpaid stock dividend of $3,953,573 and the amounts due the then chief executive officer of the Company of $1,267,692.
For the six months ended June 30, 2008, the Company used approximately $1,083,294 in cash in its current operations after the net loss of $3,577,729 was reduced by $992,917 in non-cash charges and reduced by $466,221 in changes in the working capital accounts excluding the stock dividend payable of $3,953,573.
For the six months ended June 30, 2008, approximately $3,799,030 of cash was used in investing activities of which $1,227,106 was used in drilling activities, $1,135,325 was used to complete wells, and $1,436,599 was used to purchase existing wells.
For the six months ended June 30, 2008, approximately $4,789,327 provided by financing activities was the result of bank line of credit net repayments of $6,486, proceeds from notes payable to related parties of $300,000, proceeds from former officer of $372,864, payments on notes payable to related parties of $90,000, payments to former officer of $483,053, $4,375,952 of net funds provided to Aurora by JCE for the Crockett County project, and $60,050 for sale of common stock.
Three and Nine Months Ended September 30, 2008
For the three months ended September 30, 2008, the Company had, on a restated basis, revenues of $478,180 and incurred $259,079 in production costs, $159,843 in general and administrative costs, $158,357 in depletion and accretion expense and a net loss of $4,465,048. Although the full extent of the malfeasance loss did not become apparent until later, approximately $4,365,949 of the malfeasance loss has been traced to this period.
For the three months ended September 30, 2008, Aurora sold approximately 47,450 thousand cubic feet of gas (MCF) at an average price of $10.08 per MCF.
For the nine months ended September 30, 2008, the Company had, on a restated basis, revenues of $1,433,859 and incurred $850,291 in production costs, $2,861,818 in general and administrative costs, $333,162 in depletion expense and a net loss of $8,042,777. Although the full extent of the malfeasance loss did not become apparent until later, approximately $5,036,984 of the malfeasance loss has been traced to this period.
For the nine months ended September 30, 2008, the Aurora sold approximately 123,267 thousand cubic feet of gas (MCF) at an average price of approximately $11.63 per MCF.
Liquidity: At September 30, 2008, the Company had a working capital deficit of $898,144 due primarily to the obligation to the then chief executive officer of the Company for $1,350,681.
For the nine months ended September 30, 2008 the Company used approximately $5,202,674 in its current operations after the net loss of $8,042,777 was reduced by $3,140,853 in non-cash charges but reduced by $300,750 in changes in the working capital accounts.
Approximately $1,609,434 of cash was used in investing activities of which approximately $1,573,892 was written off due to the malfeasance while $1,746,727 was used to complete drill wells, and $1,436,599 was used to purchase existing wells.
For the nine months ended September 30, 2008, approximately $7,325,290 provided by financing activities was the result of bank line of credit net repayments of $6,617, proceeds from notes payable to related parties of $300,000, proceeds from former officer of $639,951, payments on notes payable to related parties of $120,000, payments to former officer of $667,152, proceeds from the exercise of warrants of $350,000, $6,769,058 of net funds provided to Aurora by JCE for the Crockett County project, and $60,050 for sale of common stock..
Management Discussion and Analysis for the Three Months Ended March 31, 2009
Revenue: For the three months ended March 31, 2009, revenues declined $296,974 or 68.0% to $140,000 from $436,974 for the restated three month period ended March 31, 2008. This was due in large part in the fall in the volume of gas sold to 33,970 MCF from 35,656 MCF and the fall in the average price of the sales of natural gas to $4.12 per MCF from $12.26 for the three month period ended March 31, 2008.
Cost of Production: Cost of production for the three months ended March 31, 2009 declined $230,236 or 80.1% to $57,186 from $287,422 for the restated three months ended March 31, 2008 reflecting in large part the decline in the volume of gas sold.
General and Administrative Expense: General and administrative expenses for the three months ended March 31, 2009 declined $1,752,140 or 87.2% to $257,889 from $2,040,029 for the restated three month period ended March 31, 2008 reflecting the substantially decreased used of stock and warrant based compensation to finance the operations of the company and the increased influence of the new investors on the operations of the Company.
Depletion and Accretion: Depletion and accretion expense for the three months ended March 31, 2009 increased $13,399 or 22.5% to $72,910 from $59,511 for the restated three month period ended March 31, 2008 reflecting the additional depletion for the gas generating properties brought on line in the ensuing periods.
Malfeasance Losses: Recorded malfeasance losses were $249,771 for the three months ended March 31, 2009 compared to $36,470 for the three months ended March 31, 2008 as the opportunity for the diversion of funds only began in the three months ended March 31, 2008 when the funded drilling program began.
Net Loss: Net loss for the three months ended March 31, 2009 declined $1,444,522 or 73.8% to a loss of $511,936 from a loss of $1,956,458 for the three months ended March 31, 2008
Liquidity: At March 31, 2009, the Company had a working capital deficit of $2,225,037 compared to a working capital deficit of $1,756,542 at March 31, 2008. The working capital deficit was due primarily to obligations to the then chief executive officer of $1,685,055 at March 31, 2009 and $1,421,368 at March 31, 2008.
Net cash used by operating activities for the three months ended March 31, 2009 totaled $397,658 after the net loss of $511,936 was reduced by $85,902 in non-cash charges and by $28,376 in changes in the working capital accounts. This compares to cash used by operating activities in the three months ended March 31, 2008 of $305,774 after the net loss for the period of $1,916,135 was reduced by $1,916,136 in non-cash charges and increased by $265,452 in changes to the working capital accounts.
Net cash of $408,334 was used in investing activities during the three months ended March 31, 2009 primarily to add to the investment in drilled wells by $398,619. This compares to the $2,556,599 used in investing activities for the three months ended March 31, 2008 of which $1,120,000 was used for drilling costs and $1,436,599 was used to purchase completed wells.
Net cash provided by financing activities totaled $683,302 for the three months ended March 31, 2009, compared to $2,859,122 for the three months ended March 31, 2008. Net cash provided by financing activities for 2009 were the result of bank line of credit net repayments of $2,495, proceeds from notes payable to related parties of $30,000, proceeds from unauthorized preferred stock issued of $53,499, proceeds from former officer of $75,674, payments on notes payable to related parties of $70,000, payments to former officer of $27,159, and $623,783 of net funds provided to Aurora by JCE for the Crockett County project. Net cash provided by financing activities for the three months ended March 31, 2008 were the result of bank line of credit net repayments of $2,668, proceeds from notes payable to related parties of $300,000, proceeds from former officer of $210,715, payments to former officer of $167,225, proceeds from sale of common stock of $42,000, and $2,476,300 of net funds provided to Aurora by JCE for the Crockett County project.
Management Discussion and Analysis for the Three and Six Months Ended June 30, 2009
Revenue: For the three months ended June 30, 2009, revenues declined $400,860 or 77.3% to $117,845 from $518,705 for the restated three months ended June 30, 2008. This was due in large part in the fall in the volume of gas sold to 29,050 MCF from 40,161 MCF and the fall in the average price of the sales of natural gas to $3.97 per MCF from $12.92 for the three months ended June 30, 2008.
Cost of Production: Cost of production for the three months ended June 30, 2009 declined $258,722 or 85.2% to $45,068 from $303,790 for the restated three months ended June 30, 2008 reflecting in large part the decline in the volume of gas sold.
General and Administrative Expense: General and administrative expenses for the three months ended June 30, 2009 declined $393,407 or 56.9% to $298,539 from $691,946 for the restated three months ended June 30, 2008 reflecting the greater influence of new management on the operations of the Company during the three-month period ended June 30, 2009.
Depletion and Accretion: Depletion and accretion expense for the three months ended June 30, 2009 declined $42,356 or 36.7% to $72,938 from $115,294 for the restated three months ended June 30, 2008 reflecting an impairment charge taken at the end of 2008 which lowered the base for depletion as well as the reduced sale of gas by which the depletion expense is modulated.
Malfeasance Losses: Recorded malfeasance losses were $70,401 for the three months ended June 30, 2009 compared to $634,565 for the restated three months ended June 30, 2008 when the malfeasance was building.
Gain from Settlement with Former Officer: During the three months ended June 30, 2009, the then chief executive officer of the Company resigned. As a result of the resignation, the Company was able to renegotiate amounts claimed by the departing chief executive officer for past services to the Company and realized a net gain of $1,209,409 as a result.
Net Income: Net income for the three months ended June 30, 2009 increased $2,463,810 or 152% to $842,539 from a loss of $1,621,271 for the restated three months ended June 30, 2008 reflecting in major part, the gain on the settlement with the chief executive officer. In addition, general and administrative expenses declined as a result of the better control of the Company’s finances as a result of the change in management.
Revenue: For the six months ended June 30, 2009, revenues declined $697,834 or 73.0% to $257,845 from $955,679 for the restated six months ended June 30, 2008. This was due in large part in the fall in the volume of gas sold to 63,020 MCF from 75,817 MCF and the fall in the average price of the sales of natural gas to $4.05 per MCF from $12.61 for the six months ended June 30, 2008.
Cost of Production: Cost of production for the six months ended June 30, 2009 declined $488,958 or 82.7% to $102,254 from $591,212 for the restated six months ended June 30, 2008 reflecting in large part the decline in the volume of gas sold.
General and Administrative Expense: General and administrative expenses for the six months ended June 30, 2009 declined $2,145,547 or 79.4% to $556,428 from $2,701,975 for the restated six months ended June 30, 2008 reflecting the end of the use of stock and warrant based compensation programs and the greater influence of the new management on the operations of the Company.
Depletion and Accretion: Depletion and accretion expense for the six months ended June 30, 2009 declined $28,957 or 16.6% to $145,848 from $174,805 for the restated six months ended June 30, 2008 reflecting an impairment charge taken at the end of 2008 which lowered the base for depletion as well as the reduced sale of gas over which the depletion expense is modulated.
Malfeasance Losses: Recorded conversion malfeasance losses were $320,172 for the six months ended June 30, 2009 compared to $671,035 for the restated six-month period ended June 30, 2008.
Gain from settlement with former officer: In May, 2009, the then chief executive officer of the Company resigned. As a result of the resignation, the Company was able to renegotiate amounts claimed by the departing chief executive officer for past services to the Company and realized a net gain of $1,209,748 as a result.
Net Income: Net income for the six months ended June 30, 2009, increased $3,908,332 or 109% to $303,603 in net income from a loss of $3,577,729 for the restated six months ended June 30, 2008 reflecting in major part, the gain on the settlement with the chief executive officer. In addition, the general and administrative expenses declined as a result of the curtailing of the stock and warrant based compensation program and better control of the Company’s finances as a result of the change in management.
Liquidity: At June 30, 2009, the Company had a working capital deficit of $1,126,355 due primarily to accounts and accrued liabilities payable of $146,265, amounts due related parties of $368,673, amounts due the former CEO of $447,073, and the estimated liability of $85,654 due for the unconverted preferred stock. This compares to the restated working capital deficit of $5,331,906 at June 30, 2008 at the time when the malfeasance appears to have been flourishing.
For the six months ended June 30, 2009, the Company used approximately $610,559 in its current operations as the net income of $330,603 was offset by $1,043,796 in non-cash charges and increased by $102,634 in changes to the working capital accounts. This compares to the $1,083,294 used in operations for the six months ended June 30, 2008 when the net loss of $3,577,729 was offset by $2,960,656 in non-cash charges and reduced by $466,221 in changes in the working capital accounts ignoring the impact of the declaration of the stock dividend during that period.
Approximately $408,334 was used in investing activities during the six months ended June 30, 2009 of which $398,619 was added to the investment in purchased wells. This compares to $3,799,030 used in investing activities during the six months ended June 30, 2008 when $1,227,106 in drilling costs were incurred, $1,135,325 was invested completing drilled wells, and $1,436,599 was used to purchase producing wells.
Approximately $854,861 was provided by financing activities during the six months ended June 30, 2009 as the result of bank line of credit net repayments of $6,256, proceeds from notes payable to related parties of $55,000, proceeds from unauthorized preferred stock issued of $53,499, proceeds from former officer of $37,385, payments on notes payable to related parties of $70,000, payments to former officer of $18,550, and $803,783 of net funds provided to Aurora by JCE for the Crockett County project. Net cash provided by financing activities of $4,879,327 for the six months ended June 30, 2008 were the result of bank line of credit net repayments of $6,486, proceeds from notes payable to related parties of $300,000, proceeds from former officer of $540,084, payments on notes payable to related parties of $90,000, payments to former officer of $650,273, proceeds from exercise of warrants of $350,000, proceeds from sale of common stock of $60,050, and $4,375,952 of net funds provided to Aurora by JCE for the Crockett County project.
Management Discussion and Analysis for the Three and Nine Months Ended September 30, 2009
Revenue: For the three months ended September 30, 2009, revenues declined $366,660 or 76.7% to $111,520 from $478,180 for the restated three months ended September 30, 2008. This was due in large part in the fall in the volume of gas sold to 24,391 MCF from 47,450 MCF and the fall in the average price of the sales of natural gas to $4.59 per MCF from $10.08 for the three-month period ended September 30, 2008.
Cost of Production: Cost of production for the three months ended September 30, 2009 declined $216,789 or 83.7% to $42,290 from $259,079 for the restated three months ended September 30, 2008 reflecting in large part the decline in the volume of gas sold.
General and Administrative Expense: General and administrative expenses for the three months ended September 30, 2009 increased $58,780 or 36.8% to $218,623 from $159,843 for the restated three months ended September 30, 2008. The lowered level of general and administrative expenses in the three months ended September 30, 2008, however, does not appear to reflect the actual experience of the Company over calendar quarters of 2008 and 2009 and may be biased by the malfeasance activities which appear to have been peaked in that period in 2008.
Depletion and Accretion: Depletion and accretion expense for the three months ended September 30, 2009 declined $85,419 or 53.9% to $72,938from $158,357 for the restated three months ended September 30, 2008 reflecting an impairment charge taken at the end of 2008 which lowered the base for depletion as well as the reduced sale of gas by which the depletion expense is modulated.
Malfeasance Losses: Recorded malfeasance losses were negatively adjusted by $22,054 as a result of record reconciliation during the three months ended September 30, 2009 compared to $4,365,949 for the restated three months ended September 30, 2008 when most of the malfeasance appears to have taken place.
Net Loss: The net loss for the three months ended September 30, 2009 decreased $4,274,771 or 95.4% to a loss of $203,957 from a loss of $4,465,048 for the restated three months ended September 30, 2008 reflecting, for the most part, the end to stock and warrant based compensation programs and better control of the Company’s finances as a result of changes in management.
Revenue: For the nine months ended September 30, 2009, revenues declined $1,064,494 or 74.2% to $369,365 from $1,433,859 for the restated nine months ended September 30, 2008. This was due in large part to the fall in the volume of gas sold to 87,411 MCF from 123,267 MCF and the fall in the average price of the sales of natural gas to $4.20 per MCF from $11.63 for the nine months ended September 30, 2008.
Cost of Production: Cost of production for the nine months ended September 30, 2009 declined $705,747 or 83.0% to $144,544 from $850,291 for the restated nine months ended September 30, 2008 reflecting in large part the decline in the volume of gas sold.
General and Administrative Expense: General and administrative expenses for the nine months ended September 30, 2009 declined $2,086,767 or 72.9% to $775,051 from $2,861,818 for the restated nine months ended September 30, 2008 reflecting the greater influence of the new management on the operations of the Company.
Deletion and Accretion: Depletion and accretion expense for the nine months ended September 30, 2009 decreased $114,376 or 34.3% to $218,786 from $333,162 for the restated nine months ended September 30, 2008 reflecting an impairment charge taken at the end of 2008 which lowered the base for depletion as well as the reduced sale of gas in 2009 over which the depletion expense is modulated.
Malfeasance Losses: Recorded malfeasance losses were $298,118 for the nine months ended September 30, 2009 compared to $5,036,984 for the restated nine months ended September 30, 2008 when most of the malfeasance appears to have taken place.
Gain on Settlement: In May 2009, the then chief executive officer of the Company resigned. As a result of the resignation, the Company was able to renegotiate amounts claimed by the departing chief executive officer for past services to the Company and realized a net gain of $1,219,748 as a result.
Net Income: Net income for the nine months ended September 30, 2009, was $126,646. The change from the net loss of $8,042,777 for the restated nine months ended September 30, 2008 is not meaningful as the decreased loss reflects a decline in the malfeasance activities as far as they are known, a one-time settlement with the departing chief executive officer of the company, and the decline in the use of stock and warrant based compensation programs by the investors.
Liquidity: At September 30, 2009, the Company had a working capital deficit of $1,275,200 due primarily to notes payable to related parties of $478,674, remaining amounts due following the settlement with the former chief executive officer of $420,962, and the estimated amount of $85,654 in unresolved capital contributions related to the issuance of preferred stock in 2007 and 2008. This compares to the $898,144 working capital deficit for the nine months ended September 30, 2008.
For the nine months ended September 30, 2009, the Company used approximately $679,496 in its current operations after the net income $126,646 was increased by $973,554 in non cash charges and $167,412 for changes in the working capital accounts including the decrease in amounts due the former chief executive officer as a result of a settlement. . This compares to the $5,202,674 used in operations during the restated nine months ended September 30, 2008 which includes the period of time in which the malfeasance appears to have happened.
Approximately $408,334 of cash was used in investing activities during the nine months ended September 30, 2009 of which $398,619 was added to the investment in the purchased wells. This compares to $1,609,434 used in investing activities during the nine months ended September 30, 2008 when the main drilling and well acquisition activities were ongoing.
Approximately $923,935 was provided by financing activities during the nine months ended December 31, 2009 as the result of bank line of credit net repayments of $7,510, proceeds from notes payable to related parties of $165,000, proceeds from unauthorized preferred stock issued of $53,499, proceeds from former officer of $44,943, payments on notes payable to related parties of $70,000, payments to former officer of $44,661, and $782,664 of net funds provided to Aurora by JCE for the Crockett County project. Net cash provided by financing activities of $7,325,290 for the nine months ended December 31, 2008 were the result of bank line of credit net repayments of $6,617, proceeds from notes payable to related parties of $300,000, proceeds from former officer of $639,951, payments on notes payable to related parties of $120,000, payments to former officer of $667,152, proceeds from exercise of warrants of $350,000, proceeds from sale of common stock of $60,050, and $6,769,058 of net funds provided to Aurora by JCE for the Crockett County project.
Recently Issued Accounting Pronouncements
Recent Accounting Pronouncements
In June 2009, the FASB issued guidance establishing the ASC as the source of authoritative U.S. Generally Accepted Accounting Principles (“U.S. GAAP”) recognized by the FASB to be applied by non-governmental entities. Rules and interpretive releases of the Securities and Exchange Commission (“SEC”) under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants. The Codification supersedes all existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become non-authoritative. The FASB will no longer issue new standards in the form of Statements, FASB Staff Positions or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the Codification, provide background information about the guidance and provide the bases for conclusions on changes in the Codification. All content in the Codification carries the same level of authority, and the U.S. GAAP hierarchy was modified to include only two levels of U.S. GAAP: authoritative and non-authoritative. The Codification is effective for the Company’s interim and annual periods beginning with the Company’s year ending December 31, 2009. Adoption of the Codification affected disclosures in the Consolidated Financial Statements by eliminating references to previously issued accounting literature, such as SFASs, EITFs and FSPs.
In June 2009, the FASB issued amended standards for determining whether to consolidate a variable interest entity. These new standards amend the evaluation criteria to identify the primary beneficiary of a variable interest entity and require ongoing reassessment of whether an enterprise is the primary beneficiary of the variable interest entity. The provisions of the new standards are effective for annual reporting periods beginning after November 15, 2009 and interim periods within those fiscal years. The adoption of the new standards will not have an impact on the Company’s consolidated financial position, results of operations and cash flows.
In May 2009, the FASB issued guidance establishing general standards for accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued and shall be applied to subsequent events not addressed in other applicable generally accepted accounting principles. This guidance, among other things, sets forth the period after the balance sheet date during which management should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements and the disclosures an entity should make about events or transactions that occurred after the balance sheet date. The adoption of this guidance had no impact on the Company’s consolidated financial position, results of operations and cash flows
Summary of Critical Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.
Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of proved and unproved properties, future income taxes and related assets and liabilities, the fair value of various common stock, warrants and option transactions, and contingencies. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the calculation of impairment, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data, the engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.
These significant estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates, the fair value of the Company’s common stock and corresponding volatility, and the Company’s ability to generate future taxable income. Future changes to these assumptions may affect these significant estimates materially in the near term.
Oil and Natural Gas Properties
We account for investments in natural gas and oil properties using the successful efforts method of accounting. Under this method of accounting, only successful exploration costs that directly result in the discovery of proved reserves are capitalized. Unsuccessful exploration costs that do not result in an asset with future economic benefit are expensed. All development costs are capitalized because the purpose of development activities is considered to be building a producing system of wells, and related equipment facilities, rather than searching for oil and gas. Items charged to expense generally include geological and geophysical costs. Capitalized costs of proved properties are depleted on a field-by-field (Common Reservoir) basis using the units-of-production method based upon proved, producing oil and natural gas reserves.
The net capitalized costs of proved oil and natural gas properties are subject to an impairment test based on the undiscounted future net reserves from proved oil and natural gas reserves based on current economic and operating conditions. Impairment of an individual producing oil and natural gas field is first determined by comparing the undiscounted future net cash flows associated with the proved property to the carrying value of the underlying property. If the cost of the underlying property is in excess of the undiscounted future net cash flows the carrying cost of the impaired property is compared to the estimated fair value and the difference is recorded as an impairment loss. Management’s estimate of fair value takes into account many factors such as the present value discount rate, pricing, and when appropriate, possible and probable reserves when activities justified by economic conditions and actual or planned drilling or other development.
Under the successful efforts method of accounting, the depletion rate is the current period production as a percentage of the total proved producing reserves. The depletion rate is applied to the net book value of property costs to calculate the depletion expense. Proved reserves materially impact depletion expense. If the proved reserves decline, then the depletion rate (the rate at which we record depletion expense) increases, reducing net income.
We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to 10 years.
Long-lived Assets and Intangible Assets
The Company accounts for intangible assets in accordance with the provisions of the applicable FASB standard. Intangible assets that have defined lives are subject to amortization over the useful life of the assets. Intangible assets held having no contractual factors or other factors limiting the useful life of the asset are not subject to amortization but are reviewed at least annually for impairment or when indicators suggest that impairment may be needed. Intangible assets are subject to impairment review at least annually or when there is an indication that an asset has been impaired. As of December 31, 2008, the Company determined that due to the worsened financial markets and oil and gas industry, full impairment of its patented lateral drilling technology was necessary. While there are prospects for possible capital funding (either debt or equity), much is left to the market and outside instability. As such, at this time, management cannot anticipate with a comfortable degree of certainty if the appropriate amount of funding will be achieved and any funding will be diverted fully to its E&P activities. This will further postpone the Company’s ability to dedicate financial as well as human resources to its technology division in the short term future. As such, the Company has eliminated the division entirely.
For unproved property costs, management reviews these investments for impairment on a property-by-property basis if a triggering event should occur that may suggest that impairment may be required.
The Company reviews its long-lived assets and proved oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable in accordance with the applicable FASB standard. Proved oil and gas assets are evaluated for impairment at least annually. If the carrying amount of the asset, including any intangible assets associated with that asset, exceeds its estimated future undiscounted net cash flows, the Company will recognize an impairment loss equal to the difference between its carrying amount and its estimated fair value. The fair value used to calculate the impairment for producing oil and natural gas field that produces from a common reservoir is first determined by comparing the undiscounted future net cash flows associated with total proved properties to the carrying value of the underlying evaluated property. If the cost of the underlying evaluated property is in excess of the undiscounted future net cash flows, the future net cash flows discounted at 10%, which the Company believes approximates fair value, to determine the amount of impairment.
Stock Based Compensation
The Company adopted the FASB standard related to stock compensation to account for its warrants issued to key partners, directors and officers. The fair value of common warrants granted is estimated at the date of grant using the Black-Scholes option pricing model by using the historical volatility of comparable public companies. The calculation also takes into account the common stock fair market value at the grant date, the exercise price, the expected life of the common stock option or warrant, the dividend yield and the risk-free interest rate.
The Company from time to time may issue warrants and restricted stock to acquire goods or services from third parties. Restricted stock, options or warrants issued are recorded on the basis of their fair value, which is measured as of the date issued. In accordance with the standard, the options or warrants are valued using the Black-Scholes option pricing model on the basis of the market price of the underlying equity instrument on the “valuation date,” which for warrants related to contracts that have substantial disincentives to non-performance, is the date of the contract, and for all other contracts is the vesting date. Expense related to the options and warrants is recognized on a straight-line basis over the shorter of the period over which services are to be received or the vesting period.
Earnings per Share
Basic earnings per share are computed using the weighted average number of common shares outstanding. Diluted earnings per share reflect the potential dilutive effects of common stock equivalents such as options, warrants and convertible securities. Due to the Company incurring a net loss from continuing operations, basic and diluted loss per share are the same for the years ended December 31, 2009 and 2008 as all potentially dilutive common stock equivalents are anti-dilutive.
Income Taxes
Under the applicable FASB standard, deferred income taxes are recognized at each year end for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. We routinely assess the reliability of our deferred tax assets. We consider future taxable income in making such assessments. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, it is reduced by a valuation allowance. However, despite our attempt to make an accurate estimate, the ultimate utilization of our deferred tax assets is highly dependent upon our actual production and the realization of taxable income in future periods.
Contingencies
Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable.
Volatility of Oil and Natural Gas Prices
Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas.
Off-Balance Sheet Arrangements
For the years ended December 31, 2009, 2008, and 2007, we had no off-balance sheet arrangements that were reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is deemed by our management to be material to investors.
Contractual Obligations
The following table summarizes our contractual obligations and commercial commitments as of December 31, 2009:
| |
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
Total
|
|
|
Long-Term Debt
|
|
$ |
34,977 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
34,977 |
|
|
Capital Leases
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
Operating Leases
|
|
$ |
21,750 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
21,750 |
|
|
Purchase Obligations
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
Other Long-Term Liabilities
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
Total
|
|
$ |
56,727 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
56,727 |
|
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk
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.
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, 2008
|
|
$ |
12.26 |
|
|
June 30, 2008
|
|
$ |
12.92 |
|
|
September 30, 2008
|
|
$ |
10.08 |
|
|
December 31, 2008
|
|
$ |
5.00 |
|
|
March 31, 2009
|
|
$ |
4.12 |
|
|
June 30, 2009
|
|
$ |
4.05 |
|
|
September 30, 3009
|
|
$ |
4.20 |
|
|
December 31, 2009
|
|
$ |
4.66 |
|
Item 8. Financial Statements and Supplementary Data
The information required by this Item 8 is incorporated by reference to the Index to Consolidated Financial Statements beginning at page F-1 of this Annual Report.
Restatement of the Audited Financial Statements for 2007 - The Company has restated its December 31, 2007 financial results. The restatement adjusts the reported results for:
|
|
1)
|
the cancellation of unpaid subscriptions for the common stock of the Company which had not been properly authorized by the board of directors or properly accounted for by the then chief executive officer of the Company;
|
|
|
2)
|
a joint venture investment listed as an asset of the Company that was, in fact, worthless;
|
|
|
3)
|
the forced conversion of the convertible preferred stock which had not been properly authorized by the Board of Directors; and
|
|
|
4)
|
common stock and warrants given for services in 2005 and in 2007 whose value had not been recorded on the books of the Company.
|
Restatement of the Unaudited Interim Financial Statements for March, 31, 2008, June 30, 2008, and September 30, 2008 - The Company has restated its unaudited interim financial statements for March 31, 2008, June 30, 2008, and September 30, 2008. The restatement adjusts the reported results for:
| |
1)
|
verifiable revenues and asset amounts in light of a material malfeasance.
|
|
|
2)
|
the consolidation with Aurora which provides the financial support for and management direction to the Company. Such consolidation in financial reporting is required by ASC 810-20, Control of Partnerships and Similar Entities; and
|
| |
3)
|
Arithmetic errors in the reported financial statements.
|
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
On March 18, 2009, our board of directors approved the dismissal of John Kinross-Kennedy (“Mr. Kinross-Kennedy”) as the Company’s independent auditor. Mr. Kinross-Kennedy served as our independent auditor for the Company’s fiscal years ended December 31, 2007, December 31, 2006, and December 31, 2005. Mr. Kinross-Kennedy was also responsible for the review of our interim financial statements for the quarterly periods ending March 31, 2008, June 30, 2008, and September 30, 2008.
On March 23, 2009, we filed an 8-K with the Commission announcing our dismissal of Mr. Kinross-Kennedy as the Company’s independent auditor and disclosing that during the fiscal years ended December 31, 2007, December 31, 2006, and December 31, 2005, and until Mr. Kinross-Kennedy’s termination, there were no disagreements with Mr. Kinross-Kennedy on any matter of accounting principles or practices, financial disclosure, or auditing scope or procedure. Subsequent to Mr. Kinross-Kennedy’s departure from the Company, we endeavored to determine the adequacy of his professional work undertaken for the Company. However, because of the disarray created by the lack of proper financial record-keeping, it was not possible to discover the nature of financial improprieties set in place by Mr. Kinross-Kennedy until an independent audit of the Company’s books and records was undertaken in late 2010. Through this independent audit process, the Company has now determined that the accounting for the financial statements for the fiscal years ended December 31, 2007, and the interim periods ended March 31, June 30, and September 30, 2008, were not prepared in accordance with GAAP. As a result, we restated our financial statements for the following periods: Year ended December 31, 2007 and quarterly periods ended March 31, June 30, and September 30, 2008. In addition, we have filed a lawsuit against Mr. Kinross-Kennedy for professional negligence as disclosed under Item 3.
For the last two (2) fiscal years, there were no reports or other communications from Hein in connection with our financial statements that contained an adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope, or accounting principles. For the last two (2) fiscal years, and any subsequent interim period preceding the dismissal, there were no disagreements with Hein on any matter of accounting principles or practices, financial statement disclosure, or auditing scope of procedure which, if not resolved to the satisfaction of Hein, would have caused Hein to make reference to the subject matter of such disagreements in connection with any reports or other communications us.
Concurrent with the decision to dismiss Hein as our independent registered public accounting firm, our board of directors approved the appointment of Wilson Morgan, LLP (“Wilson”) as our registered independent public accounting firm.
We, during the last two (2) fiscal years and any subsequent interim period to the date hereof, did not have discussions nor have we consulted with Wilson regarding the following: (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on our financial statements, and neither a written report or oral advice was provided to us that Wilson concluded was an important factor considered by us in reaching a decision as to the accounting, auditing, or financial reporting issue, or (ii) any matter that was the subject of a disagreement or reportable event as defined in Regulation S-K, Item 304(a)(1)(iv) and Item 304(a)(1)(v), respectively.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures, as defined in Rule 13a-1 5(e) promulgated under the Securities Exchange Act of 1934 (the “Exchange Act”), that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2009, 2008, and 2007. Based on the evaluation of these disclosure controls and procedures, and in light of the material weaknesses found in our internal controls over financial reporting, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective.
This Annual Report does not include an attestation report of the company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this Annual Report.
Management’s Report on Internal Control over Financial Reporting
December 31, 2009:
Material Weaknesses in Internal Control Over Financial Reporting
Management’s assessment of the effectiveness of the registrant’s internal control over financial reporting is as of the year December 31, 2009. Based on that evaluation, our management concluded that our control over financial reporting and related disclosure controls and procedures were not effective because for the significant part of the year (a) we did not have adequate controls over our control environment and (b) our accounting processes lacked appropriate segregation of responsibilities necessary for an effective system of internal control. We believe that our lack of segregation of duties and inadequate controls over the control environment constitute material weaknesses in our internal control. In addition to these material weaknesses, Management’s assessment showed that the following material weaknesses from the audited year ended December 31, 2009:
As of December 31, 2009, we did not maintain effective controls over the control environment. Specifically we had not developed and effectively communicated to our employees, including officers, its accounting policies and procedures. This has resulted in inconsistent practices and created an opportunity for the malfeasance that occurred during 2008 and 2009.
As of December 31 2009, we did not maintain effective controls over financial statement disclosure. Specifically, controls were not designed and in place to ensure that all disclosures required were originally addressed in our financial statements. Due to the continuing investigation of the malfeasance that occurred during 2008 and 2009, as of December 31, 2009, we were unable to compile complete and accurate financial statements nor file the 2009 Annual Report on Form 10-K by its due date of March 31, 2010. Accordingly, management has determined that this control deficiency constitutes a material weakness.
During our annual audit, Management evaluated remediation plans related to the above material weakness in internal control over financial reporting.
During November, 2008, we hired a CFO who possesses the needed GAAP accounting and SEC reporting skills necessary to improve our internal controls over financial reporting. From January 1, 2009 through May 15, 2009, the CFO had not been granted full access to the Company’s underlying books, records, contracts, relationships and operating procedures. The full extent of the malfeasance was not discovered until after the CFO had access to this critical information. Our internal investigation into these matters was not concluded until December 2010. As a result, we were unable to file timely our Annual Report on Form 10-K for the year ended December 31, 2009; nor were we able to file timely Quarterly Reports on Forms 10-Q for the 2010 interim periods.
During January, 2009, we appointed our CFO to the board of directors. While the CFO is qualified as an audit committee financial expert as defined in Item 407(d)(5)(ii) of Regulation S-B, he is not independent and, as such, his role on the board of directors does not meet the independence requirements of Item 407(d)(5)(ii) of Regulation S-B.
December 31, 2008:
Material Weaknesses in Internal Control Over Financial Reporting
Management’s assessment of the effectiveness of the registrant’s internal control over financial reporting is as of the year December 31, 2008. Based on that evaluation, our management concluded that our control over financial reporting and related disclosure controls and procedures were not effective because (a) we did not have adequate controls over our control environment and (b) our accounting processes lacked appropriate segregation of responsibilities necessary for an effective system of internal control. We believe that our lack of segregation of duties and inadequate controls over the control environment constitute material weaknesses in our internal control. In addition to these material weaknesses, Management’s assessment showed that the following material weaknesses from the audited year ended December 31, 2008:
As of December 31, 2008, we did not maintain effective controls over the control environment. Specifically we had not developed and effectively communicated to our employees, including officers, its accounting policies and procedures. This has resulted in inconsistent practices and created an opportunity for the malfeasance that occurred during 2008 and 2009. Further, the Board of Directors did not have any directors who qualified as an audit committee financial expert as defined in Item 407(d)(5)(ii) of Regulation S-B. Since these entity level programs have a pervasive effect across the organization, management has determined that these circumstances constitute a material weakness.
As of December 31 2008, we did not maintain effective controls over financial statement disclosure. Specifically, controls were not designed and in place to ensure that all disclosures required were originally addressed in our financial statements. Accordingly, management has determined that this control deficiency constitutes a material weakness.
As of December 31, 2008, we did not have written documentation of our internal control policies and procedures. Written documentation of key internal controls over financial reporting is a requirement of Section 404 of the Sarbanes-Oxley Act as of the year ending December 31, 2008. Accordingly, management concluded that the control deficiency that resulted represents a material weakness.
As of December 31, 2008, we did 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. Accordingly, management has determined that this control deficiency constitutes a material weakness.
As of December 31, 2008, we believe our auditor did not meet the requirements for independence. The independent auditor maintained our general ledger, prepared and entered journal entries into the general ledger, prepared our quarterly 10-Q SEC filings for the periods ended March 31, June 30, and September 30, 2008, and made all critical financial accounting decisions, while purportedly conducting independent reviews of the Company’s quarterly filings.
This lack of internal controls over financial reporting created an opportunity for fraud malfeasance surrounding our funds that was reported in the 2008 and 2009 financial statements. The lack of internal controls also resulted in the need for an internal audit investigation by our CFO that required the investment of Company resources in a forensic accounting to compile the information necessary to restate the financial statements and prepare the records for the examination by our independent auditor.
During our annual audit, Management evaluated remediation plans related to the above internal control deficiencies. Management analyzed the costs and benefits of several different options to improve our internal controls over financial reporting. The following options for improving the controls were analyzed (i) forming an internal audit department, (ii) additional staffing to provide segregation of duties and a review infrastructure for financial reporting, (iii) an information technology department to provide security over our information and to help facilitate electronic filing. In the evaluation, Management estimated implementation of the proposed remediation plan within 1 to 2 years.
During November, 2008, we hired a CFO who possesses the needed GAAP accounting and SEC reporting skills necessary to improve our internal controls over financial reporting. However, as of December 31, 2008, the CFO had not had adequate time to familiarize himself with our internal controls nor had he uncovered the extent of material weaknesses in internal controls that existed at the time. Also, at December 31, 2008, the CFO had not been granted full access to the Company’s underlying books, records, contracts, relationships and operating procedures. The full extent of the malfeasance was not discovered until after the CFO had access to this critical information.
December 31, 2007:
Material Weaknesses in Internal Control Over Financial Reporting
Management’s assessment of the effectiveness of the registrant’s internal control over financial reporting is as of the year December 31, 2007. Based on that evaluation, our management concluded that our control over financial reporting and related disclosure controls and procedures were not effective because (a) we did not have adequate controls over our control environment and (b) our accounting processes lacked appropriate segregation of responsibilities necessary for an effective system of internal control, and (c) our auditor’s independence was impaired. We believe that our lack of segregation of duties, inadequate controls over the control environment, and impairment of our independent auditor’s independence constitute material weaknesses in our internal control. In addition to these material weaknesses, Management’s assessment showed that the following material weaknesses from the audited year ended December 31, 2007:
As of December 31, 2007, we did not maintain effective controls over the control environment. Specifically we had not developed and effectively communicated to our employees, including officers, its accounting policies and procedures. This has resulted in inconsistent practices and created an opportunity for the malfeasance that occurred during 2008 and 2009. Further, the Board of Directors did not have any directors who qualified as an audit committee financial expert as defined in Item 407(d)(5)(ii) of Regulation S-B. Since these entity level programs have a pervasive effect across the organization, management has determined that these circumstances constitute a material weakness.
As of December 31 2007, we did not maintain effective controls over financial statement disclosure. Specifically, controls were not designed and in place to ensure that all disclosures required were originally addressed in our financial statements. Accordingly, management has determined that this control deficiency constitutes a material weakness.
As of December 31, 2007, we did not have written documentation of our internal control policies and procedures. Written documentation of key internal controls over financial reporting is a requirement of Section 404 of the Sarbanes-Oxley Act as of the year ending December 31, 2007. Accordingly, management concluded that the control deficiency that resulted represents a material weakness.
As of December 31, 2007, we did 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. Accordingly, management has determined that this control deficiency constitutes a material weakness.
As of December 31, 2007, we believe our auditor did not meet the requirements for independence. The independent auditor maintained our general ledger, prepared and entered journal entries into the general ledger, prepared our SEC filings, including the quarterly Forms 10-Q and annual Form 10-K, and made all critical financial accounting decisions, while purportedly conducting an independent annual audit of the Company.
This lack of internal controls over financial reporting created an opportunity for malfeasance surrounding our funds that was reported in the 2008 and 2009 financial statements. The lack of internal controls also resulted in the need for an internal audit investigation by our CFO that required the investment of Company resources in a forensic accounting to compile the information necessary to restate the financial statements and prepare the records for the examination by our independent auditor.
During our annual audit, Management evaluated remediation plans related to the above internal control deficiencies. Management analyzed the costs and benefits of several different options to improve our internal controls over financial reporting. The following options for improving the controls were analyzed (i) forming an internal audit department, (ii) additional staffing to provide segregation of duties and a review infrastructure for financial reporting, (iii) an information technology department to provide security over our information and to help facilitate electronic filing. In the evaluation, Management estimated implementation of the proposed remediation plan within 1 to 2 years.
During our annual audit, Management evaluated remediation plans related to the above internal control deficiencies. Management remediated the above deficiencies in the 2007 financial statements by (a) hiring a CFO with the appropriate GAAP and SEC reporting skills to reconstruct the 2007 accounting and restate the financial statements, as necessary, (b) induced the former CEO to resign from the Company (on May 15, 2009) and (b) engaged a new independent auditor to audit the restated 2007 financial statements.
Item 9B. Other Information
There are no events required to be disclosed by this Item.
Item 10. Directors, Executive Officers and Corporate Governance
Business Experience and Background of Directors and Executive Officers as of December 31, 2009, 2008, and 2007:
|
Name
|
|
Age
|
|
Positions Held
|
|
Robert J. Miranda (1)
|
|
56
|
|
Current Director, Chairman, CEO, and Chief Financial Officer
|
|
Ronald Zamber (1)
|
|
49
|
|
Current Director
|
|
Edgar Trotter (1)
|
|
66
|
|
Former Director (2)
|
|
Perry Mansell (1)
|
|
63
|
|
Former Director (3)
|
|
Jon Fullenkamp (1)
|
|
55
|
|
Former Director, Chairman , President and CEO (4)
|
|
Rick May (1)
|
|
64
|
|
Former Director (5)
|
|
|
(1)
|
There are no family relationships among our executive officers and directors.
|
|
|
(2)
|
Mr. Trotter resigned from the board effective May 31, 2010.
|
|
|
(3)
|
Mr. Mansell resigned from the board effective November 11, 2010.
|
|
|
(4)
|
Mr. Fullenkamp resigned from the board and as President and CEO effective April 28, 2009.
|
|
|
(5)
|
Mr. May resigned from the board effective September 30, 2009.
|
Robert J. Miranda, CPA – Was appointed as our Chief Financial Officer on November 16, 2008. On April 28, 2009, he was appointed Chairman and interim President and CEO upon the resignation of our former President and CEO, Jon Fullenkamp. On March 28, 2011, he was appointed President and CEO. Since October 2007, Mr. Miranda has been managing director of Miranda & Associates, a professional accountancy corporation. From March 2003 through October 2007, Mr. Miranda was a Global Operations Director at Jefferson Wells, where he specialized in providing Sarbanes-Oxley compliance reviews for public companies. Mr. Miranda was a national director at Deloitte & Touche where he participated in numerous audits, corporate finance transactions, mergers, and acquisitions. Mr. Miranda is a licensed Certified Public Accountant and has over 35 years of experience in accounting, including experience in Sarbanes-Oxley compliance, auditing, business consulting, strategic planning and advisory services. Mr. Miranda holds a B.S. degree in Business Administration from the University of Southern California, a certificate from the Owner/President Management Program from the Harvard Business School and membership in the American Institute of Certified Public Accountants.
Ronald W. Zamber, M.D. Director – Was appointed director on January 24, 2009. Dr. Zamber brings more than 15 years of experience in corporate management and business development extending across public and private companies and non-profit organizations. Since 2000, Dr. Zamber has been president and CEO of The Eye Clinic of Fairbanks (ECF), a private, full service eye care practice based in Fairbanks, Alaska and serving the entire Alaska interior. Dr. Zamber received his bachelor's degree with high honors from the University of Notre Dame and his medical degree with honors from the University of Washington.
Edgar P. Trotter, Ph.D. – Was appointed director on January 24, 2009 and resigned as director on May 31, 2010. Mr. Trotter is Acting Associate Vice President, Undergraduate Programs and Professor, Department of Communications for California State University, Fullerton (CSUF), where he has been a professor since 1975. He has held prior posts as the Chairman of the Department of Communications and as Director of the CSUF Learning Technology Center. Mr. Trotter holds a Ph.D. in Journalism from Southern Illinois University, a Master of Science in Journalism from Ohio University and a Bachelor of Science in Mathematics from Murray State University. He is a former U.S. Navy officer and Vietnam War veteran.
Perry Mansell – Was appointed to the board on February 28, 2007 and resigned on November 11, 2010. Mr. Mansell has owned and operated Mansell Consulting and General Construction since 1970.
Jon Fullenkamp – Was appointed to the board Chairman, President and CEO in January 2005. He resigned from the board and as President and CEO on April 28, 2009.
Rick May – Was appointed to the board on April 8, 2007 and resigned on September 24, 2008. For the past ten years, Mr. May has been the sole owner and CEO of Rapid ID, a Nevada corporation that provides mobile tracking services.
Involvement in Certain Legal Proceedings
The foregoing directors or executive officers have not been involved during the last five years in any of the following events:
Bankruptcy petitions filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time;
Conviction in a criminal proceeding or being subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);
Being subject to any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring or suspending or otherwise limiting his involvement in any type of business, securities or banking activities; or
Being found by a court of competition jurisdiction (in a civil action), the Securities and Exchange Commission or the Commodities Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended or vacated.
Board Composition
Our business and affairs are organized under the direction of our board of directors, which currently consists of three (3) members. The primary responsibilities of our board of directors are to provide oversight, strategic guidance, counseling and direction to our management. Our board of directors meets on a regular basis and additionally as required. Written board materials are distributed in advance as a general rule, and our board of directors schedules meetings with and presentations from members of our senior management on a regular basis and as required.
Our board of directors set schedules to meet throughout the year and also can hold special meetings and act by written consent under certain circumstances.
Limitation of Liability and Indemnification
We intend to enter into indemnification agreements with each of our directors and executive officers and certain other key employees. The form of agreement provides that we will indemnify each of our directors, executive officers, and such other key employees against any and all expenses incurred by that director, executive officer or key employee because of his or her status as one of our directors, executive officers or key employees, to the fullest extent permitted by law and our bylaws (except in a proceeding initiated by such person without board approval). In addition, the form agreement provides that, to the fullest extent permitted by law, we will advance all expenses incurred by our directors, executive officers, and such key employees in connection with a legal proceeding.
The Nevada Revised Statutes and our bylaws contain provisions relating to the limitation of liability and indemnification of directors and officers.
Our bylaws provide that we will indemnify our directors and officers to the fullest extent permitted by law, as it now exists or may in the future be amended, against all expenses and liabilities reasonably incurred in connection with their service for or on our behalf. Our bylaws provide that we shall advance the expenses incurred by a director or officer in advance of the final disposition of an action or proceeding. Our bylaws also authorize us to indemnify any of our employees or agents and permit us to secure insurance on behalf of any officer, director, employee or agent for any liability arising out of their action in that capacity, whether or not the law would otherwise permit indemnification.
Shareholder Communications
Any shareholder of the Company wishing to communicate to the Board of Directors may do so by sending written communication to the board of directors to the attention of Mr. Robert J. Miranda, Chief Executive Officer, at the principal executive offices of the Company. The Board of Directors will consider any such written communication at its next regularly scheduled meeting.
Compliance with Section 16(a) of the Exchange Act:
Under the securities laws of the United States, the Company's directors, its executive officers and any persons holding more than 10% of our common stock are required to report their ownership of our common stock and any changes in that ownership to the Securities and Exchange Commission. Specific due dates for these reports have been established by rules adopted by the SEC and we are required to report in this Annual Report any failure to file by those deadlines.
Based solely upon a review of Forms 3, 4, and 5, and amendments to these forms furnished to us, except as provided below, all parties subject to the reporting requirements of Section 16(a) of the Exchange Act filed on a timely basis all such required reports during and with respect to our 2009 fiscal year.
To the best of our knowledge, the number of late reports for Ron Zamber was 1, the number of transactions that were not reported on a timely basis was 5, and the number of failures to file a required Form was 5.
To the best of our knowledge, the number of late reports for Edgar Trotter was 1, the number of transactions that were not reported on a timely basis was 1, and the number of failures to file a required Form was 1.
To the best of our knowledge, the number of late reports for Robert Miranda was 0, the number of transactions that were not reported on a timely basis was 1, and the number of failures to file a required Form was 1.
Based solely upon a review of Forms 3, 4, and 5, and amendments to these forms furnished to us, except as provided below, all parties subject to the reporting requirements of Section 16(a) of the Exchange Act filed on a timely basis all such required reports during and with respect to our 2008 fiscal year.
To the best of our knowledge, the number of late reports for Robert Miranda was 1, the number of transactions that were not reported on a timely basis was 0, and the number of failures to file a required Form was 0.
Based solely upon a review of Forms 3, 4, and 5, and amendments to these forms furnished to us, except as provided below, all parties subject to the reporting requirements of Section 16(a) of the Exchange Act filed on a timely basis all such required reports during and with respect to our 2007 fiscal year.
Rick May was appointed to our board of directors on January 29, 2007 and Perry Mansell was appointed to our board of directors on February 28, 2007. In both cases, the required Form 3’s were filed late.
Code of Ethics
We have not adopted a code of ethics to apply to our principal executive officer, principal financial officer, principal accounting officer and controller, or persons performing similar functions. We expect to prepare a Code of Ethics in the near future.
Item 11. Executive Compensation
The following table sets forth the total compensation awarded to, earned by, or paid to our “principal executive officer,” and our other named executive officers for all services rendered in all capacities to us in 2009, 2008, and 2007.
|
Name and
Principal
Position
|
|
Year
|
|
Salary
($)
|
|
|
Bonus
($)
|
|
|
Stock
Awards
($)
|
|
|
Option
Awards
($)
|
|
|
Non-Equity
Incentive Plan
Compensation
($)
|
|
|
Nonqualified
Deferred
Compensation
($)
|
|
|
All Other
Compensation
($)
|
|
|
Total
($)
|
|
|
Robert J. Miranda
|
|
2009
|
|
|
180,000 |
(3) |
|
|
- |
|
|
|
- |
|
|
|
5,795 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
185,795 |
|
|
Chairman, CEO, and CEO (1) (3)
|
|
2008
|
|
|
10,000 |
(3) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
10,000 |
|
| |
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jon Fullenkamp
|
|
2009
|
|
|
104,167 |
|
|
|
- |
|
|
|
- |
|
|
|
1,392 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
105,559 |
|
|
former Chairman, CEO, and CFO (2)
|
|
2008
|
|
|
250,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
250,000 |
|
| |
|
2007
|
|
|
250,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
250,000 |
|
|
|
(1)
|
Appointed CFO on November 16, 2008; director on January 24, 2009; and Chairman, President & interim CEO on April 28, 2009; CEO on March 28, 2011.
|
|
|
(2)
|
Jon Fullenkamp resigned effective April 28, 2009.
|
|
|
(3)
|
Represents the portion of the total consulting fees paid to Miranda & Associates, A Professional Accountancy Corporation, that is wholly-owned by Mr. Miranda, in consideration of services, attributable to the services provided by Mr. Miranda as an executive officer of Victory Energy Corporation.
|
Director Compensation
The following table sets forth the total compensation awarded to, earned by, or paid to each person who served as a director during the years ended December 31, 2009, 2008, and 2007, other than a director who also served as a named executive officer. Our directors who are not executive officers did not receive any cash compensation for serving on our board of directors. We have a policy of reimbursing our directors for their reasonable out-of-pocket expenses incurred in attending Board and committee meetings. Each director is paid for his or her director services in the form of 100,000 warrants monthly for each month of service. These five (5) year warrants are exercisable into common stock at an exercise price $0.01, and vest immediately upon issuance.
|
Name
|
|
Year
|
|
Fees
Earned
or Paid
in Cash
($)
|
|
|
Stock
Awards
($)
|
|
|
Option
Awards
($)
|
|
|
Non-Equity
Incentive
Compensation
($)
|
|
|
Nonqualified
Deferred
Compensation
Earnings
($)
|
|
|
All Other
Compensation
($)
|
|
|
Total
($)
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Edgar Trotter, Former Director (2)
|
|
2009
|
|
|
- |
|
|
|
- |
|
|
|
5,795 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5,795 |
|
| |
|
2008
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Perry Mansell, Former Director (1)
|
|
2009
|
|
|
- |
|
|
|
- |
|
|
|
5,312 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5,312 |
|
| |
|
2008
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ronald Zamber,
Current Director
|
|
2009
|
|
|
- |
|
|
|
- |
|
|
|
5,795 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5,795 |
|
| |
|
2008
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1)
|
– Perry Mansell resigned effective November 11, 2009
|
|
|
(2)
|
– Edgar Trotter resigned effective May 31, 2010
|
|
|
(3)
|
– Jon Fullenkamp resigned effective April 28, 2009
|
|
|
(4)
|
– Rick May resigned effective September 30, 2008
|
Outstanding Equity Awards at Fiscal Year-End
The following table sets forth certain information concerning outstanding stock awards held by the named executive officers as of December 31, 2009, 2008, and 2007.
| |
|
Option Awards
|
|
|
Stock Awards
|
|
|
Name
|
|
Year
|
|
Number of
Securities
Underlying
Unexercised
Options
(#)
Exercisable
|
|
|
Number of
Securities
Underlying
Unexercised
Options (#)
Unexercisable
|
|
|
Equity
Incentive
Plan
Awards:
Number of
Securities
Underlying
Unexercised
Unearned
Options
(#)
|
|
|
Option
Exercise
Price
($)
|
|
|
Option
Expiration
Date
|
|
|
Number
of
Shares
or Units
of
Stock
That
Have
Not
Vested
(#)
|
|
|
Market
Value
of
Shares
or
Units
of
Stock
That
Have
Not
Vested
($)
|
|
|
Equity
Incentive
Plan
Awards:
Number
of
Unearned
Shares,
Units or
Other
Rights
That
Have Not
Vested
(#)
|
|
|
Equity
Incentive
Plan
Awards:
Market
or Payout
Value of
Unearned
Shares,
Units or
Other
Rights
That
Have Not
Vested
($)
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Robert J. Miranda Chairman, CEO, and CEO
|
|
2009
|
|
|
1,200,000 |
|
|
|
- |
|
|
|
- |
|
|
$ |
0.01 |
|
|
12/31/2014
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
2008
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jon Fullenkamp former Chairman, CEO, and CFO
|
|
2009
|
|
|
400,000 |
|
|
|
- |
|
|
|
- |
|
|
$ |
0.01 |
|
|
12/31/2014
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
2008
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Securities Authorized for Issuance under Equity Compensation Plans
The following table sets forth information concerning the Company’s equity compensation plans as of December 31, 2009, 2008, and 2007.
|
Equity Compensation Plan Information
|
|
| |
|
Year
|
|
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
|
|
|
Weighted average
exercise price of
outstanding options,
warrants and rights
|
|
|
Number of securities
remaining available
for future issuance
|
|
|
Plan category
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation plans approved by security holders
|
|
2009
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
2008
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation plans not approved by shareholders
|
|
2009
|
|
|
13,362,226 |
|
|
$ |
0.13 |
|
|
|
8,400,000 |
|
| |
|
2008
|
|
|
7,713,557 |
|
|
$ |
0.21 |
|
|
|
- |
|
| |
|
2007
|
|
|
2,420,000 |
|
|
$ |
0.28 |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
2009
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
2008
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
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 currently exercisable or exercisable within 60 days of December 31, 2009, 2008, and 2007, are deemed outstanding and beneficially owned by the person holding such options for purposes of computing the number of shares and percentage beneficially owned by such person, but are not deemed outstanding for purposes of computing the percentage beneficially owned by any other person. Except as indicated in the footnotes to these tables, and subject to applicable community property laws, the persons or entities named have sole voting and investment power with respect to all shares of our common stock shown as beneficially owned by them.
The following is the schedule of beneficial ownership as of December 31, 2009:
|
Name and
Position
|
|
Business
Address
|
|
Common
Stock
|
|
|
Warrants (4)
|
|
|
Total
|
|
|
Percent
of Class
(1)
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
John Fullenkamp,
Former CEO and Director
|
|
27762 Antonio Parkway
Ladera Ranch, CA 92694
|
|
|
16,177,896 |
|
|
|
400,000 |
|
|
|
16,577,896 |
(2) |
|
|
12.1 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ronald Zamber, Director
|
|
1919 Lathrop Suite 103
Fairbanks, AK 99701
|
|
|
8,312,578 |
|
|
|
5,242,226 |
|
|
|
13,554,804 |
|
|
|
9.9 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Perry Mansell,
Former Director
|
|
20341 Irvine Avenue, #D6
Newport Beach, CA 92660
|
|
|
925,000 |
|
|
|
1,000,000 |
|
|
|
1,925,000 |
|
|
|
1.5 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Robert Miranda, Chairman, CEO, CFO, and Director
|
|
20341 Irvine Avenue, #D6
Newport Beach, CA 92660
|
|
|
— |
|
|
|
1,200,000 |
|
|
|
1,200,000 |
|
|
|
0.9 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Edgar Trotter,
Former Director
|
|
20341 Irvine Avenue, #D6
Newport Beach, CA 92660
|
|
|
— |
|
|
|
1,200,000 |
|
|
|
1,200,000 |
|
|
|
0.9 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Officers and Directors As a Group (5 Persons)
|
|
|
|
|
25,415,474 |
|
|
|
9,142,226 |
|
|
|
34,557,700 |
|
|
|
25.3 |
% |
|
|
(1)
|
Based on 136,719,608 shares outstanding.
|
|
|
(2)
|
Ron Zamber holds a proxy to vote all the Fullenkamp shares.
|
|
|
(3)
|
Includes 4,042,226 of warrants of James Capital Consulting, LLC; Ron Zamber is the managing member of this entity
|
|
|
(4)
|
All warrants were exercisable immediately.
|
The following is the schedule of beneficial ownership as of December 31, 2008:
|
Name and
Position
|
|
Business
Address
|
|
Common
Stock
|
|
|
Warrants
(2)
|
|
|
Total
|
|
|
Percent
of Class
(1)
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
John Fullenkamp,
Former CEO and Director
|
|
27762 Antonio Parkway
Ladera Ranch, CA 92694
|
|
|
18,769,038 |
|
|
|
— |
|
|
|
18,769,038 |
|
|
|
13.7 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Perry Mansell,
Former Director
|
|
20341 Irvine Avenue, #D6
Newport Beach, CA 92660
|
|
|
925,000 |
|
|
|
— |
|
|
|
925,000 |
|
|
|
.07 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rick May, Former Director
|
|
20341 Irvine Avenue, #D6
Newport Beach, CA 92660
|
|
|
625,000 |
|
|
|
— |
|
|
|
625,000 |
|
|
|
0.5 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ronald
Zamber, >5%
Shareholder
|
|
1919 Lathrop
Suite 103
Fairbanks, AK
99701
|
|
|
8,312,578 |
|
|
|
3,693,557 |
|
|
|
12,006,135 |
|
|
|
8.8 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Officers and Directors As a Group (3 Persons)
|
|
|
|
|
20,319,038 |
|
|
|
— |
|
|
|
20,319,038 |
|
|
|
14.9 |
% |
|
|
(1)
|
Based on 136,719,608 shares outstanding.
|
|
|
(2)
|
All warrants were exercisable immediately.
|
The following is the schedule of beneficial ownership as of December 31, 2007:
|
Name and Position
|
|
Business
Address
|
|
Common
Stock
|
|
|
Warrants
|
|
|
Total
|
|
|
Percent of
Class
(1)
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
John Fullenkamp,
Former CEO and Director
|
|
27762 Antonio Parkway
Ladera Ranch, CA 92694
|
|
|
15,737,616 |
|
|
|
— |
|
|
|
15,737,616 |
|
|
|
37.1 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Perry Mansell,
Former Director
|
|
20341 Irvine Avenue, #D6
Newport Beach, CA 92660
|
|
|
540,000 |
|
|
|
— |
|
|
|
540,000 |
|
|
|
1.3 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rick May, Former Director
|
|
20341 Irvine Avenue, #D6
Newport Beach, CA 92660
|
|
|
540,000 |
|
|
|
— |
|
|
|
540,000 |
|
|
|
1.3 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Officers and Directors As a Group (3 Persons)
|
|
|
|
|
16,817,616 |
|
|
|
— |
|
|
|
16,817,616 |
|
|
|
39.7 |
% |
|
|
(1)
|
Based on 42,395,366 shares outstanding.
|
Item 13. Certain Relationships and Related Transactions, and Director Independence
Related Party Transactions
Year ended December 31, 2009:
During 2009, we entered into unsecured notes payable totaling $195,000 with Ronald Zamber, a director. These notes bear interest at a fixed rate of 10% and mature on December 31, 2010. The unpaid balance of unsecured notes payable to Mr. Zamber is $355,000 as of December 31, 2009.
On May 15, 2009, the Company entered into a “Separation Agreement and General Release of Claims” with Jon Fullenkamp (“Fullenkamp”) and the Virgin Family Trust. The terms of the Agreement include (a) termination of an employment agreement between the Company and Fullenkamp; (b) payment of all accrued salaries, unreimbursed expenses, and shareholder advances previously made by Fullenkamp; (c) reduction of shareholder advances from estimated balance owed at the time of settlement of $1,665,375 to a balance of $500,000 (the “Separation Settlement”); (d) Payment terms of the Separation Settlement of $10,000 monthly commencing June 1, 2009, and payable over a fifty (50) month period, including imputed interest at the rate of 3.52% per annum; (e) cancellation of 2,000,000 shares of preferred stock, convertible at the rate of 100 shares of common, (d) lockup agreement with respect to all shares owned directly or indirectly by Fullenkamp for a period of five years, (e) Fullenkamp was to cooperate with the Company to recover misappropriated funds and agreed to bring litigation or induce others to bring litigation against the Company.
At the time of the agreement, Fullenkamp was owed the sum of approximately $1,665,375 in shareholder advances which were settled for $500,000, resulting in a gain on the settlement of this debt of $1,199,748. After the first payment of $10,000 the company recorded a discount of 3.25% on $490,000, the minimum federal rate in the amount of $34,373 against the note. The discount is amortized to interest expense over the period of estimated maturity. During the year ended December 31, 2009, the Company recorded interest expense of $8,997 and the note had an unamortized discount of $24,476. During the year ended December 31, 2009, the Company paid $51,004 of the principal of the Separation Settlement, reducing the outstanding balance as of December 31, 2009 to $404,623.
During the year ended December 31, 2009, we incurred a total of $328,610 of accounting, internal audit, CEO & CFO management, and tax, and business turnaround consulting fees with Miranda & Associates, A Professional Accountancy Corporation (“Miranda”). Of these fees, $180,000 is attributable to the services of Robert Miranda as an executive officer of the Company. The balance of $148,610 incurred with Miranda relates to internal audit, tax, and advisory services provided by other members of the Miranda firm. As of December 31, 2009, Miranda & Associates was owed $95,734 for these professional services.
Year ended December 31, 2008:
During 2008, we entered into unsecured notes payable totaling $160,000 with Ronald Zamber, a director. These notes bear interest at a fixed rate of 10% and mature on December 31, 2010. The unpaid balance of unsecured notes payable to Mr. Zamber is $160,000 as of December 31, 2008.
During 2008, we entered into loans payable with Jon Fullenkamp, former Chairman and CEO, in the amount of $258,659. As of December 31, 2008, we owed Jon Fullenkamp $1,636,538 for these unsecured loans. These loans were settled on May 15, 2009, upon the entry of the Separation Agreement between us and Jon Fullenkamp. On March 24, 2011 the Company and Jon Fullenkamp entered into a comprehensive Settlement Agreement whereby they, among other things, cancelled the Separation Agreement and waived all rights thereunder.
During the year ended December 31, 2008, we incurred a total of $30,550 of accounting, internal audit, CFO, tax, and fees with Miranda & Associates, A Professional Accountancy Corporation (“Miranda”). Of these fees, $5,000 is attributable to the services of Robert Miranda as an executive officer of the Company. The balance of $25,550 incurred with Miranda relates to SEC compliance, accounting, tax, and advisory services provided by other members of the Miranda firm. As of December 31, 2009, Miranda & Associates was owed $25,550 for these professional services.
Year ended December 31, 2007:
During 2007, we entered into loans payable with Jon Fullenkamp, former Chairman and CEO, in the amount of $687,794. These loans were settled on May 15, 2009, upon the entry of the Separation Agreement between us and Jon Fullenkamp. As of December 31, 2008, we owe Jon Fullenkamp $1,377,879 for these unsecured loans.
Employment, Compensation and Consulting Agreements
Consulting Services Agreement, dated effective November 16, 2008, between the Company and Miranda & Associates, A Professional Accountancy Corporation
On November 16, 2008, we entered into a consulting services agreement with Miranda & Associates, A Professional Accountancy Corporation. Under the terms of the agreement, Mr. Miranda has agreed to serve as our Chief Financial Officer on an at-will basis. The employment agreement has an effective date of November 16, 2008.
The agreement provides for an initial base retainer of $2,500 per month with an increase to be made quarterly as time and fees are incurred. We have agreed to maintain in effect a directors’ and officers’ liability insurance policy with a minimum limit of liability of $1 million and that we would enter into an indemnification agreement with Mr. Miranda upon terms mutually acceptable to us and Mr. Miranda.
We may terminate the agreement at any time, with or without due cause. “Due cause” includes any intentional misapplication of our funds or other material assets, or any other act of dishonesty injurious to us, or conviction of a felony or a crime involving moral turpitude. “Due cause” also includes abuse of controlled substances or alcohol and breach, nonperformance or nonobservance of any of the terms of the agreement, provided that Mr. Miranda fails to satisfactorily remedy the performance problem following 30 days’ written notice. Miranda & Associates may terminate the agreement at any time, with or without good reason, upon 30 days notice.
Consulting Services Agreement, dated effective August 1, 2009, between the Company and Miranda & Associates, A Professional Accountancy Corporation
On August 1, 2009, we entered into a consulting services agreement with Miranda & Associates, A Professional Accountancy Corporation. Under the terms of the agreement, Mr. Miranda has agreed to serve as our interim President, Chief Executive Officer, and Chief Financial Officer on an at-will basis. The consulting services agreement has an effective date of August 1, 2009. The agreement replaces the prior agreement for CFO services dated November 16, 2009.
The agreement provides for an initial base retainer of $15,000 per month with an increase to be made quarterly as time and fees are incurred. We have agreed to maintain in effect a directors’ and officers’ liability insurance policy with a minimum limit of liability of $1 million and that we would enter into an indemnification agreement with Mr. Miranda upon terms mutually acceptable to us and Mr. Miranda.
We may terminate the agreement at any time, with or without due cause. “Due cause” includes any intentional misapplication of our funds or other material assets, or any other act of dishonesty injurious to us, or conviction of a felony or a crime involving moral turpitude. “Due cause” also includes abuse of controlled substances or alcohol and breach, nonperformance or nonobservance of any of the terms of the agreement, provided that Mr. Miranda fails to satisfactorily remedy the performance problem following 30 days’ written notice. Miranda & Associates may terminate the agreement at any time, with or without good reason, upon 30 days notice.
Director Independence
We are quoted on the OTC Markets. While the OTC Markets does not maintain director independence standards, we are taking the necessary steps to qualify as having independent directors under the guidelines of FINRA.
Item 14. Principal Accounting Fees and Services
Audit Fees
We did not file when due our Annual Report on Form 10-K for the fiscal year ended December 31, 2009 or Quarterly Reports on Forms 10-Q for the interim 2009 periods. Accordingly, the aggregate fees billed for the fiscal year ended December 31, 2009 for professional services rendered by the principal accountant for the audit of our annual financial statements and review of the financial statements or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements for that fiscal year was $0. The aggregate fees billed in each of the fiscal years ended December 31, 2008 and 2007 for professional services rendered by the principal accountant for the audit of our annual financial statements and review of the financial statements or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements was $0 and $7,500, respectively.
Audit - Related Fees
The aggregate fees billed in the fiscal year ended December 31, 2008 and 2007 for professional services rendered by the principal accountant for the review of the financial statements included in our Forms 10-Q for the quarterly periods ended March 31, 2008, June 30, 2008 and September 30, 2008, and March 31, 2007, June 30, 2007, and September 30, 2007 were included in the audit fees above.
Tax Fees
For the fiscal years ended December 31, 2009, 2008, and 2007 our principal accountants did not render any services for tax compliance, tax advice, and tax planning work.
All Other Fees
None.
Of the fees described above for the years ended December 31, 2008 and 2007, 100% were approved by the entire board of directors.
Part IV
Item 15. Exhibits, Financial Statement Schedules
(a)(1) and (2) Financial Statements and Schedules
INDEX TO FINANCIAL STATEMENTS
| |
Page
|
| |
|
|
Report of Independent Registered Public Accounting Firm
|
F-1
|
| |
|
|
Consolidated Balance Sheets as of December 31, 2009, 2008, and 2007
|
F-2
|
| |
|
|
Consolidated Statements of Operations for the Years Ended December 31, 2009, 2008, and 2007
|
F-3
|
| |
|
|
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008, and 2007
|
F-4
|
| |
|
|
Consolidated Statement of Shareholder’s Deficiency for the Years Ended
|
|
|
December 31, 2009, 2008, and 2007
|
F-5
|
| |
|
|
Supplemental Schedules of Restatement for the Balance Sheet and Statements of Operation, and Cash Flow for the Year Ending December 31, 2007
|
F-7
|
| |
|
|
Supplemental Schedules of Balance Sheet, Statements of Operations and Cash Flow for the Calendar Quarters Ending
|
|
| |
|
|
March 31, 2008 (As Restated)
|
F-10
|
| |
|
|
June 30, 2008 (As Restated)
|
F-13
|
| |
|
|
September 30, 2008 (As Restated)
|
F-16
|
| |
|
|
March 31, 2009
|
F-19
|
| |
|
|
June 30, 2009
|
F-22
|
| |
|
|
September 30, 2009
|
F-25
|
| |
|
|
Notes to Financial Statements for the Years Ended
|
|
|
December 31, 2009, 2008, and 2007
|
F-28
|
(a)(3) Exhibits
Refer to (b) below.
|
(b)
|
|
Exhibits
|
| |
|
|
|
3.1
|
|
Articles of Incorporation of All Things, Inc., filed on January 7, 1982
|
| |
|
|
|
3.2
|
|
Certificate of Amendment of Articles of Incorporation, filed on January 7, 1982
|
| |
|
|
|
3.3
|
|
Certificate of Amendment of Articles of Incorporation, filed on March 21, 1985
|
| |
|
|
|
3.4
|
|
Certificate of Amendment of Articles of Incorporation, filed on November 1, 1995
|
| |
|
|
|
3.5
|
|
Certificate of Amendment of Articles of Incorporation, filed on April 28, 2003
|
|
3.6
|
|
Certificate of Amendment of Articles of Incorporation, filed on May 3, 2006
|
| |
|
|
|
3.7
|
|
Certificate of Amendment of Articles of Incorporation, filed on May 10, 2006
|
| |
|
|
|
3.8
|
|
Certificate of Amendment of Articles of Incorporation, filed on August 22, 2006
|
| |
|
|
|
3.9
|
|
Certificate of Amendment of Articles of Incorporation, filed on October 3, 2008
|
| |
|
|
|
3.10
|
|
Bylaws of Victory Energy Corporation
|
| |
|
|
|
10.1
|
|
Unsecured Promissory Notes (Zamber)
|
10.2 The Victory Energy Corporation/James Capital Energy, LLC, Joint Venture Partnership Agreement by and between Victory Energy Corporation, James Capital Energy, LLC and James Capital Consulting dated December 31, 2009
10.3 First Amendment to The Victory Energy Corporation/James Capital Energy, LLC, Joint Venture Partnership Agreement, changing the name of the Partnership to “Aurora Energy Partners, A Texas General Partnership, dated March 31, 2010
10.4 Separation Agreement by and between Victory Energy Corporation and Jon Fullenkamp dated May 15, 2009
10.5 Settlement Agreement and Mutual General Release by and between Jon Fullenkamp and Xploration, on the one hand; and Victory Energy Corporation, James Capital Energy, LLC, James Capital Consulting, LLC, James Capital, LLC, Aurora Energy Partners, Zamber Energy Investments, LLC, International Vision Quest, Miranda & Associates, Ronald Zamber, Robert Miranda, Richard May, and Tom Konz, on the other hand.
10.6 Consulting Services Agreement by and between Victory Energy Corporation and Miranda & Associates, A Professional Accountancy Corporation dated November 16, 2008
10.7 Consulting Services Agreement by and between the Victory Energy Corporation and Miranda & Associates, A Professional Accountancy Corporation, dated August 1, 2009
31.1 Rule 13a-14(a)/15d-14(a) Certification of Robert Miranda
31.2 Rule 13a-14(a)/15d-14(a) Certification of Robert Miranda
32 Section 1350 Certification of Robert Miranda
SIGNATURES
In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
Date: March 28, 2011
|
VICTORY ENERGY CORPORATION
|
| |
|
|
| |
By:
|
/s/ Robert J. Miranda
|
| |
|
Robert J. Miranda
|
| |
|
Chief Executive Officer,
Chief Financial Officer,
Chairman, and Director
|
In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
|
Date: March 28, 2011
|
By:
|
/s/ Ronald W. Zamber
|
| |
|
Ronald W. Zamber
Director
|
| |
|
|
|
Date: March 28, 2011
|
By:
|
/s/ Robert Grenley
|
| |
|
Robert Grenley
|
| |
|
Director
|
| |
|
|
|
Date: March 28, 2011
|
By:
|
/s/ David B. McCall
|
| |
|
David B. McCall
Director
|
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders of
Victory Energy Corporation
Newport Beach, California
We have audited the accompanying balance sheets of Victory Energy Corporation (the “Company”) as of December 31, 2009, 2008, and 2007, and the related statements of operations, shareholders’ deficit and cash flows for the years ended December 31, 2009, 2008, and 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2009, 2008, and 2007, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
The accompanying financial statements have been prepared assuming the Company will continue as a going concern. The Company has experienced recurring losses since inception and has an accumulated deficit. These conditions raise substantial doubt regarding the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are described in Note 1 to the financial statements. The financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of this uncertainty.
/s/ WilsonMorgan LLP
Irvine, California
March 28, 2011
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
| |
|
December 31,
|
|
| |
|
2009
|
|
|
2008
|
|
|
2007
|
|
| |
|
|
|
|
|
|
|
(As Restated)
|
|
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
22,076 |
|
|
$ |
166,189 |
|
|
$ |
3,251 |
|
|
Accounts receivable, net
|
|
|
100,319 |
|
|
|
- |
|
|
|
- |
|
|
Prepaid expenses
|
|
|
46,818 |
|
|
|
7,250 |
|
|
|
- |
|
|
Total current assets
|
|
|
169,213 |
|
|
|
173,439 |
|
|
|
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
FIXED ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Furniture and equipment
|
|
|
2,294 |
|
|
|
2,294 |
|
|
|
2,294 |
|
|
Accumulated depreciation
|
|
|
(2,294 |
) |
|
|
(2,294 |
) |
|
|
(2,294 |
) |
|
Total furniture and equipment
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties
|
|
|
1,660,533 |
|
|
|
1,594,565 |
|
|
|
- |
|
|
Accumulated depletion
|
|
|
(853,152 |
) |
|
|
(562,808 |
) |
|
|
- |
|
|
Oil and natural gas properties, net
|
|
|
807,381 |
|
|
|
1,031,757 |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funds held by court
|
|
|
13,006 |
|
|
|
5,664 |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$ |
989,600 |
|
|
$ |
1,210,860 |
|
|
$ |
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS' DEFICIT
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$ |
240,310 |
|
|
$ |
38,257 |
|
|
$ |
34,803 |
|
|
Accrued liabilities
|
|
|
61,331 |
|
|
|
110 |
|
|
|
- |
|
|
Accrued interest
|
|
|
27,148 |
|
|
|
- |
|
|
|
- |
|
|
Line of credit - bank
|
|
|
85,444 |
|
|
|
94,353 |
|
|
|
81,860 |
|
|
Notes payable - related parties
|
|
|
355,000 |
|
|
|
383,673 |
|
|
|
- |
|
|
Liability for unauthorized preferred stock issued
|
|
|
85,654 |
|
|
|
32,159 |
|
|
|
217,614 |
|
|
Amounts due former officer
|
|
|
404,623 |
|
|
|
1,636,536 |
|
|
|
1,377,882 |
|
|
Total Current Liabilities
|
|
|
1,259,510 |
|
|
|
2,185,088 |
|
|
|
1,712,159 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation
|
|
|
34,977 |
|
|
|
20,120 |
|
|
|
- |
|
|
TOTAL LIABILITIES
|
|
|
1,294,487 |
|
|
|
2,205,208 |
|
|
|
1,712,159 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS' DEFICIT
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock, $0.001 par value, 10,000,000 shares authorized; none issued and outstanding after restatement
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Common Stock, $0.001 par value, 200,000,000 shares authorized, 136,719,608, 136,719,608 and 42,395,366 issued and outstanding, respectively
|
|
|
136,720 |
|
|
|
136,720 |
|
|
|
42,395 |
|
|
Additional paid in capital
|
|
|
31,263,272 |
|
|
|
30,188,672 |
|
|
|
14,116,707 |
|
|
Accumulated Deficit
|
|
|
(31,704,879 |
) |
|
|
(31,319,740 |
) |
|
|
(15,868,010 |
) |
|
TOTAL STOCKHOLDERS' DEFICIT
|
|
|
(304,887 |
) |
|
|
(994,348 |
) |
|
|
(1,708,908 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT
|
|
$ |
989,600 |
|
|
$ |
1,210,860 |
|
|
$ |
3,251 |
|
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
| |
|
For the Years Ended December 31,
|
|
| |
|
2009
|
|
|
2008
|
|
|
2007
|
|
| |
|
|
|
|
|
|
|
(As Restated)
|
|
|
REVENUES
|
|
$ |
512,607 |
|
|
$ |
1,642,631 |
|
|
$ |
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
COSTS AND EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of production
|
|
|
196,520 |
|
|
|
934,534 |
|
|
|
- |
|
|
General and administrative expense
|
|
|
935,983 |
|
|
|
3,519,409 |
|
|
|
10,320,050 |
|
|
Depletion and accretion
|
|
|
291,867 |
|
|
|
564,377 |
|
|
|
- |
|
|
Malfeasance losses
|
|
|
280,647 |
|
|
|
4,955,793 |
|
|
|
- |
|
|
Impairment of oil and natural gas properties
|
|
|
342,366 |
|
|
|
2,775,696 |
|
|
|
- |
|
|
Loss (gain) on settlement with former officer
|
|
|
(1,199,748 |
) |
|
|
390,000 |
|
|
|
- |
|
|
Total costs and expenses
|
|
|
847,635 |
|
|
|
13,139,809 |
|
|
|
10,320,050 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
LOSS FROM OPERATIONS
|
|
|
(335,028 |
) |
|
|
(11,497,178 |
) |
|
|
(10,320,050 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME AND EXPENSE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
50,111 |
|
|
|
979 |
|
|
|
6,639 |
|
|
Total other expense
|
|
|
50,111 |
|
|
|
979 |
|
|
|
6,639 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS
|
|
$ |
(385,139 |
) |
|
$ |
(11,498,157 |
) |
|
$ |
(10,326,689 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares, basic and diluted
|
|
|
136,719,608 |
|
|
|
95,529,303 |
|
|
|
23,587,429 |
|
|
Net loss per share, basic and diluted
|
|
$ |
(0.00 |
) |
|
$ |
(0.12 |
) |
|
$ |
(0.44 |
) |
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW
| |
|
For the Years Ended December 31,
|
|
| |
|
2009
|
|
|
2008
|
|
|
2007
|
|
| |
|
|
|
|
|
|
|
(Restated)
|
|
|
CASH FLOW FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$ |
(385,139 |
) |
|
$ |
(11,498,157 |
) |
|
$ |
(10,326,689 |
) |
|
Adjustment to reconcile net loss from operations to net cash used in operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion
|
|
|
290,344 |
|
|
|
562,808 |
|
|
|
- |
|
|
Amortization of debt discount
|
|
|
8,997 |
|
|
|
|
|
|
|
|
|
|
Accretion of asset retirement obligation
|
|
|
1,523 |
|
|
|
1,569 |
|
|
|
- |
|
|
Impairment of oil and natural gas properties
|
|
|
342,366 |
|
|
|
2,775,696 |
|
|
|
- |
|
|
Common stock for services
|
|
|
- |
|
|
|
2,082,125 |
|
|
|
9,492,665 |
|
|
Common stock for settlement
|
|
|
- |
|
|
|
390,000 |
|
|
|
- |
|
|
Warrants for services
|
|
|
27,791 |
|
|
|
342,730 |
|
|
|
109,000 |
|
|
Gain on settlement with former officer
|
|
|
(1,199,748 |
) |
|
|
- |
|
|
|
- |
|
|
Change in working capital
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(100,319 |
) |
|
|
(5,664 |
) |
|
|
- |
|
|
Funds held by court
|
|
|
(7,342 |
) |
|
|
- |
|
|
|
- |
|
|
Prepaid expense
|
|
|
(39,568 |
) |
|
|
(7,250 |
) |
|
|
- |
|
|
Accounts payable
|
|
|
202,053 |
|
|
|
3,409 |
|
|
|
15,579 |
|
|
Accrued liabilities
|
|
|
88,369 |
|
|
|
110 |
|
|
|
- |
|
|
Asset retirement obligations
|
|
|
13,334 |
|
|
|
18,551 |
|
|
|
- |
|
|
Net cash used in operating activities
|
|
|
(757,339 |
) |
|
|
(5,334,073 |
) |
|
|
(709,445 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilled wells
|
|
|
(9,715 |
) |
|
|
(1,746,727 |
) |
|
|
- |
|
|
Purchase of wells
|
|
|
(398,619 |
) |
|
|
(2,623,534 |
) |
|
|
- |
|
|
Net cash used in investing activities
|
|
|
(408,334 |
) |
|
|
(4,370,261 |
) |
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank line of credit net borrowings (repayments)
|
|
|
(8,909 |
) |
|
|
12,493 |
|
|
|
24,899 |
|
|
Proceeds from notes payable to related parties
|
|
|
325,000 |
|
|
|
383,673 |
|
|
|
- |
|
|
Proceeds from former officer
|
|
|
19,838 |
|
|
|
300,412 |
|
|
|
687,797 |
|
|
Proceeds from unauthorized preferred stock issued
|
|
|
53,499 |
|
|
|
- |
|
|
|
- |
|
|
Payments on notes payable to related parties
|
|
|
(353,673 |
) |
|
|
- |
|
|
|
- |
|
|
Payments to former officer
|
|
|
(61,004 |
) |
|
|
(41,758 |
) |
|
|
- |
|
|
Warrants exercised
|
|
|
- |
|
|
|
350,000 |
|
|
|
- |
|
|
Aurora capital contributions
|
|
|
1,371,674 |
|
|
|
9,733,892 |
|
|
|
- |
|
|
Aurora capital distributions
|
|
|
(324,865 |
) |
|
|
(931,490 |
) |
|
|
- |
|
|
Sale of common stock
|
|
|
- |
|
|
|
60,050 |
|
|
|
- |
|
|
Net cash provided by financing activities
|
|
|
1,021,560 |
|
|
|
9,867,272 |
|
|
|
712,696 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
(144,113 |
) |
|
|
162,938 |
|
|
|
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning cash and cash equivalents
|
|
|
166,189 |
|
|
|
3,251 |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending cash and cash equivalents
|
|
$ |
22,076 |
|
|
$ |
166,189 |
|
|
$ |
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental schedule of non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock dividend paid
|
|
$ |
- |
|
|
$ |
3,953,573 |
|
|
$ |
- |
|
|
Preferred stock converted to common stock
|
|
$ |
- |
|
|
$ |
185,458 |
|
|
$ |
29,336 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosures of cash flow information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the period for
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
Income taxes
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
VICTORY ENERGY CORPORATION AND SUBSIDARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT)
| |
|
Common Stock $0.001 Par
|
|
|
Preferred Stock $0.001 Par
|
|
|
Additional Paid In
|
|
|
|
|
|
|
|
|
Description
|
|
Number
|
|
|
Amount
|
|
|
Number
|
|
|
Amount
|
|
|
Capital
|
|
|
Accumulated Deficit
|
|
|
|
|
|
|
|
|
4,518,515 |
|
|
$ |
4,518 |
|
|
|
715,517 |
|
|
$ |
716 |
|
|
$ |
4,566,320 |
|
|
$ |
(5,491,321 |
) |
|
$ |
(919,767 |
) |
|
Adjustments for restatement
|
|
|
- |
|
|
|
- |
|
|
|
(715,517 |
) |
|
|
(716 |
) |
|
|
(42,734 |
) |
|
|
(50,000 |
) |
|
|
(93,450 |
) |
|
Balance, January 1,2007 (As restated)
|
|
|
4,518,515 |
|
|
|
4,518 |
|
|
|
- |
|
|
|
- |
|
|
|
4,523,586 |
|
|
|
(5,541,321 |
) |
|
|
(1,013,217 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transactions as reported
|
|
|
37,876,851 |
|
|
|
37,877 |
|
|
|
(85,000 |
) |
|
|
(85 |
) |
|
|
3,294,011 |
|
|
|
(3,896,827 |
) |
|
|
(565,024 |
) |
|
Adjustments for restatement
|
|
|
- |
|
|
|
- |
|
|
|
85,000 |
|
|
|
85 |
|
|
|
6,299,110 |
|
|
|
(6,429,862 |
) |
|
|
(130,667 |
) |
|
Balance, December 31, 2007 (As restated)
|
|
|
42,395,366 |
|
|
$ |
42,395 |
|
|
|
- |
|
|
$ |
- |
|
|
$ |
14,116,707 |
|
|
$ |
(15,868,010 |
) |
|
$ |
(1,708,908 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock in exchange for services
|
|
|
13,150,000 |
|
|
|
13,150 |
|
|
|
- |
|
|
|
- |
|
|
|
1,599,075 |
|
|
|
- |
|
|
|
1,612,225 |
|
|
Warrants in exchange for services
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
245,000 |
|
|
|
- |
|
|
|
245,000 |
|
|
Preferred stock converted to common
|
|
|
4,482,758 |
|
|
|
4,483 |
|
|
|
- |
|
|
|
- |
|
|
|
10,987 |
|
|
|
- |
|
|
|
15,470 |
|
|
Common stock for cash
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
41,400 |
|
|
|
- |
|
|
|
41,400 |
|
|
Aurora capital contributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,750,000 |
|
|
|
- |
|
|
|
2,750,000 |
|
|
Aurora capital distributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(273,700 |
) |
|
|
- |
|
|
|
(273,700 |
) |
|
Net loss for quarter
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1,956,458 |
) |
|
|
(1,956,458 |
) |
|
Balance, March 31, 2008
|
|
|
60,028,124 |
|
|
$ |
60,028 |
|
|
|
- |
|
|
$ |
- |
|
|
$ |
18,489,469 |
|
|
$ |
(17,824,468 |
) |
|
$ |
725,029 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock in exchange for services
|
|
|
2,350,000 |
|
|
|
2,350 |
|
|
|
- |
|
|
|
- |
|
|
|
468,148 |
|
|
|
- |
|
|
|
470,498 |
|
|
Commons stock for debt settlement
|
|
|
2,000,000 |
|
|
|
2,000 |
|
|
|
- |
|
|
|
- |
|
|
|
388,000 |
|
|
|
- |
|
|
|
390,000 |
|
|
Common stock for cash
|
|
|
315,000 |
|
|
|
315 |
|
|
|
- |
|
|
|
- |
|
|
|
17,735 |
|
|
|
- |
|
|
|
18,050 |
|
|
Preferred stock converted to common
|
|
|
28,568,965 |
|
|
|
28,569 |
|
|
|
- |
|
|
|
- |
|
|
|
70,021 |
|
|
|
- |
|
|
|
98,590 |
|
|
Exercise of Warrants
|
|
|
3,000,000 |
|
|
|
3,000 |
|
|
|
- |
|
|
|
- |
|
|
|
347,000 |
|
|
|
- |
|
|
|
350,000 |
|
|
Warrants in exchange for services
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
68,726 |
|
|
|
- |
|
|
|
68,726 |
|
|
Stock dividend paid payable
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(3,953,573 |
) |
|
|
(3,953,573 |
) |
|
Aurora capital contributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,145,000 |
|
|
|
- |
|
|
|
2,145,000 |
|
|
Aurora capital distributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(245,348 |
) |
|
|
- |
|
|
|
(245,348 |
) |
|
Net loss for quarter
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1,621,271 |
) |
|
|
(1,621,271 |
) |
|
Balance, June 30, 2008
|
|
|
96,262,089 |
|
|
$ |
96,262 |
|
|
|
- |
|
|
$ |
- |
|
|
$ |
21,748,751 |
|
|
$ |
(23,399,312 |
) |
|
$ |
(1,554,299 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock dividend paid
|
|
|
19,767,863 |
|
|
|
19,768 |
|
|
|
- |
|
|
|
- |
|
|
|
3,933,805 |
|
|
|
- |
|
|
|
3,953,573 |
|
|
Preferred stock converted to common
|
|
|
4,482,758 |
|
|
|
4,483 |
|
|
|
- |
|
|
|
- |
|
|
|
10,987 |
|
|
|
- |
|
|
|
15,470 |
|
|
Warrants in exchange for services
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
21,840 |
|
|
|
- |
|
|
|
21,840 |
|
|
Aurora capital contributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,600,000 |
|
|
|
- |
|
|
|
2,600,000 |
|
|
Aurora capital distributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(206,894 |
) |
|
|
- |
|
|
|
(206,894 |
) |
|
Net loss for quarter
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(4,465,048 |
) |
|
|
(4,465,048 |
) |
|
Balance, September 30, 2008
|
|
|
120,512,710 |
|
|
$ |
120,513 |
|
|
|
- |
|
|
$ |
- |
|
|
$ |
28,108,489 |
|
|
$ |
(27,864,360 |
) |
|
$ |
364,642 |
|
VICTORY ENERGY CORPORATION AND SUBSIDARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT)
| |
|
Common Stock $0.001 Par
|
|
|
Preferred Stock $0.001 Par
|
|
|
Additional Paid In
|
|
|
|
|
|
|
|
|
Description
|
|
Number
|
|
|
Amount
|
|
|
Number
|
|
|
Amount
|
|
|
Capital
|
|
|
Accumulated Deficit
|
|
|
|
|
|
Preferred stock converted to common, balance
|
|
|
16,206,900 |
|
|
|
16,207 |
|
|
|
- |
|
|
|
- |
|
|
|
39,675 |
|
|
|
- |
|
|
|
55,882 |
|
|
Cancelled
|
|
|
-2 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Warrants in exchange for services
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
7,164 |
|
|
|
- |
|
|
|
7,164 |
|
|
Aurora capital contributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,238,892 |
|
|
|
- |
|
|
|
2,238,892 |
|
|
Aurora capital distributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(205,548 |
) |
|
|
- |
|
|
|
(205,548 |
) |
|
Net loss for quarter
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(3,455,380 |
) |
|
|
(3,455,380 |
) |
|
Balance, December 31, 2008
|
|
|
136,719,608 |
|
|
$ |
136,720 |
|
|
|
- |
|
|
$ |
- |
|
|
$ |
30,188,672 |
|
|
$ |
(31,319,740 |
) |
|
$ |
(994,348 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
136,719,608 |
|
|
$ |
136,720 |
|
|
|
- |
|
|
|
- |
|
|
$ |
30,188,672 |
|
|
$ |
(31,319,740 |
) |
|
$ |
(994,348 |
) |
|
Warrants in exchange for services
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
12,992 |
|
|
|
- |
|
|
|
12,992 |
|
|
Aurora capital contributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
890,000 |
|
|
|
- |
|
|
|
890,000 |
|
|
Aurora capital distributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(266,217 |
) |
|
|
- |
|
|
|
(266,217 |
) |
|
Net loss for quarter
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(511,936 |
) |
|
|
(511,936 |
) |
|
Balance, March 31, 2009
|
|
|
136,719,608 |
|
|
$ |
136,720 |
|
|
|
- |
|
|
$ |
- |
|
|
$ |
30,825,447 |
|
|
$ |
(31,831,676 |
) |
|
$ |
(869,509 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants in exchange for services
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5,580 |
|
|
|
- |
|
|
|
5,580 |
|
|
Aurora capital contributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
200,000 |
|
|
|
- |
|
|
|
200,000 |
|
|
Aurora capital distributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(20,000 |
) |
|
|
- |
|
|
|
(20,000 |
) |
|
Net income for quarter
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
842,539 |
|
|
|
842,539 |
|
|
Balance, June 30, 2009
|
|
|
136,719,608 |
|
|
$ |
136,720 |
|
|
|
- |
|
|
$ |
- |
|
|
$ |
31,011,027 |
|
|
$ |
(30,989,137 |
) |
|
$ |
158,610 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants in exchange for services
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,828 |
|
|
|
- |
|
|
|
4,828 |
|
|
Aurora capital contributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
17,529 |
|
|
|
- |
|
|
|
17,529 |
|
|
Aurora capital distributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(38,648 |
) |
|
|
- |
|
|
|
(38,648 |
) |
|
Net loss for quarter
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(203,957 |
) |
|
|
(203,957 |
) |
|
Balance, September 30, 2009
|
|
|
136,719,608 |
|
|
$ |
136,720 |
|
|
|
- |
|
|
$ |
- |
|
|
$ |
30,994,736 |
|
|
$ |
(31,193,094 |
) |
|
$ |
(61,638 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants in exchange for services
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,392 |
|
|
|
- |
|
|
|
4,392 |
|
|
Aurora capital contributions
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
264,144 |
|
|
|
- |
|
|
|
264,144 |
|
|
Net loss for quarter
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
(511,785 |
) |
|
|
(511,785 |
) |
|
Balance, December 31, 2009
|
|
|
136,719,608 |
|
|
$ |
136,720 |
|
|
|
- |
|
|
$ |
- |
|
|
$ |
31,263,272 |
|
|
$ |
(31,704,879 |
) |
|
$ |
(304,887 |
) |
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
| |
|
December 31, 2007
|
|
| |
|
As Originally
|
|
|
Restatement
|
|
|
As
|
|
| |
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
| |
|
|
|
|
|
|
|
|
|
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
3,251 |
|
|
|
|
|
$ |
3,251 |
|
|
Subscriptions receivable
|
|
|
160,000 |
|
|
|
(160,000 |
)a |
|
|
- |
|
|
Total current assets
|
|
|
163,251 |
|
|
|
(160,000 |
) |
|
|
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
FIXED ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Furniture and equipment
|
|
|
2,294 |
|
|
|
- |
|
|
|
2,294 |
|
|
Accumulated depreciation
|
|
|
(2,294 |
) |
|
|
- |
|
|
|
(2,294 |
) |
|
Total furniture and equipment
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in joint venture
|
|
|
50,000 |
|
|
|
(50,000 |
)b |
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$ |
213,251 |
|
|
$ |
(210,000 |
) |
|
$ |
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS' DEFICIT
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
34,803 |
|
|
|
- |
|
|
|
34,803 |
|
|
Line of credit - bank
|
|
|
81,860 |
|
|
|
- |
|
|
|
81,860 |
|
|
Liability for unauthorized preferred stock issued
|
|
|
- |
|
|
|
217,614 |
c |
|
|
217,614 |
|
|
Stock subscriptions payable
|
|
|
203,500 |
|
|
|
(203,500 |
)a |
|
|
- |
|
|
Amounts due former officer
|
|
|
1,377,879 |
|
|
|
3 |
e |
|
|
1,377,882 |
|
|
Total current liabilities
|
|
|
1,698,042 |
|
|
|
14,117 |
|
|
|
1,712,159 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES
|
|
|
1,698,042 |
|
|
|
14,117 |
|
|
|
1,712,159 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS' DEFICIT
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock, $0.001 par value, 10,000,000 shares
authorized; none issued and outstanding after restatement
|
|
|
631 |
|
|
|
(631 |
)c |
|
|
- |
|
|
Common Stock, $0.001 par value, 200,000,000 shares
authorized, 42,395,366 issued and outstanding
|
|
|
42,395 |
|
|
|
- |
|
|
|
42,395 |
|
|
Additional paid in capital
|
|
|
7,860,331 |
|
|
|
6,256,376 |
c,d |
|
|
14,116,707 |
|
|
Deficit accumulated in development stage company
|
|
|
(9,388,148 |
) |
|
|
(6,479,862 |
)a,b,d |
|
|
(15,868,010 |
) |
|
TOTAL STOCKHOLDERS' DEFICIT
|
|
|
(1,484,791 |
) |
|
|
(224,117 |
) |
|
|
(1,708,908 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT
|
|
$ |
213,251 |
|
|
$ |
(210,000 |
) |
|
$ |
3,251 |
|
Footnotes:
a: Reverse stock subscription receivable as not a valid transaction
b: Adjust for write off of impaired joint venture in 2006
c: Establish a payable and reverse amounts received for unconverted preferred stock issued without proper authority
d: Recognize value of common stock and warrants issued for services
e: Reconciliation of amounts due former officer
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
| |
|
For the Year Ended December 31, 2007
|
|
| |
|
As Originally
|
|
|
Restatement
|
|
|
As
|
|
| |
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
| |
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
COSTS AND EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses
|
|
|
3,890,188 |
|
|
|
6,429,862 |
a,b,c |
|
|
10,320,050 |
|
|
Total expenses
|
|
|
3,890,188 |
|
|
|
6,429,862 |
|
|
|
10,320,050 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
LOSS FROM OPERATIONS
|
|
|
(3,890,188 |
) |
|
|
(6,429,862 |
) |
|
|
(10,320,050 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME AND EXPENSE
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
6,639 |
|
|
|
- |
|
|
|
6,639 |
|
|
Total other expense
|
|
|
6,639 |
|
|
|
- |
|
|
|
6,639 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS
|
|
$ |
(3,896,827 |
) |
|
$ |
(6,429,862 |
) |
|
$ |
(10,326,689 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares, basic and diluted
|
|
|
23,953,149 |
|
|
|
(365,720 |
)d |
|
|
23,587,429 |
|
|
Net loss per share, basic and diluted
|
|
$ |
(0.16 |
) |
|
$ |
17.58 |
|
|
$ |
(0.44 |
) |
Footnotes:
a: Reverse stock subscription receivable as not a valid transaction
b: Adjust for write off of worthless joint venture in 2006
c: Recognize value of common stock and warrants issued for services
d: Recalculated to tie to stock transfer ledger
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOW
| |
|
For the Year Ended December 31, 2007
|
|
| |
|
As Originally
|
|
|
Restatement
|
|
|
As
|
|
| |
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
| |
|
|
|
|
|
|
|
|
|
|
CASH FLOW FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$ |
(3,896,827 |
) |
|
$ |
(6,429,862 |
)a,b,c |
|
$ |
(10,326,689 |
) |
|
Adjustment to reconcile net loss from operations to net cash provided by (used in) operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock for services
|
|
|
447,400 |
|
|
|
9,045,265 |
c |
|
|
9,492,665 |
|
|
Warrants for services
|
|
|
- |
|
|
|
109,000 |
c |
|
|
109,000 |
|
|
Change in working capital
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subscriptions receivable
|
|
|
(160,000 |
) |
|
|
160,000 |
a |
|
|
- |
|
|
Accounts payable
|
|
|
15,661 |
|
|
|
(79 |
)e |
|
|
15,582 |
|
|
Net cash provided by (used in) operating activities
|
|
|
(3,593,766 |
) |
|
|
2,884,324 |
|
|
|
(709,442 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank line of credit net borrowings (repayments)
|
|
|
24,899 |
|
|
|
- |
|
|
|
24,899 |
|
|
Proceeds from former officer
|
|
|
687,794 |
|
|
|
- |
|
|
|
687,794 |
|
|
Contributed capital
|
|
|
2,270,383 |
|
|
|
(2,270,383 |
)a |
|
|
- |
|
|
Sale of common stock
|
|
|
1,189,020 |
|
|
|
(1,189,020 |
)a |
|
|
- |
|
|
Revaluation of stock subscriptions
|
|
|
(575,000 |
) |
|
|
575,000 |
a |
|
|
- |
|
|
Net cash provided by (used in) financing activities
|
|
|
3,597,096 |
|
|
|
(2,884,403 |
) |
|
|
712,693 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
3,330 |
|
|
|
(79 |
) |
|
|
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning cash and cash equivalents
|
|
|
(79 |
) |
|
|
79 |
e |
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending cash and cash equivalents
|
|
$ |
3,251 |
|
|
$ |
- |
|
|
$ |
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental schedule of non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock converted to common stock
|
|
$ |
- |
|
|
$ |
29,336 |
d |
|
$ |
29,336 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosures of cash flow information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the period for
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
Income taxes
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
Footnotes:
a: Reverse stock subscription receivable as an inappropriate transaction
b: Adjust for write off of worthless joint venture in 2006
c: Recognize value of common stock and warrants issued for services
d: Preferred stock converted to common stock
e: Reclass for proper presentation
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| |
|
March 31, 2008
|
|
|
December 31, 2007
|
|
| |
|
As Originally
|
|
|
Restatement
|
|
|
As
|
|
|
As
|
|
| |
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Restated
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
- |
|
|
|
- |
|
|
$ |
- |
|
|
$ |
3,251 |
|
|
Receivable from related party
|
|
|
- |
|
|
|
300,000 |
f |
|
|
300,000 |
|
|
|
- |
|
|
Subscriptions receivable
|
|
|
160,000 |
|
|
|
(160,000 |
)a |
|
|
- |
|
|
|
- |
|
|
Total current assets
|
|
|
160,000 |
|
|
|
140,000 |
|
|
|
300,000 |
|
|
|
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIXED ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Furniture and equipment
|
|
|
2,294 |
|
|
|
- |
|
|
|
2,294 |
|
|
|
2,294 |
|
|
Accumulated depreciation
|
|
|
(2,294 |
) |
|
|
- |
|
|
|
(2,294 |
) |
|
|
(2,294 |
) |
|
Total furniture and equipment
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling costs in process
|
|
|
3,036,000 |
|
|
|
(1,916,000 |
)e |
|
|
1,120,000 |
|
|
|
- |
|
|
Oil and natural gas properties
|
|
|
- |
|
|
|
1,436,599 |
e |
|
|
1,436,599 |
|
|
|
- |
|
|
Accumulated depletion
|
|
|
- |
|
|
|
(59,149 |
)e |
|
|
(59,149 |
) |
|
|
- |
|
|
Total production assets, net
|
|
|
3,036,000 |
|
|
|
(538,550 |
) |
|
|
2,497,450 |
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in joint venture
|
|
|
50,000 |
|
|
|
(50,000 |
)b |
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$ |
3,246,000 |
|
|
$ |
(448,550 |
) |
|
$ |
2,797,450 |
|
|
$ |
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS' DEFICIT
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank overdraft
|
|
$ |
23,773 |
|
|
$ |
179 |
g |
|
$ |
23,952 |
|
|
$ |
- |
|
|
Accounts payable
|
|
|
32,485 |
|
|
|
(2,602 |
)f |
|
|
29,883 |
|
|
|
34,803 |
|
|
Line of credit - bank
|
|
|
81,860 |
|
|
|
(2,668 |
)g |
|
|
79,192 |
|
|
|
81,860 |
|
|
Loans payable to related party
|
|
|
- |
|
|
|
300,000 |
f |
|
|
300,000 |
|
|
|
- |
|
|
Liability for unauthorized preferred stock issued
|
|
|
- |
|
|
|
202,147 |
c |
|
|
202,147 |
|
|
|
217,614 |
|
|
Stock subscriptions payable
|
|
|
203,500 |
|
|
|
(203,500 |
)a |
|
|
- |
|
|
|
- |
|
|
Amounts due former officer
|
|
|
1,369,339 |
|
|
|
52,029 |
g |
|
|
1,421,368 |
|
|
|
1,377,882 |
|
|
Total Current Liabilities
|
|
|
1,710,957 |
|
|
|
345,585 |
|
|
|
2,056,542 |
|
|
|
1,712,159 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligation
|
|
|
- |
|
|
|
15,879 |
f |
|
|
15,879 |
|
|
|
- |
|
|
TOTAL LIABILITIES
|
|
|
1,710,957 |
|
|
|
361,464 |
|
|
|
2,072,421 |
|
|
|
1,712,159 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS' EQUITY (DEFICIT)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock, $0.001 par value, 10,000,000 shares authorized; none issued and outstanding after restatement
|
|
|
586 |
|
|
|
(586 |
)c |
|
|
- |
|
|
|
- |
|
|
Common Stock, $0.001 par value, 200,000,000 shares authorized, 60,028,124 and 16,497,766 issued and outstanding, respectively
|
|
|
60,028 |
|
|
|
- |
|
|
|
60,028 |
|
|
|
42,395 |
|
|
Additional paid in capital
|
|
|
9,110,743 |
|
|
|
9,378,726 |
c,d,f |
|
|
18,489,469 |
|
|
|
14,116,707 |
|
|
Accumulated deficit
|
|
|
(7,636,314 |
) |
|
(10,188,154
|
)a,b,c,d,e,f,g |
|
|
(17,824,468 |
) |
|
|
(15,868,010 |
) |
|
TOTAL STOCKHOLDERS' EQUITY (DEFICIT)
|
|
|
1,535,043 |
|
|
|
(810,014 |
) |
|
|
725,029 |
|
|
|
(1,708,908 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
|
|
$ |
3,246,000 |
|
|
$ |
(448,550 |
) |
|
$ |
2,797,450 |
|
|
$ |
3,251 |
|
Footnotes:
a: Reverse stock subscription receivable as not a valid transaction
b: Adjust for write off of worthless joint venture in 2006
c: Establish a payable and reverse amounts received for unconverted preferred stock issued without proper authority
d: Recognize value of common stock and warrants issued for services
e: Properly record costs of drilling and related depletion
f: Consolidation with Aurora Energy Partners
g: Reconciliation of amounts due former officer
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(Unaudited)
| |
|
For the Three Months Ended March 31,
|
|
| |
|
2008
|
|
|
2007
|
|
| |
|
As Originally
|
|
|
Restatement
|
|
|
As
|
|
|
As
|
|
| |
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Restated
|
|
|
REVENUES
|
|
$ |
252,000 |
|
|
$ |
184,974 |
a,d |
|
$ |
436,974 |
|
|
$ |
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COSTS AND EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of production
|
|
|
103,700 |
|
|
|
183,722 |
a,d |
|
|
287,422 |
|
|
|
- |
|
|
General and administrative expense
|
|
|
1,396,466 |
|
|
|
613,563 |
b,d |
|
|
2,010,029 |
|
|
|
6,252,297 |
|
|
Depletion and accretion
|
|
|
- |
|
|
|
59,511 |
c,d |
|
|
59,511 |
|
|
|
- |
|
|
Malfeasance losses
|
|
|
- |
|
|
|
36,470 |
f |
|
|
36,470 |
|
|
|
- |
|
|
Total expenses
|
|
|
1,500,166 |
|
|
|
893,266 |
|
|
|
2,393,432 |
|
|
|
6,252,297 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOSS FROM OPERATIONS
|
|
|
(1,248,166 |
) |
|
|
(708,292 |
) |
|
|
(1,956,458 |
) |
|
|
(6,252,297 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME AND EXPENSE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sale of working interest in wells
|
|
|
(3,000,000 |
) |
|
|
3,000,000 |
e |
|
|
- |
|
|
|
- |
|
|
Total other income (expense)
|
|
|
(3,000,000 |
) |
|
|
3,000,000 |
|
|
|
- |
|
|
|
- |
|
|
NET INCOME (LOSS)
|
|
$ |
1,751,834 |
|
|
$ |
(3,708,292 |
) |
|
$ |
(1,956,458 |
) |
|
$ |
(6,252,297 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares, basic and diluted
|
|
|
106,041,725 |
|
|
|
(57,784,025 |
)g |
|
|
48,257,700 |
|
|
|
10,354,996 |
|
|
Net income (loss) per share, basic and diluted
|
|
$ |
0.02 |
|
|
$ |
0.06 |
|
|
$ |
(0.04 |
) |
|
$ |
(0.60 |
) |
Footnotes:
a: Properly accrue verifiable revenue amounts and related costs
b: Recognize value of common stock and warrants issued for services
c: Properly record costs of drilling and related depletion
d: Consolidation with Aurora Energy Partners
e: Reverse inappropraite entry
f: Post investigation
g: Recalculated to tie to stock transfer ledger
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOW
(Unaudited)
| |
|
For the Three Months Ended March 31,
|
|
| |
|
2008
|
|
|
|
|
|
2008
|
|
|
2007
|
|
| |
|
As Originally
|
|
|
Restatement
|
|
|
As
|
|
|
As
|
|
| |
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Restated
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOW FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$ |
1,751,834 |
|
|
$ |
(3,708,292 |
) |
|
$ |
(1,956,458 |
) |
|
$ |
(6,252,297 |
) |
|
Adjustment to reconcile net loss from operations to net cash provided by (used in) operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion
|
|
|
- |
|
|
|
59,149 |
e |
|
|
59,149 |
|
|
|
- |
|
|
Accretion to asset retirement obligation
|
|
|
- |
|
|
|
362 |
e |
|
|
362 |
|
|
|
- |
|
|
Common stock for services
|
|
|
1,268,000 |
|
|
|
343,625 |
d |
|
|
1,611,625 |
|
|
|
6,033,310 |
|
|
Warrants for services
|
|
|
- |
|
|
|
245,000 |
d |
|
|
245,000 |
|
|
|
- |
|
|
Change in working capital
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivable from related party
|
|
|
- |
|
|
|
(300,000 |
)f |
|
|
(300,000 |
) |
|
|
- |
|
|
Bank overdraft
|
|
|
- |
|
|
|
23,952 |
g |
|
|
23,952 |
|
|
|
- |
|
|
Accounts payable
|
|
|
(2,318 |
) |
|
|
(2,603 |
)f,g |
|
|
(4,921 |
) |
|
|
13,197 |
|
|
Asset retirement obligations
|
|
|
- |
|
|
|
15,517 |
e |
|
|
15,517 |
|
|
|
- |
|
|
Net cash provided by (used in) operating activities
|
|
|
3,017,516 |
|
|
|
(3,323,290 |
) |
|
|
(305,774 |
) |
|
|
(205,790 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling costs
|
|
|
(3,036,000 |
) |
|
|
1,916,000 |
f |
|
|
(1,120,000 |
) |
|
|
- |
|
|
Purchase of wells
|
|
|
- |
|
|
|
(1,436,599 |
)f |
|
|
(1,436,599 |
) |
|
|
- |
|
|
Net cash provided by (used in) investing activities
|
|
|
(3,036,000 |
) |
|
|
479,401 |
|
|
|
(2,556,599 |
) |
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank line of credit net borrowings (repayments)
|
|
|
|
|
|
|
(2,668 |
)g |
|
|
(2,668 |
) |
|
|
22,886 |
|
|
Proceeds from notes payable to related parties
|
|
|
|
|
|
|
300,000 |
g |
|
|
300,000 |
|
|
|
|
|
|
Proceeds from former officer
|
|
|
(8,540 |
) |
|
|
219,255 |
g |
|
|
210,715 |
|
|
|
|
|
|
Payments to former officer
|
|
|
|
|
|
|
(167,225 |
)d |
|
|
(167,225 |
) |
|
|
183,496 |
|
|
Sale of common stock
|
|
|
|
|
|
|
42,000 |
d |
|
|
42,000 |
|
|
|
- |
|
|
Aurora capital contributions
|
|
|
- |
|
|
|
2,750,000 |
f |
|
|
2,750,000 |
|
|
|
- |
|
|
Aurora capital distributions
|
|
|
- |
|
|
|
(273,700 |
)f |
|
|
(273,700 |
) |
|
|
- |
|
|
Net cash provided by (used in) financing activities
|
|
|
(8,540 |
) |
|
|
2,867,662 |
|
|
|
2,859,122 |
|
|
|
206,382 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
(27,024 |
) |
|
|
23,773 |
|
|
|
(3,251 |
) |
|
|
592 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning cash and cash equivalents
|
|
|
3,251 |
|
|
|
- |
|
|
|
3,251 |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending cash and cash equivalents
|
|
$ |
(23,773 |
) |
|
$ |
23,773 |
g |
|
$ |
- |
|
|
$ |
592 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental schedule of non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock converted to common stock
|
|
$ |
- |
|
|
$ |
15,470 |
h |
|
$ |
15,470 |
|
|
$ |
- |
|
Footnotes:
a: Reverse stock subscription receivable as not a valid transaction
b: Adjust for write off of worthless joint venture in 2006
c: Establish a payable and reverse amounts received for unconverted preferred stock issued without proper authority
d: Recognize value of common stock and warrants issued for services
e: Properly record costs of drilling and related depletion
f: Consolidation with Aurora Energy Partners
g: Reconciliation and presentation
h: Preferred stock converted to common stock
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| |
|
June 30, 2008
|
|
|
December 31, 2007
|
|
| |
|
As Originally
|
|
|
Restatement
|
|
|
As
|
|
|
As
|
|
| |
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Restated
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
159 |
|
|
$ |
95 |
c |
|
$ |
254 |
|
|
$ |
3,251 |
|
|
Receivable from related party
|
|
|
- |
|
|
|
300,000 |
f |
|
|
300,000 |
|
|
|
- |
|
|
Subscriptions receivable
|
|
|
160,000 |
|
|
|
(160,000 |
)a |
|
|
- |
|
|
|
- |
|
|
Prepaid Expense
|
|
|
7,250 |
|
|
|
- |
|
|
|
7,250 |
|
|
|
- |
|
|
Total current assets
|
|
|
167,409 |
|
|
|
140,095 |
|
|
|
307,504 |
|
|
|
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIXED ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Furniture and equipment
|
|
|
2,294 |
|
|
|
- |
|
|
|
2,294 |
|
|
|
2,294 |
|
|
Accumulated depreciation
|
|
|
(2,294 |
) |
|
|
- |
|
|
|
(2,294 |
) |
|
|
(2,294 |
) |
|
Total furniture and equipment
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas working interest
|
|
|
1,570,000 |
|
|
|
(1,570,000 |
)e |
|
|
- |
|
|
|
- |
|
|
Drilling costs in process
|
|
|
3,564,000 |
|
|
|
(2,336,894 |
)e |
|
|
1,227,106 |
|
|
|
- |
|
|
Oil and natural gas properties
|
|
|
- |
|
|
|
2,571,924 |
e |
|
|
2,571,924 |
|
|
|
- |
|
|
Accumulated depletion
|
|
|
- |
|
|
|
(174,057 |
)e |
|
|
(174,057 |
) |
|
|
- |
|
|
Total production assets, net
|
|
|
5,134,000 |
|
|
|
(1,509,027 |
) |
|
|
3,624,973 |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funds held by court
|
|
|
- |
|
|
|
170,000 |
f |
|
|
170,000 |
|
|
|
- |
|
|
Investment in joint venture
|
|
|
50,000 |
|
|
|
(50,000 |
)b |
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$ |
5,351,409 |
|
|
$ |
(1,248,932 |
) |
|
$ |
4,102,477 |
|
|
$ |
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS' DEFICIT
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$ |
57,974 |
|
|
$ |
(28,760 |
)f |
|
$ |
29,214 |
|
|
$ |
34,803 |
|
|
Bank line of credit
|
|
|
76,545 |
|
|
|
(1,172 |
)g |
|
|
75,373 |
|
|
|
81,860 |
|
|
Dividend payable
|
|
|
3,953,621 |
|
|
|
(47 |
)g |
|
|
3,953,574 |
|
|
|
- |
|
|
Loan payable related party
|
|
|
- |
|
|
|
210,000 |
f |
|
|
210,000 |
|
|
|
- |
|
|
Short term Advance
|
|
|
2,078,000 |
|
|
|
(2,078,000 |
)g |
|
|
- |
|
|
|
- |
|
|
Liability for unauthorized preferred stock issued
|
|
|
- |
|
|
|
103,557 |
a |
|
|
103,557 |
|
|
|
217,614 |
|
|
Stock subscriptions payable
|
|
|
203,500 |
|
|
|
(203,500 |
)a |
|
|
- |
|
|
|
- |
|
|
Amounts due former officer
|
|
|
1,209,779 |
|
|
|
57,913 |
g |
|
|
1,267,692 |
|
|
|
1,377,882 |
|
|
Total current liabilities
|
|
|
7,579,419 |
|
|
|
(1,940,009 |
) |
|
|
5,639,410 |
|
|
|
1,712,159 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation
|
|
|
- |
|
|
|
17,366 |
f |
|
|
17,366 |
|
|
|
- |
|
|
TOTAL LIABILITIES
|
|
|
7,579,419 |
|
|
|
(1,922,643 |
) |
|
|
5,656,776 |
|
|
|
1,712,159 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS' EQUITY (DEFICIT)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock, $0.001 par value, 10,000,000 shares authorized; none issued and outstanding after restatement
|
|
|
2,300 |
|
|
|
(2,300 |
)c |
|
|
- |
|
|
|
- |
|
|
Common Stock, $0.001 par value, 200,000,000 shares authorized, 96,262,089 and 31,285,366 issued and outstanding, respectively
|
|
|
96,262 |
|
|
|
|
|
|
|
96,262 |
|
|
|
42,395 |
|
|
Additional paid in capital
|
|
|
10,331,845 |
|
|
|
11,416,906 |
c,d,f |
|
|
21,748,751 |
|
|
|
14,116,707 |
|
|
Accumulated deficit
|
|
|
(12,658,417 |
) |
|
(10,740,895
|
)a,b,c,d,e,f,g |
|
|
(23,399,312 |
) |
|
|
(15,868,010 |
) |
|
TOTAL STOCKHOLDERS' EQUITY (DEFICIT)
|
|
|
(2,228,010 |
) |
|
|
673,711 |
|
|
|
(1,554,299 |
) |
|
|
(1,708,908 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
|
|
$ |
5,351,409 |
|
|
$ |
(1,248,932 |
) |
|
$ |
4,102,477 |
|
|
$ |
3,251 |
|
Footnotes:
a: Reverse stock subscription receivable as not a valid transaction
b: Adjust for write off of worthless joint venture in 2006
c: Establish a payable and reverse amounts received for preferred stock issued without proper authority
d: Recognize value of common stock and warrants issued for services
e: Properly record costs of drilling and related depletion
f: Consolidation with Aurora Energy Partners
g: Reconciliation and presentation
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(Unaudited)
| |
|
For the Three Months Ended June 30,
|
|
|
For the Six Months Ended June 30,
|
|
| |
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
| |
|
As Originally
|
|
|
Restatement
|
|
|
As
|
|
|
As
|
|
|
As Originally
|
|
|
Restatement
|
|
|
As
|
|
|
As
|
|
| |
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Restated
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Restated
|
|
|
REVENUES
|
|
$ |
149,019 |
|
|
$ |
369,686 |
a,d |
|
$ |
518,705 |
|
|
$ |
- |
|
|
$ |
401,019 |
|
|
$ |
554,660 |
a,d |
|
$ |
955,679 |
|
|
$ |
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COSTS AND EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of production
|
|
|
464,728 |
|
|
|
(160,938 |
)a,d |
|
|
303,790 |
|
|
|
- |
|
|
|
568,428 |
|
|
|
22,784 |
a,d |
|
|
591,212 |
|
|
|
- |
|
|
General and administrative expense
|
|
|
752,773 |
|
|
|
(60,827 |
)b,d |
|
|
691,946 |
|
|
|
2,115,549 |
|
|
|
2,149,239 |
|
|
|
552,736 |
b,d |
|
|
2,701,975 |
|
|
|
8,367,846 |
|
|
Depletion and accretion
|
|
|
|
|
|
|
115,294 |
c,d |
|
|
115,294 |
|
|
|
|
|
|
|
|
|
|
|
174,805 |
c,d |
|
|
174,805 |
|
|
|
|
|
|
Malfeasance losses
|
|
|
- |
|
|
|
634,565 |
f |
|
|
634,565 |
|
|
|
- |
|
|
|
- |
|
|
|
671,035 |
f |
|
|
671,035 |
|
|
|
- |
|
|
Loss from settlement with former officer
|
|
|
- |
|
|
|
- |
b |
|
|
390,000 |
|
|
|
- |
|
|
|
- |
|
|
|
390,000 |
b |
|
|
390,000 |
|
|
|
|
|
|
Total expenses
|
|
|
1,217,501 |
|
|
|
528,094 |
|
|
|
2,135,595 |
|
|
|
2,115,549 |
|
|
|
2,717,667 |
|
|
|
1,811,360 |
|
|
|
4,529,027 |
|
|
|
8,367,846 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOSS FROM OPERATIONS
|
|
|
(1,068,482 |
) |
|
|
(158,408 |
) |
|
|
(1,616,890 |
) |
|
|
(2,115,549 |
) |
|
|
(2,316,648 |
) |
|
|
(1,256,700 |
) |
|
|
(3,573,348 |
) |
|
|
(8,367,846 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME AND EXPENSE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sale of working interest in wells
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,000,000 |
|
|
|
(3,000,000 |
)e |
|
|
- |
|
|
|
- |
|
|
Interest expense
|
|
|
- |
|
|
|
4,381 |
g |
|
|
4,381 |
|
|
|
- |
|
|
|
- |
|
|
|
4,381 |
g |
|
|
4,381 |
|
|
|
- |
|
|
Total other (income) expense
|
|
|
- |
|
|
|
4,381 |
|
|
|
4,381 |
|
|
|
- |
|
|
|
3,000,000 |
|
|
|
(2,995,619 |
) |
|
|
4,381 |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
|
|
$ |
(1,068,482 |
) |
|
$ |
(162,789 |
) |
|
$ |
(1,621,271 |
) |
|
$ |
(2,115,549 |
) |
|
$ |
683,352 |
|
|
$ |
(4,252,319 |
) |
|
$ |
(3,577,729 |
) |
|
$ |
(8,367,846 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares basic and diluted
|
|
|
80,751,752 |
|
|
|
(149,760 |
)h |
|
|
80,601,992 |
|
|
|
20,924,665 |
|
|
|
294,112,238 |
|
|
|
(229,682,392 |
)h |
|
|
64,429,846 |
|
|
|
15,669,029 |
|
|
Net income (loss) per share, basic and diluted
|
|
$ |
(0.01 |
) |
|
$ |
1.09 |
|
|
$ |
(0.02 |
) |
|
$ |
(0.10 |
) |
|
$ |
0.00 |
|
|
$ |
0.02 |
|
|
$ |
(0.06 |
) |
|
$ |
(0.53 |
) |
Footnotes:
a: Properly accrue verifiable revenue amounts and related costs
b: Recognize value of common stock and warrants issued for services
c: Properly record costs of drilling and related depletion
d: Consolidation with Aurora Energy Partners
e: Reverse inappropriate entry
f: Post investigation
g: Reconciliation and presentation
h: Recalculated to tie to stock transfer ledger
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOW
(Unaudited)
| |
|
For the Six Months Ended June 30,
|
|
| |
|
2008
|
|
|
|
|
|
2008
|
|
|
2007
|
|
| |
|
As Originally
|
|
|
|
|
|
As
|
|
|
As
|
|
| |
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Restated
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOW FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$ |
(2,316,648 |
) |
|
$ |
(1,261,081 |
) |
|
$ |
(3,577,729 |
) |
|
$ |
(8,367,846 |
) |
|
Adjustment to reconcile net loss from operations to net cash provided by (used in) operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion
|
|
|
- |
|
|
|
174,057 |
e |
|
|
174,057 |
|
|
|
- |
|
|
Accretion to asset retirement obligation
|
|
|
- |
|
|
|
748 |
e |
|
|
748 |
|
|
|
- |
|
|
Common stock for services
|
|
|
1,967,050 |
|
|
|
115,075 |
d |
|
|
2,082,125 |
|
|
|
8,012,726 |
|
|
Common stock for settlement
|
|
|
- |
|
|
|
390,000 |
d |
|
|
390,000 |
|
|
|
- |
|
|
Warrants for services
|
|
|
- |
|
|
|
313,726 |
d |
|
|
313,726 |
|
|
|
- |
|
|
Declaration of stock dividend
|
|
|
- |
|
|
|
(3,953,573 |
)h |
|
|
(3,953,573 |
) |
|
|
- |
|
|
Change in working capital
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivable from related party
|
|
|
- |
|
|
|
(300,000 |
)f |
|
|
(300,000 |
) |
|
|
- |
|
|
Funds held by court
|
|
|
- |
|
|
|
(170,000 |
)f |
|
|
(170,000 |
) |
|
|
- |
|
|
Prepaid expense
|
|
|
(7,250 |
) |
|
|
- |
|
|
|
(7,250 |
) |
|
|
|
|
|
Accounts payable
|
|
|
23,171 |
|
|
|
(28,760 |
)f,g |
|
|
(5,589 |
) |
|
|
21,219 |
|
|
Dividends payable
|
|
|
3,953,621 |
|
|
|
(48 |
)h |
|
|
3,953,573 |
|
|
|
- |
|
|
Asset retirement obligations
|
|
|
- |
|
|
|
16,618 |
e,f |
|
|
16,618 |
|
|
|
- |
|
|
Net cash provided by (used in) operating activities
|
|
|
3,619,944 |
|
|
|
(4,703,238 |
) |
|
|
(1,083,294 |
) |
|
|
(333,901 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling costs
|
|
|
(3,564,000 |
) |
|
|
2,336,894 |
e,f |
|
|
(1,227,106 |
) |
|
|
- |
|
|
Drilled wells
|
|
|
- |
|
|
|
(1,135,325 |
)e,f |
|
|
(1,135,325 |
) |
|
|
- |
|
|
Purchase of wells
|
|
|
(1,570,000 |
) |
|
|
133,401 |
e,f |
|
|
(1,436,599 |
) |
|
|
- |
|
|
Net cash provided by (used in) investing activities
|
|
|
(5,134,000 |
) |
|
|
1,334,970 |
|
|
|
(3,799,030 |
) |
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank line of credit net borrowings (repayments)
|
|
|
(5,315 |
) |
|
|
(1,171 |
)g |
|
|
(6,486 |
) |
|
|
23,661 |
|
|
Dividends declared
|
|
|
(3,953,621 |
) |
|
|
3,953,621 |
g |
|
|
- |
|
|
|
- |
|
|
Proceeds from notes payable to related parties
|
|
|
- |
|
|
|
300,000 |
f |
|
|
300,000 |
|
|
|
- |
|
|
Proceeds from sale of working interest in wells
|
|
|
3,000,000 |
|
|
|
(3,000,000 |
)i |
|
|
- |
|
|
|
- |
|
|
Proceeds from former officer
|
|
|
- |
|
|
|
372,864 |
g |
|
|
372,864 |
|
|
|
298,480 |
|
|
Payments on notes payable to related parties
|
|
|
- |
|
|
|
(90,000 |
)f |
|
|
(90,000 |
) |
|
|
- |
|
|
Payments to former officer
|
|
|
(168,100 |
) |
|
|
(314,953 |
)g |
|
|
(483,053 |
) |
|
|
- |
|
|
Warrants exercise
|
|
|
- |
|
|
|
350,000 |
d |
|
|
350,000 |
|
|
|
- |
|
|
Contributed capital
|
|
|
2,078,000 |
|
|
|
(2,078,000 |
)i |
|
|
- |
|
|
|
- |
|
|
Aurora capital contributions
|
|
|
- |
|
|
|
4,895,000 |
f |
|
|
4,895,000 |
|
|
|
- |
|
|
Aurora capital distributions
|
|
|
- |
|
|
|
(519,048 |
)f |
|
|
(519,048 |
) |
|
|
- |
|
|
Conversion of preferred stock to common stock
|
|
|
200,000 |
|
|
|
(200,000 |
)d |
|
|
- |
|
|
|
- |
|
|
Sale of common stock
|
|
|
110,000 |
|
|
|
(49,950 |
)g |
|
|
60,050 |
|
|
|
- |
|
|
Sale of warrants
|
|
|
250,000 |
|
|
|
(250,000 |
)d |
|
|
- |
|
|
|
- |
|
|
Net cash provided by financing activities
|
|
|
1,510,964 |
|
|
|
3,368,363 |
|
|
|
4,879,327 |
|
|
|
322,141 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
(3,092 |
) |
|
|
95 |
|
|
|
(2,997 |
) |
|
|
(11,760 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning cash and cash equivalents
|
|
|
3,251 |
|
|
|
- |
|
|
|
3,251 |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending cash and cash equivalents
|
|
$ |
159 |
|
|
$ |
95 |
|
|
$ |
254 |
|
|
$ |
(11,760 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental schedule of non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock converted to common stock
|
|
$ |
- |
|
|
$ |
114,059 |
j |
|
$ |
114,059 |
|
|
$ |
- |
|
Footnotes:
a: Reverse stock subscription receivable as not a valid transaction
b: Adjust for write off of worthless joint venture in 2006
c: Establish a payable and reverse amounts received for preferred stock issued without proper authority
d: Recognize value of common stock and warrants issued for services
e: Properly record costs of drilling and related depletion
f: Consolidation with Aurora Energy Partners
g: Reconciliation and presentation
h: Declaration of stock dividend
i: Reverse inappropriate entry
j: Preferred stock converted to common stock
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| |
|
September 30, 2008
|
|
|
December 31, 2007
|
|
| |
|
As Originally
|
|
|
Restatement
|
|
|
As
|
|
|
As
|
|
| |
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Restated
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
4,337 |
|
|
|
512,096 |
c |
|
$ |
516,433 |
|
|
$ |
3,251 |
|
|
Subscriptions receivable
|
|
|
160,000 |
|
|
|
(160,000 |
)a |
|
|
- |
|
|
|
- |
|
|
Accounts receivable related party
|
|
|
- |
|
|
|
300,000 |
f |
|
|
300,000 |
|
|
|
- |
|
|
Prepaid rent
|
|
|
7,250 |
|
|
|
- |
|
|
|
7,250 |
|
|
|
- |
|
|
Total current assets
|
|
|
171,587 |
|
|
|
652,096 |
|
|
|
823,683 |
|
|
|
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIXED ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Furniture and equipment
|
|
|
2,294 |
|
|
|
- |
|
|
|
2,294 |
|
|
|
2,294 |
|
|
Accumulated depreciation
|
|
|
(2,294 |
) |
|
|
- |
|
|
|
(2,294 |
) |
|
|
(2,294 |
) |
|
Total furniture and equipment
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling costs in process
|
|
|
6,304,000 |
|
|
|
(7,877,892 |
)e |
|
|
(1,573,892 |
) |
|
|
- |
|
|
Natural gas working interest
|
|
|
1,430,000 |
|
|
|
(1,430,000 |
)e |
|
|
- |
|
|
|
- |
|
|
Oil and natural gas properties
|
|
|
|
|
|
|
3,183,326 |
e |
|
|
3,183,326 |
|
|
|
- |
|
|
Accumulated depletion
|
|
|
- |
|
|
|
(332,028 |
)e |
|
|
(332,028 |
) |
|
|
- |
|
|
Total production assets, net
|
|
|
7,734,000.00 |
|
|
|
(6,456,594.00 |
) |
|
|
1,277,406.00 |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funds held by court
|
|
|
- |
|
|
|
3,131 |
|
|
|
3,131 |
|
|
|
- |
|
|
Investment in joint venture
|
|
|
50,000 |
|
|
|
(50,000 |
)b |
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$ |
7,955,587 |
|
|
$ |
(5,851,367 |
) |
|
$ |
2,104,220 |
|
|
$ |
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
110,781 |
|
|
|
(82,966 |
)f |
|
|
27,815 |
|
|
|
34,803 |
|
|
Accrued liabilities
|
|
|
320,500 |
|
|
|
(320,500 |
)f |
|
|
- |
|
|
|
- |
|
|
Line of credit
|
|
|
76,414 |
|
|
|
(1,171 |
)g |
|
|
75,243 |
|
|
|
81,860 |
|
|
Loan payable to related party
|
|
|
- |
|
|
|
180,000 |
|
|
|
180,000 |
|
|
|
- |
|
|
Liability for unauthorized preferred stock issued
|
|
|
- |
|
|
|
88,088 |
|
|
|
88,088 |
|
|
|
217,614 |
|
|
Stock subscriptions payable
|
|
|
203,500 |
|
|
|
(203,500 |
)a |
|
|
- |
|
|
|
- |
|
|
Amounts due former officer
|
|
|
879,306 |
|
|
|
471,375 |
g |
|
|
1,350,681 |
|
|
|
1,377,882 |
|
|
Total current liabilities
|
|
|
1,590,501 |
|
|
|
131,326 |
|
|
|
1,721,827 |
|
|
|
1,712,159 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation
|
|
|
- |
|
|
|
17,751 |
|
|
|
17,751 |
|
|
|
- |
|
|
TOTAL LIABILITIES
|
|
|
1,590,501 |
|
|
|
149,077 |
|
|
|
1,739,578 |
|
|
|
1,712,159 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS' EQUITY (DEFICIT)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock, $0.001 par value, 10,000,000 shares authorized; none issued and outstanding after restatement
|
|
|
2,255 |
|
|
|
(2,255 |
)c |
|
|
- |
|
|
|
- |
|
|
Common Stock, $0.001 par value, 200,000,000 shares authorized, 120,512,710 and 42,395,366 issued and outstanding, respectively
|
|
|
120,513 |
|
|
|
|
|
|
|
120,513 |
|
|
|
42,395 |
|
|
Additional paid in capital
|
|
|
14,261,260 |
|
|
|
13,847,229 |
c,d,f |
|
|
28,108,489 |
|
|
|
14,116,707 |
|
|
Accumulated deficit
|
|
|
(8,018,942 |
) |
|
(19,845,418)
|
a,b,c,d,e,f,g |
|
|
(27,864,360 |
) |
|
|
(15,868,010 |
) |
|
TOTAL STOCKHOLDERS' EQUITY (DEFICIT)
|
|
|
6,365,086 |
|
|
|
(6,000,444 |
) |
|
|
364,642 |
|
|
|
(1,708,908 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
|
|
$ |
7,955,587 |
|
|
$ |
(5,851,367 |
) |
|
$ |
2,104,220 |
|
|
$ |
3,251 |
|
a: Reverse stock subscription receivable as not a valid transaction
b: Adjust for write off of worthless joint venture in 2006
c: Establish a payable and reverse amounts received for preferred stock issued without proper authority
d: Recognize value of common stock and warrants issued for services
e: Properly record costs of drilling and related depletion
f: Consolidation with Aurora Energy Partners
g: Reconciliation and presentation
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(Unaudited)
| |
|
For the Three Months Ended September 30,
|
|
|
For the Nine Months Ended September 30,
|
|
| |
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
| |
|
As Originally
|
|
|
Restatement
|
|
|
As
|
|
|
As
|
|
|
As Originally
|
|
|
Restatement
|
|
|
As
|
|
|
As
|
|
| |
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Restated
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Restated
|
|
|
REVENUES
|
|
$ |
357,617 |
|
|
$ |
120,563 |
a,d |
|
$ |
478,180 |
|
|
$ |
- |
|
|
$ |
758,636 |
|
|
$ |
675,223 |
a,d |
|
$ |
1,433,859 |
|
|
$ |
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COSTS AND EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of production
|
|
|
239,894 |
|
|
|
19,185 |
a,d |
|
|
259,079 |
|
|
|
- |
|
|
|
808,322 |
|
|
$ |
41,969 |
a,d |
|
|
850,291 |
|
|
|
- |
|
|
General and administrative expense
|
|
|
385,142 |
|
|
|
(225,299 |
) a,d |
|
|
159,843 |
|
|
|
142,159 |
|
|
|
2,305,487 |
|
|
556,331
|
a.d |
|
|
2,861,818 |
|
|
|
8,510,005 |
|
|
Depletion and accretion
|
|
|
- |
|
|
|
158,357 |
c,d |
|
|
158,357 |
|
|
|
- |
|
|
|
- |
|
|
|
333,162 |
c,d |
|
|
333,162 |
|
|
|
- |
|
|
Malfeasance losses
|
|
|
- |
|
|
|
4,365,949 |
f |
|
|
4,365,949 |
|
|
|
- |
|
|
|
- |
|
|
|
5,036,984 |
f |
|
|
5,036,984 |
|
|
|
- |
|
|
Loss from settlement with former officer
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
390,000 |
b |
|
|
390,000 |
|
|
|
- |
|
|
Total expenses
|
|
|
385,142 |
h |
|
|
4,318,192 |
|
|
|
4,943,228 |
|
|
|
142,159 |
|
|
|
3,113,809 |
h |
|
|
6,358,446 |
|
|
|
9,472,255 |
|
|
|
8,510,005 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOSS FROM OPERATIONS
|
|
|
(38,525 |
) |
|
|
(4,197,629 |
) |
|
|
(4,465,048 |
) |
|
|
(142,159 |
) |
|
|
(2,355,173 |
) |
|
|
(5,683,223 |
) |
|
|
(8,038,396 |
) |
|
|
(8,510,005 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME AND EXPENSE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Sale of working interest in wells
|
|
|
(4,678,000 |
) |
|
|
4,678,000 |
e |
|
|
- |
|
|
|
- |
|
|
|
(7,678,000 |
) |
|
|
(7,678,000 |
)e |
|
|
- |
|
|
|
- |
|
|
Interest expense
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,381 |
g |
|
|
4,381 |
|
|
|
- |
|
|
Total other (income) expense
|
|
|
(4,678,000 |
) |
|
|
4,678,000 |
|
|
|
- |
|
|
|
- |
|
|
|
(7,678,000 |
) |
|
|
(7,673,619 |
) |
|
|
4,381 |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS
|
|
$ |
4,639,475 |
h
|
|
$ |
(8,875,629 |
) |
|
$ |
(4,465,048 |
) |
|
$ |
(142,159 |
) |
|
$ |
5,322,827 |
h |
|
$ |
1,990,396 |
|
|
$ |
(8,042,777 |
) |
|
$ |
(8,510,005 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares, basic and diluted
|
|
|
118,933,524 |
|
|
|
263,594 |
i |
|
|
119,197,118 |
|
|
|
31,825,366 |
|
|
|
308,036,585 |
|
|
|
(225,217,728 |
)i |
|
|
82,818,857 |
|
|
|
21,461,340 |
|
|
Net income (loss) per share, basic and diluted
|
|
$ |
0.04 |
|
|
$ |
(33.67 |
) |
|
$ |
(0.04 |
) |
|
$ |
(0.00 |
) |
|
$ |
0.02 |
|
|
$ |
(0.01 |
) |
|
$ |
(0.10 |
) |
|
$ |
(0.40 |
) |
Footnotes:
a: Properly accrue verifiable revenue amounts and related costs
b: Recognize value of common stock and warrants issued for services
c: Properly record costs of drilling and related depletion
d: Consolidation with Aurora Energy Partners
e: Reverse inappropriate entry
f: Post investigation
g: Reconciliation and presentation
h: Arithmetic error in original statement not corrected
i: Recalculated to tie to stock transfer ledger
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW
(Unaudited)
| |
|
For the Nine Months Ended September 30,
|
|
| |
|
2008
|
|
|
|
|
|
2008
|
|
|
2007
|
|
| |
|
As Originally
|
|
|
|
|
|
As
|
|
|
As
|
|
| |
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Restated
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOW FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$ |
(2,355,173 |
) |
|
$ |
(5,687,604 |
) |
|
$ |
(8,042,777 |
) |
|
$ |
(8,510,005 |
) |
|
Adjustment to reconcile net loss from operations to net cash provided by (used in) operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion
|
|
|
- |
|
|
|
332,028 |
e |
|
|
332,028 |
|
|
|
- |
|
|
Accretion to asset retirement obligation
|
|
|
- |
|
|
|
1,134 |
e |
|
|
1,134 |
|
|
|
- |
|
|
Common stock for services
|
|
|
1,967,050 |
|
|
|
115,075 |
d |
|
|
2,082,125 |
|
|
|
8,012,726 |
|
|
Common stock for settlement
|
|
|
- |
|
|
|
390,000 |
d |
|
|
390,000 |
|
|
|
- |
|
|
Warrants for services
|
|
|
- |
|
|
|
335,566 |
d |
|
|
335,566 |
|
|
|
- |
|
|
Change in working capital
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivable from related party
|
|
|
- |
|
|
|
(300,000 |
)f |
|
|
(300,000 |
) |
|
|
- |
|
|
Deposits
|
|
|
- |
|
|
|
(3,131 |
)f,g |
|
|
(3,131 |
) |
|
|
- |
|
|
Prepaid expense
|
|
|
(7,250 |
) |
|
|
- |
|
|
|
(7,250 |
) |
|
|
|
|
|
Accounts payable
|
|
|
75,978 |
|
|
|
(82,964 |
)f,g |
|
|
(6,986 |
) |
|
|
15,379 |
|
|
Accrued liabilities
|
|
|
320,500 |
|
|
|
(320,500 |
)f,g |
|
|
- |
|
|
|
- |
|
|
Asset retirement obligations
|
|
|
- |
|
|
|
16,617 |
e |
|
|
16,617 |
|
|
|
- |
|
|
Net cash provided by (used in) operating activities
|
|
|
1,105 |
|
|
|
(5,203,779 |
) |
|
|
(5,202,674 |
) |
|
|
(481,900 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling costs
|
|
|
(6,304,000 |
) |
|
|
7,877,892 |
e |
|
|
1,573,892 |
|
|
|
- |
|
|
Drilled wells
|
|
|
- |
|
|
|
(1,746,727 |
)e |
|
|
(1,746,727 |
) |
|
|
- |
|
|
Purchase of wells
|
|
|
(1,430,000 |
) |
|
|
(6,599 |
)e |
|
|
(1,436,599 |
) |
|
|
- |
|
|
Net cash provided by (used in) investing activities
|
|
|
(7,734,000 |
) |
|
|
6,124,566 |
|
|
|
(1,609,434 |
) |
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank line of credit net borrowings (repayments)
|
|
|
(5,446 |
) |
|
|
(1,171 |
)g |
|
|
(6,617 |
) |
|
|
23,879 |
|
|
Proceeds from notes payable to related parties
|
|
|
- |
|
|
|
300,000 |
f |
|
|
300,000 |
|
|
|
- |
|
|
Proceeds from former officer
|
|
|
- |
|
|
|
639,951 |
g |
|
|
639,951 |
|
|
|
- |
|
|
Payments on notes payable to related parties
|
|
|
- |
|
|
|
(120,000 |
)f |
|
|
(120,000 |
) |
|
|
- |
|
|
Payments to former officer
|
|
|
(498,573 |
) |
|
|
(168,579 |
)g |
|
|
(667,152 |
) |
|
|
458,150 |
|
|
Proceeds from sale of working interest in wells
|
|
|
7,678,000 |
|
|
|
(7,678,000 |
)i |
|
|
- |
|
|
|
- |
|
|
Warrants exercised
|
|
|
- |
|
|
|
350,000 |
d |
|
|
350,000 |
|
|
|
- |
|
|
Aurora capital contributions
|
|
|
- |
|
|
|
7,495,000 |
f |
|
|
7,495,000 |
|
|
|
- |
|
|
Aurora capital distributions
|
|
|
- |
|
|
|
(725,942 |
)f |
|
|
(725,942 |
) |
|
|
- |
|
|
Conversion of preferred stock to common stock
|
|
|
200,000 |
|
|
|
(200,000 |
)d |
|
|
- |
|
|
|
- |
|
|
Sale of common stock
|
|
|
110,000 |
|
|
|
(49,950 |
)g |
|
|
60,050 |
|
|
|
- |
|
|
Sale of warrants
|
|
|
250,000 |
|
|
|
(250,000 |
)d |
|
|
- |
|
|
|
- |
|
|
Net cash provided by (used in) financing activities
|
|
|
7,733,981 |
|
|
|
(408,691 |
) |
|
|
7,325,290 |
|
|
|
482,029 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
1,086 |
|
|
|
512,096 |
|
|
|
513,182 |
|
|
|
129 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning cash and cash equivalents
|
|
|
3,251 |
|
|
|
- |
|
|
|
3,251 |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending cash and cash equivalents
|
|
$ |
4,337 |
|
|
$ |
512,096 |
|
|
$ |
516,433 |
|
|
$ |
129 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental schedule of non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Dividend
|
|
$ |
- |
|
|
$ |
3,953,573 |
j |
|
$ |
3,953,573 |
|
|
$ |
- |
|
|
Preferred stock converted to common stock
|
|
$ |
- |
|
|
$ |
129,529 |
k |
|
$ |
129,529 |
|
|
$ |
29,336 |
|
a: Reverse stock subscription receivable as not a valid transaction
b: Adjust for write off of worthless joint venture in 2006
c: Establish a payable and reverse amounts received for preferred stock issued without proper authority
d: Recognize value of common stock and warrants issued for services
e: Properly record costs of drilling and related depletion
f: Consolidation with Aurora Energy Partners
g: Reconciliation and presentation
h: Declaration of stock dividend
i: Reverse inappropriate entry
j: Stock dividend declared
k: Preferred stock converted to common stock
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| |
|
March 31,
|
|
|
December 31,
|
|
| |
|
2009
|
|
|
2008
|
|
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
43,499 |
|
|
$ |
166,189 |
|
|
Prepaid expenses
|
|
|
7,250 |
|
|
|
7,250 |
|
|
Total current assets
|
|
|
50,749 |
|
|
|
173,439 |
|
| |
|
|
|
|
|
|
|
|
|
FIXED ASSETS
|
|
|
|
|
|
|
|
|
|
Furniture and equipment
|
|
|
2,294 |
|
|
|
2,294 |
|
|
Accumulated depreciation
|
|
|
(2,294 |
) |
|
|
(2,294 |
) |
|
Total furniture and fixtures
|
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
Oil and natural gas properties
|
|
|
2,002,899 |
|
|
|
1,594,565 |
|
|
Accumulated depletion
|
|
|
(635,394 |
) |
|
|
(562,808 |
) |
|
Oil and natural gas properties, net
|
|
|
1,367,505 |
|
|
|
1,031,757 |
|
| |
|
|
|
|
|
|
|
|
|
OTHER ASSETS
|
|
|
|
|
|
|
|
|
|
Fund held at court
|
|
|
9,096 |
|
|
|
5,664 |
|
| |
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$ |
1,427,350 |
|
|
$ |
1,210,860 |
|
| |
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS' DEFICIT
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$ |
69,546 |
|
|
$ |
38,414 |
|
|
Line of credit
|
|
|
91,858 |
|
|
|
94,353 |
|
|
Loans payable to related party
|
|
|
343,673 |
|
|
|
383,673 |
|
|
Liability for unauthorized preferred stock issued
|
|
|
85,654 |
|
|
|
32,159 |
|
|
Amounts due former officer
|
|
|
1,685,055 |
|
|
|
1,636,489 |
|
|
Total Current Liabilities
|
|
|
2,275,786 |
|
|
|
2,185,088 |
|
| |
|
|
|
|
|
|
|
|
|
OTHER LIABILITIES
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligation
|
|
|
21,073 |
|
|
|
20,120 |
|
|
TOTAL LIABILITIES
|
|
|
2,296,859 |
|
|
|
2,205,208 |
|
| |
|
|
|
|
|
|
|
|
|
STOCKHOLDERS' DEFICIT
|
|
|
|
|
|
|
|
|
|
Preferred stock, $0.001 par value, 10,000,000 shares authorized; none issued and outstanding after restatement
|
|
|
- |
|
|
|
- |
|
|
Common Stock, $0.001 par value, 200,000,000 shares authorized, 136,719,608 and 136,719,608 issued and outstanding, respectively
|
|
|
136,720 |
|
|
|
136,720 |
|
|
Additional paid in capital
|
|
|
30,825,447 |
|
|
|
30,188,672 |
|
|
Accumulated deficit
|
|
|
(31,831,676 |
) |
|
|
(31,319,740 |
) |
|
TOTAL STOCKHOLDERS' DEFICIT
|
|
|
(869,509 |
) |
|
|
(994,348 |
) |
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT
|
|
$ |
1,427,350 |
|
|
$ |
1,210,860 |
|
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(Unaudited)
| |
|
For the Three Months Ending March 31,
|
|
| |
|
2009
|
|
|
2008
|
|
| |
|
|
|
|
(As Restated)
|
|
|
REVENUES
|
|
$ |
140,000 |
|
|
$ |
436,974 |
|
| |
|
|
|
|
|
|
|
|
|
COSTS AND EXPENSES
|
|
|
|
|
|
|
|
|
|
Costs of production
|
|
|
57,186 |
|
|
|
287,422 |
|
|
General and administrative expense
|
|
|
257,889 |
|
|
|
2,010,029 |
|
|
Depletion and accretion
|
|
|
72,910 |
|
|
|
59,511 |
|
|
Malfeasance losses
|
|
|
249,771 |
|
|
|
36,470 |
|
|
Total expenses
|
|
|
637,756 |
|
|
|
2,393,432 |
|
| |
|
|
|
|
|
|
|
|
|
LOSS FROM OPERATIONS
|
|
|
(497,756 |
) |
|
|
(1,956,458 |
) |
| |
|
|
|
|
|
|
|
|
|
OTHER INCOME AND EXPENSE
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
4,519 |
|
|
|
- |
|
|
Other
|
|
|
9,661 |
|
|
|
- |
|
|
Total other expense
|
|
|
14,180 |
|
|
|
- |
|
|
NET LOSS
|
|
$ |
(511,936 |
) |
|
$ |
(1,956,458 |
) |
| |
|
|
|
|
|
|
|
|
|
Weighted average shares, basic and diluted
|
|
|
136,719,608 |
|
|
|
48,257,700 |
|
|
Net loss per share, basic and diluted
|
|
$ |
(0.00 |
) |
|
$ |
(0.04 |
) |
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOW
(Unaudited)
| |
|
For the Three Months Ended March 31,
|
|
| |
|
2009
|
|
|
2008
|
|
| |
|
|
|
|
(As Restated)
|
|
|
CASH FLOW FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
Net loss
|
|
$ |
(511,936 |
) |
|
$ |
(1,956,458 |
) |
|
Adjustment to reconcile net loss from operations to net cash used in operating activities
|
|
|
|
|
|
|
|
|
|
Depletion
|
|
|
72,586 |
|
|
|
59,149 |
|
|
Accretion to asset retirement obligation
|
|
|
324 |
|
|
|
362 |
|
|
Common stock for services
|
|
|
- |
|
|
|
1,611,625 |
|
|
Warrants for services
|
|
|
12,992 |
|
|
|
245,000 |
|
|
Change in working capital
|
|
|
|
|
|
|
|
|
|
Receivable from related party
|
|
|
- |
|
|
|
(300,000 |
) |
|
Funds held at court
|
|
|
(3,432 |
) |
|
|
- |
|
|
Accounts payable
|
|
|
29,820 |
|
|
|
19,031 |
|
|
Accrued liabilities
|
|
|
1,359 |
|
|
|
- |
|
|
Asset retirement obligations
|
|
|
629 |
|
|
|
15,517 |
|
|
Net cash provided used in operating activities
|
|
|
(397,658 |
) |
|
|
(305,774 |
) |
| |
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Drilling costs
|
|
|
- |
|
|
|
(1,120,000 |
) |
|
Drilled wells
|
|
|
(9,715 |
) |
|
|
- |
|
|
Purchase of wells
|
|
|
(398,619 |
) |
|
|
(1,436,599 |
) |
|
Net cash used in investing activities
|
|
|
(408,334 |
) |
|
|
(2,556,599 |
) |
| |
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Bank line of credit net borrowings (repayments)
|
|
|
(2,495 |
) |
|
|
(2,668 |
) |
|
Proceeds from notes payable to related parties
|
|
|
30,000 |
|
|
|
300,000 |
|
|
Proceeds from unauthorized preferred stock issued
|
|
|
53,499 |
|
|
|
- |
|
|
Proceeds from former officer
|
|
|
75,674 |
|
|
|
210,715 |
|
|
Payments on notes payable to related party
|
|
|
(70,000 |
) |
|
|
- |
|
|
Payments to former officer
|
|
|
(27,159 |
) |
|
|
(167,225 |
) |
|
Sale of common stock
|
|
|
- |
|
|
|
42,000 |
|
|
Aurora capital contributions
|
|
|
890,000 |
|
|
|
2,750,000 |
|
|
Aurora capital distributions
|
|
|
(266,217 |
) |
|
|
(273,700 |
) |
|
Net cash provided by financing activities
|
|
|
683,302 |
|
|
|
2,859,122 |
|
| |
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
(122,690 |
) |
|
|
(3,251 |
) |
| |
|
|
|
|
|
|
|
|
|
Beginning cash and cash equivalents
|
|
|
166,189 |
|
|
|
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
Ending cash and cash equivalents
|
|
$ |
43,499 |
|
|
$ |
- |
|
| |
|
|
|
|
|
|
|
|
|
Supplemental schedule of non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
Preferred stock converted to common stock
|
|
$ |
- |
|
|
$ |
15,470 |
|
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| |
|
June 30,
|
|
|
December 31,
|
|
| |
|
2009
|
|
|
2008
|
|
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
2,157 |
|
|
$ |
166,189 |
|
|
Prepaid expenses
|
|
|
7,250 |
|
|
|
7,250 |
|
|
Total current assets
|
|
|
9,407 |
|
|
|
173,439 |
|
| |
|
|
|
|
|
|
|
|
|
FIXED ASSETS
|
|
|
|
|
|
|
|
|
|
Furniture and equipment
|
|
|
2,294 |
|
|
|
2,294 |
|
|
Accumulated depreciation
|
|
|
(2,294 |
) |
|
|
(2,294 |
) |
|
Total furniture and fixtures
|
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
Oil and natural gas properties
|
|
|
2,002,899 |
|
|
|
1,594,565 |
|
|
Accumulated depletion
|
|
|
(707,980 |
) |
|
|
(562,808 |
) |
|
Oil and natural gas properties, net
|
|
|
1,294,919 |
|
|
|
1,031,757 |
|
| |
|
|
|
|
|
|
|
|
|
OTHER ASSETS
|
|
|
|
|
|
|
|
|
|
Funds held at court
|
|
|
11,471 |
|
|
|
5,664 |
|
| |
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$ |
1,315,797 |
|
|
$ |
1,210,860 |
|
| |
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$ |
146,265 |
|
|
$ |
38,367 |
|
|
Line of credit
|
|
|
88,097 |
|
|
|
94,353 |
|
|
Loans payable to related party
|
|
|
368,673 |
|
|
|
383,673 |
|
|
Liability for unauthorized preferred stock issued
|
|
|
85,654 |
|
|
|
32,159 |
|
|
Amounts due former officer
|
|
|
447,073 |
|
|
|
1,636,536 |
|
|
Total current liabilities
|
|
|
1,135,762 |
|
|
|
2,185,088 |
|
| |
|
|
|
|
|
|
|
|
|
OTHER LIABILITIES
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligation
|
|
|
21,424 |
|
|
|
20,120 |
|
|
TOTAL LIABILITIES
|
|
|
1,157,186 |
|
|
|
2,205,208 |
|
| |
|
|
|
|
|
|
|
|
|
STOCKHOLDERS' EQUITY (DEFICIT)
|
|
|
|
|
|
|
|
|
|
Preferred stock, $0.001 par value, 10,000,000 shares authorized; none issued and outstanding after restatement
|
|
|
- |
|
|
|
- |
|
|
Common Stock, $0.001 par value, 200,000,000 shares authorized, 136,719,608 and 136,719,608 issued and outstanding respectively
|
|
|
136,720 |
|
|
|
136,720 |
|
|
Additional paid in capital
|
|
|
31,011,028 |
|
|
|
30,188,672 |
|
|
Accumulated deficit
|
|
|
(30,989,137 |
) |
|
|
(31,319,740 |
) |
|
TOTAL STOCKHOLDERS' EQUITY (DEFICIT)
|
|
|
158,611 |
|
|
|
(994,348 |
) |
| |
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
|
|
$ |
1,315,797 |
|
|
$ |
1,210,860 |
|
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(Unaudited)
| |
|
For the Three Months Ended June 30,
|
|
|
For the Six Months Ended June 30,
|
|
| |
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
| |
|
|
|
|
(As Restated)
|
|
|
|
|
|
(As Restated)
|
|
|
REVENUES
|
|
$ |
117,845 |
|
|
$ |
518,705 |
|
|
$ |
257,845 |
|
|
$ |
955,679 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COSTS AND EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of production
|
|
|
45,068 |
|
|
|
303,790 |
|
|
|
102,254 |
|
|
|
591,212 |
|
|
General and administrative expense
|
|
|
298,539 |
|
|
|
691,946 |
|
|
|
556,428 |
|
|
|
2,701,975 |
|
|
Depletion and accretion
|
|
|
72,938 |
|
|
|
115,294 |
|
|
|
145,848 |
|
|
|
174,805 |
|
|
Malfeasance losses
|
|
|
70,401 |
|
|
|
634,565 |
|
|
|
320,172 |
|
|
|
671,035 |
|
|
Loss (gain) from settlement with former officer
|
|
|
(1,219,409 |
) |
|
|
390,000 |
|
|
|
(1,209,748 |
) |
|
|
390,000 |
|
|
Total expenses
|
|
|
(732,463 |
) |
|
|
2,135,595 |
|
|
|
(85,046 |
) |
|
|
4,529,027 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOSS FROM OPERATIONS
|
|
|
850,308 |
|
|
|
(1,616,890 |
) |
|
|
342,891 |
|
|
|
(3,573,348 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME AND EXPENSE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
7,769 |
|
|
|
4,381 |
|
|
|
12,288 |
|
|
|
4,381 |
|
|
Total other expense
|
|
|
7,769 |
|
|
|
4,381 |
|
|
|
12,288 |
|
|
|
4,381 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
|
|
$ |
842,539 |
|
|
$ |
(1,621,271 |
) |
|
$ |
330,603 |
|
|
$ |
(3,577,729 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares, basic and diluted
|
|
|
136,719,608 |
|
|
|
80,601,992 |
|
|
|
136,719,608 |
|
|
|
64,429,846 |
|
|
Net income (loss) per share, basic and diluted
|
|
$ |
0.01 |
|
|
$ |
(0.02 |
) |
|
$ |
0.00 |
|
|
$ |
(0.06 |
) |
Note: Diluted earnings per share are not presented for the three and six months ended June 30, 2009 as the net income arises from a one time gain on settlement and not from the on-going operations of the Company.
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOW
(Unaudited)
| |
|
For the Six Months Ended June 30,
|
|
| |
|
2009
|
|
|
2008
|
|
| |
|
|
|
|
(As Restated)
|
|
|
CASH FLOW FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$ |
330,603 |
|
|
$ |
(3,577,729 |
) |
|
Adjustment to reconcile net loss from operations to net cash used in operating activities
|
|
|
|
|
|
|
|
|
|
Depletion
|
|
|
145,172 |
|
|
|
174,057 |
|
|
Accretion to asset retirement obligation
|
|
|
758 |
|
|
|
748 |
|
|
Amortization of debt discount
|
|
|
1,450 |
|
|
|
- |
|
|
Common stock for services
|
|
|
|
|
|
|
2,082,125 |
|
|
Common stock for settlement
|
|
|
- |
|
|
|
390,000 |
|
|
Warrants for services
|
|
|
18,572 |
|
|
|
313,726 |
|
|
Gain on settlement with former officer
|
|
|
(1,209,748 |
) |
|
|
- |
|
|
Change in working capital
|
|
|
|
|
|
|
|
|
|
Receivable from related party
|
|
|
- |
|
|
|
(300,000 |
) |
|
Funds held at court
|
|
|
(5,807 |
) |
|
|
(177,250 |
) |
|
Accounts payable
|
|
|
102,628 |
|
|
|
(5,589 |
) |
|
Accured liabilities
|
|
|
5,267 |
|
|
|
- |
|
|
Asset retirement obligations
|
|
|
546 |
|
|
|
16,618 |
|
|
Net cash used in operating activities
|
|
|
(610,559 |
) |
|
|
(1,083,294 |
) |
| |
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Drilling costs
|
|
|
- |
|
|
|
(1,227,106 |
) |
|
Drilled wells
|
|
|
(9,715 |
) |
|
|
(1,135,325 |
) |
|
Purchase of wells
|
|
|
(398,619 |
) |
|
|
(1,436,599 |
) |
|
Net cash used in investing activities
|
|
|
(408,334 |
) |
|
|
(3,799,030 |
) |
| |
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Bank line of credit net borrowings (repayments)
|
|
|
(6,256 |
) |
|
|
(6,486 |
) |
|
Proceeds from notes payable to related parties
|
|
|
55,000 |
|
|
|
300,000 |
|
|
Proceeds from unauthorized preferred stock issued
|
|
|
53,499 |
|
|
|
- |
|
|
Proceeds from former officer
|
|
|
37,385 |
|
|
|
540,084 |
|
|
Payments on notes payable to related party
|
|
|
(70,000 |
) |
|
|
(90,000 |
) |
|
Payments to former officer
|
|
|
(18,550 |
) |
|
|
(650,273 |
) |
|
Warrants exercised
|
|
|
- |
|
|
|
350,000 |
|
|
Sale of common stock
|
|
|
- |
|
|
|
60,050 |
|
|
Aurora capital contributions
|
|
|
1,090,000 |
|
|
|
4,895,000 |
|
|
Aurora capital distributions
|
|
|
(286,217 |
) |
|
|
(519,048 |
) |
|
Net cash provided by financing activities
|
|
|
854,861 |
|
|
|
4,879,327 |
|
| |
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
(164,032 |
) |
|
|
(2,997 |
) |
| |
|
|
|
|
|
|
|
|
|
Beginning cash and cash equivalents
|
|
|
166,189 |
|
|
|
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
Ending cash and cash equivalents
|
|
$ |
2,157 |
|
|
$ |
254 |
|
| |
|
|
|
|
|
|
|
|
Supplemental schedule of non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
Stock dividend paid
|
|
$ |
- |
|
|
$ |
3,953,573 |
|
|
Preferred stock converted to common stock
|
|
$ |
- |
|
|
$ |
114,059 |
|
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| |
|
September 30,
|
|
|
December 31,
|
|
| |
|
2009
|
|
|
2008
|
|
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
2,294 |
|
|
$ |
166,189 |
|
|
Accounts receivable
|
|
|
34,536 |
|
|
|
- |
|
|
Prepaid expenses
|
|
|
8,819 |
|
|
|
7,250 |
|
|
Total current assets
|
|
|
45,649 |
|
|
|
173,439 |
|
| |
|
|
|
|
|
|
|
|
|
FIXED ASSETS
|
|
|
|
|
|
|
|
|
|
Furniture and equipment
|
|
|
2,294 |
|
|
|
2,294 |
|
|
Accumulated depreciation
|
|
|
(2,294 |
) |
|
|
(2,294 |
) |
|
Total furniture and fixtures
|
|
|
- |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
Oil and natural gas properties
|
|
|
2,002,899 |
|
|
|
1,594,565 |
|
|
Accumulated depletion
|
|
|
(780,566 |
) |
|
|
(562,808 |
) |
|
Oil and natural gas properties, net
|
|
|
1,222,333 |
|
|
|
1,031,757 |
|
| |
|
|
|
|
|
|
|
|
|
OTHER ASSETS
|
|
|
|
|
|
|
|
|
|
Funds held at court
|
|
|
13,006 |
|
|
|
5,664 |
|
| |
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$ |
1,280,988 |
|
|
$ |
1,210,860 |
|
| |
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDER'S DEFICIT
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$ |
248,716 |
|
|
$ |
38,367 |
|
|
Line of credit
|
|
|
86,843 |
|
|
|
94,353 |
|
|
Loans payable to related party
|
|
|
478,674 |
|
|
|
383,673 |
|
|
Liability for unauthorized preferred stock issued
|
|
|
85,654 |
|
|
|
32,159 |
|
|
Amounts due former officer
|
|
|
420,962 |
|
|
|
1,636,536 |
|
|
Total current liabilities
|
|
|
1,320,849 |
|
|
|
2,185,088 |
|
| |
|
|
|
|
|
|
|
|
|
OTHER LIABILITIES
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligation
|
|
|
21,776 |
|
|
|
20,120 |
|
|
TOTAL LIABILITIES
|
|
|
1,342,625 |
|
|
|
2,205,208 |
|
| |
|
|
|
|
|
|
|
|
|
STOCKHOLDERS' DEFICIT
|
|
|
|
|
|
|
|
|
|
Preferred stock, $0.001 par value, 10,000,000 shares authorized; none issued and outstanding after restatement
|
|
|
- |
|
|
|
- |
|
|
Common Stock, $0.001 par value, 200,000,000 shares authorized, 136,719,608 and 136,719,608 issued and outstanding, respectively
|
|
|
136,720 |
|
|
|
136,720 |
|
|
Additional paid in capital
|
|
|
30,994,737 |
|
|
|
30,188,672 |
|
|
Accumulated deficit
|
|
|
(31,193,094 |
) |
|
|
(31,319,740 |
) |
|
TOTAL STOCKHOLDERS' DEFICIT
|
|
|
(61,637 |
) |
|
|
(994,348 |
) |
| |
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT
|
|
$ |
1,280,988 |
|
|
$ |
1,210,860 |
|
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
| |
|
For the Three Months Ended
|
|
|
For the Nine Months Ended
|
|
| |
|
September 30,
|
|
|
September 30,
|
|
| |
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
| |
|
|
|
|
(As Restated)
|
|
|
|
|
|
(As Restated)
|
|
|
REVENUES
|
|
$ |
111,520 |
|
|
$ |
478,180 |
|
|
$ |
369,365 |
|
|
$ |
1,433,859 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COSTS AND EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of production
|
|
|
42,290 |
|
|
|
259,079 |
|
|
|
144,544 |
|
|
|
850,291 |
|
|
General and administrative expense
|
|
|
218,623 |
|
|
|
159,843 |
|
|
|
775,051 |
|
|
|
2,861,818 |
|
|
Depletion and accretion
|
|
|
72,938 |
|
|
|
158,357 |
|
|
|
218,786 |
|
|
|
333,162 |
|
|
Malfeasance losses
|
|
|
(22,054 |
) |
|
|
4,365,949 |
|
|
|
298,118 |
|
|
|
5,036,984 |
|
|
Loss (gain) from settlement with former officer
|
|
|
(10,000 |
) |
|
|
- |
|
|
|
(1,219,748 |
) |
|
|
390,000 |
|
|
Total expenses
|
|
|
301,797 |
|
|
|
4,943,228 |
|
|
|
216,751 |
|
|
|
9,472,255 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOSS FROM OPERATIONS
|
|
|
(190,277 |
) |
|
|
(4,465,048 |
) |
|
|
152,614 |
|
|
|
(8,038,396 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME AND EXPENSE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
13,680 |
|
|
|
- |
|
|
|
25,968 |
|
|
|
4,381 |
|
|
Total other expense
|
|
|
13,680 |
|
|
|
- |
|
|
|
25,968 |
|
|
|
4,381 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
|
|
$ |
(203,957 |
) |
|
$ |
(4,465,048 |
) |
|
$ |
126,646 |
|
|
$ |
(8,042,777 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares, basic and diluted
|
|
|
136,719,608 |
|
|
|
119,197,118 |
|
|
|
136,719,608 |
|
|
|
82,818,857 |
|
|
Net loss per share, basic and diluted
|
|
$ |
(0.00 |
) |
|
$ |
(0.04 |
) |
|
$ |
0.00 |
|
|
$ |
(0.10 |
) |
Note: Diluted earnings per share are not presented for the nine months ended September 30, 2009 as the net income arises from a one time gain on settlement and not from the on-going operations of the Company.
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOW
(Unaudited)
| |
|
For the Nine Months Ended
|
|
| |
|
September 30,
|
|
| |
|
2009
|
|
|
2008
|
|
| |
|
|
|
|
(As Restated)
|
|
|
CASH FLOW FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$ |
126,646 |
|
|
$ |
(8,042,777 |
) |
Adjustment to reconcile net loss from operations to net cash used in operating activities:
|
|
|
|
|
|
|
|
|
|
Depletion
|
|
|
217,758 |
|
|
|
332,028 |
|
|
Accretion to asset retirement obligation
|
|
|
1,147 |
|
|
|
1,134 |
|
|
Amortization of debt discount
|
|
|
3,889 |
|
|
|
- |
|
|
Common stock for services
|
|
|
- |
|
|
|
2,082,125 |
|
|
Common stock for settlement
|
|
|
- |
|
|
|
390,000 |
|
|
Warrants for services
|
|
|
23,400 |
|
|
|
335,566 |
|
|
Gain on settlement with former officer
|
|
|
(1,219,748 |
) |
|
|
- |
|
|
Change in working capital:
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(34,536 |
) |
|
|
- |
|
|
Receivable from related party
|
|
|
- |
|
|
|
(300,000 |
) |
|
Funds held at court
|
|
|
(7,342 |
) |
|
|
(3,131 |
) |
|
Prepaid expense
|
|
|
(1,569 |
) |
|
|
(7,250 |
) |
|
Accounts payable
|
|
|
184,537 |
|
|
|
(6,986 |
) |
|
Accred liabilities
|
|
|
25,813 |
|
|
|
- |
|
|
Asset retirement obligations
|
|
|
509 |
|
|
|
16,617 |
|
|
Net cash used in operating activities
|
|
|
(679,496 |
) |
|
|
(5,202,674 |
) |
| |
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Drilling costs
|
|
|
- |
|
|
|
1,573,892 |
|
|
Drilled wells
|
|
|
(9,715 |
) |
|
|
(1,746,727 |
) |
|
Purchase of wells
|
|
|
(398,619 |
) |
|
|
(1,436,599 |
) |
|
Net cash used in investing activities
|
|
|
(408,334 |
) |
|
|
(1,609,434 |
) |
| |
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Bank line of credit net borrowings (repayments)
|
|
|
(7,510 |
) |
|
|
(6,617 |
) |
|
Proceeds from notes payable to related parties
|
|
|
165,000 |
|
|
|
300,000 |
|
|
Proceeds from unauthorized preferred stock issued
|
|
|
53,499 |
|
|
|
- |
|
|
Proceeds from former officer
|
|
|
44,943 |
|
|
|
639,951 |
|
|
Payments on notes payable to related parties
|
|
|
(70,000 |
) |
|
|
(120,000 |
) |
|
Payments to former officer
|
|
|
(44,661 |
) |
|
|
(667,152 |
) |
|
Warrants exercised
|
|
|
- |
|
|
|
350,000 |
|
|
Sale of common stock
|
|
|
- |
|
|
|
60,050 |
|
|
Aurora capital contributions
|
|
|
1,107,529 |
|
|
|
7,495,000 |
|
|
Aurora capital distributions
|
|
|
(324,865 |
) |
|
|
(725,942 |
) |
|
Net cash provided by financing activities
|
|
|
923,935 |
|
|
|
7,325,290 |
|
| |
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
(163,895 |
) |
|
|
513,182 |
|
| |
|
|
|
|
|
|
|
|
|
Beginning cash and cash equivalents
|
|
|
166,189 |
|
|
|
3,251 |
|
| |
|
|
|
|
|
|
|
|
|
Ending cash and cash equivalents
|
|
$ |
2,294 |
|
|
$ |
516,433 |
|
| |
|
|
|
|
|
|
|
|
Supplemental schedule of non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
Stock dividend paid
|
|
$ |
- |
|
|
$ |
3,953,573 |
|
|
Preferred stock converted to common stock
|
|
$ |
- |
|
|
$ |
129,529 |
|
Victory Energy Corporation and Subsidiaries
Notes to the Consolidated Financial Statements
Note 1 – Financial Statement Presentation
Organization and nature of operations
Victory Energy Corporation (Pink Sheets symbol VYEY), formerly known as Victory Capital Holdings Corporation (the “Company”) was organized under the laws of the State of Nevada on January 7, 1982, under the name All Things, Inc. On March 21, 1985 the Corporation’s name was changed to New Environmental Technologies Corporation and on April 28, 2003 to Victory Capital Holdings Corporation. The name was changed finally to Victory Energy Corporation on May 3, 2006.
The business of the Company is to acquire, develop, produce and exploit oil and natural gas properties. The Company’s major oil and natural gas properties are located in Texas. The Company’s executive offices are located in Newport Beach, California and its operations offices are located in Austin, Texas.
The Company’s initial authorized capital consisted of 100,000,000 shares of $0.001 par value common voting stock and, as of the date of this filing, has authorized capital of 490,000,000 shares of $0.001 par value common stock.
Going concern
As presented in the consolidated financial statements, the Company has incurred a net loss of $465,746 during the twelve months ended December 31, 2009, and losses are expected to continue in the near term. Current liabilities exceeded current assets by $1,090,297 and the accumulated deficit is $31,704,879 at December 31, 2009. Amounts outstanding and payable to creditors are in arrears and the Company is in negotiations with certain creditors to obtain extensions and settlements of outstanding amounts. The Company is currently in default on one its debt obligations and the Company has no future borrowings or funding sources available under existing financing arrangements. Management anticipates that significant additional capital expenditures will be necessary to develop the Company’s oil and natural gas properties, which consist primarily of proved reserves that are non-producing, before significant positive operating cash flows will be achieved.
Management's plans to alleviate these conditions include the renegotiation of certain trade payables, settlements of debt amounts with stock, and deferral of certain scheduled payments, as considered necessary. In addition, management is pursuing business partnering arrangements for the acquisition and development of its properties as well as debt and equity funding through private placements. Without outside investment from the sale of equity securities, debt financing or partnering with other oil and natural gas companies, operating activities and overhead expenses will be reduced to a pace that available operating cash flows will support.
The accompanying consolidated financial statements are prepared as if the Company will continue as a going concern. The consolidated financial statements do not contain adjustments, including adjustments to recorded assets and liabilities, which might be necessary if the Company were unable to continue as a going concern.
Restatement of Consolidated Financial Statements
The Company has restated its consolidated balance sheet as of December 31, 2007, and the consolidated statements operations, stockholders equity (deficit) and cash flows for the year ending December 31, 2007.
The Management and Board of Directors of the Company have determined that the Company’s consolidated financial statements for the year ended December 31, 2007 need to be restated due to accounting errors in the Company’s valuation of stock-based compensation and the accounting of stock subscriptions receivable and payable.
Note 2 – Summary of Significant Accounting Policies
Principles of consolidation
The accompanying consolidated financial statements are presented in accordance with U.S. generally accepted accounting principles. The consolidated financial statements include the accounts of the Company and Aurora Energy Partners, A Texas General Partnership. The Company holds a 15% equity interest in Aurora Energy Partners. Since the Company serves as managing partner and is responsible for managing all business operations of the partnership, the financial statements of Aurora have been consolidated with the Company. All significant intercompany transactions have been eliminated. The consolidated financial statements reflect necessary adjustments, all of which were of a recurring nature and are in the opinion of management necessary for a fair presentation.
Property and equipment
Property and equipment are recorded at cost. Cost of repairs and maintenance are expensed as they are incurred. Major repairs that extend the useful life of equipment are capitalized and depreciated over the remaining estimated useful life. When property and equipment are sold or otherwise disposed, the related costs and accumulated depreciation are removed from the respective accounts and the gains or losses realized on the disposition are reflected in operations. The Company uses the straight-line method in computing depreciation for financial reporting purposes.
Revenue Recognition
We use the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of gas and oil sold to purchasers. The volumes sold may differ from the volumes to which we are entitled based on our interests in the properties. Differences between volumes sold and entitled volumes create oil and gas imbalances which are generally reflected as adjustments to reported proved oil and gas reserves and future cash flows in our supplemental oil and gas disclosures. If our excess takes of natural gas or oil exceed our estimated remaining proved reserves for a property, a natural gas or oil imbalance liability is recorded in the consolidated balance sheet.
Allowance for Doubtful Accounts
We recognize an allowance for doubtful accounts to ensure trade receivables are not overstated due to uncollectability. Bad debt reserves are maintained for all customers based on a variety of factors, including the length of time receivables are past due, macroeconomic conditions, significant one-time events and historical experience. An additional reserve for individual accounts is recorded when we become aware of a customer's inability to meet its financial obligations, such as in the case of bankruptcy filings or deterioration in the customer's operating results or financial position. If circumstances related to customers change, estimates of the recoverability of receivables would be further adjusted.
Fair Value of Financial Instruments
The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, other assets, fixed assets, derivative liability, deferred revenue, accounts payable, accrued liabilities and short-term debt. The estimated fair value of cash, accounts receivable, other assets, accounts payable, deferred revenue and accrued liabilities approximated their carrying amounts due to the short-term nature of these instruments. The carrying value of short-term debt also approximates fair value since their terms are similar to those in the lending market for comparable loans with comparable risks. None of these instruments are held for trading purposes.
The Company utilizes various types of financing to fund its business needs, including debt with warrants attached and other instruments indexed to its stock. The Company reviews its warrants and conversion features of securities issued as to whether they are freestanding or contain an embedded derivative and if so, whether they are classified as a liability at each reporting period until the amount is settled and reclassified into equity with changes in fair value recognized in current earnings.
Inputs used in the valuation to derive fair value are classified based on a fair value hierarchy which distinguishes between assumptions based on market data (observable inputs) and an entity’s own assumptions (unobservable inputs). The hierarchy consists of three levels:
| |
•
|
Level one – Quoted market prices in active markets for identical assets or liabilities;
|
| |
•
|
Level two - Inputs other than level one inputs that are either directly or indirectly observable; and
|
| |
•
|
Level three – Unobservable inputs developed using estimates and assumptions, which are developed by the reporting entity and reflect those assumptions that a market participant would use.
|
Determining which category an asset or liability falls within the hierarchy requires significant judgment. The company evaluates its hierarchy disclosures each quarter. The following table presents all assets that were measured and recognized at fair value as of December 31, 2009 and 2008, and for the twelve months then ended on a non-recurring basis. The assets shown below were presented at fair value due to the impairment analysis indicating an estimated fair value below the carrying value for the proved oil and gas properties.
Fair value of assets measured and recognized at fair value on a non-recurring basis as of December 31, 2009, 2008, and 2007 were as follows:
As of December 31, 2009 and for the year then ended:
|
Description
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total Realized
(Loss) due to
valuation
|
|
|
Total
Unrealized
(Loss)
|
|
|
Cash and Accounts Receivable
|
|
$ |
122, 395 |
|
|
$ |
- |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
Proved Properties (net)
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
807,381 |
|
|
$ |
(342,366 |
) |
|
$ |
— |
|
|
Totals
|
|
$ |
122, 395 |
|
|
$ |
— |
|
|
$ |
807,381 |
|
|
$ |
(342,366 |
) |
|
$ |
— |
|
As of December 31, 2008 and for the year then ended:
|
Description
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total Realized
(Loss) due to
valuation
|
|
|
Total
Unrealized
(Loss)
|
|
|
Cash and Accounts Receivable
|
|
$ |
166,189 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
Proved Properties (net)
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
1,031,757 |
|
|
$ |
(2,775,696 |
) |
|
$ |
— |
|
|
Totals
|
|
$ |
166,189 |
|
|
$ |
— |
|
|
$ |
1,031,757 |
|
|
$ |
(2,775,696 |
) |
|
$ |
— |
|
As of December 31, 2007 and for the year then ended:
|
Description
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total Realized
(Loss) due to
valuation
|
|
|
Total
Unrealized
(Loss)
|
|
|
Cash and Accounts Receivable
|
|
$ |
3,251 |
|
|
$ |
- |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
Proved Properties (net)
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
Totals
|
|
$ |
3,251 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
The Company valued the Proved Properties at their fair value in accordance with the applicable FASB standard due to the impairment indicators prevalent as of December 31, 2009 and 2008. The inputs that were used in determining the fair value of these assets were Level 3 inputs. These inputs consist of but are not limited to the following: estimates of reserve quantities, estimates of future production costs and taxes, estimates of consistent pricing of commodities, 10% discount rate, etc. Impairment expense was recorded at both year ends at the amount the carrying value of the assets exceeded their estimated fair values as of December 31, 2009 and 2008.
Recent Accounting Pronouncements
Recently Issued Accounting Standards
In August 2009, the FASB issued an amendment to the accounting standards related to the measurement of liabilities that are recognized or disclosed at fair value on a recurring basis. This standard clarifies how a company should measure the fair value of liabilities and that restrictions preventing the transfer of a liability should not be considered as a factor in the measurement of liabilities within the scope of this standard. This standard was effective for the Company on October 1, 2009.
In October 2009, the FASB issued an amendment to the accounting standards related to the accounting for revenue in arrangements with multiple deliverables including how the arrangement consideration is allocated among delivered and undelivered items of the arrangement. Among the amendments, this standard eliminates the use of the residual method for allocating arrangement consideration and requires an entity to allocate the overall consideration to each deliverable based on an estimated selling price of each individual deliverable in the arrangement in the absence of having vendor-specific objective evidence or other third party evidence of fair value of the undelivered items. This standard also provides further guidance on how to determine a separate unit of accounting in a multiple-deliverable revenue arrangement and expands the disclosure requirements about the judgments made in applying the estimated selling price method and how those judgments affect the timing or amount of revenue recognition. This standard, for which the Company is currently assessing the impact, will become effective for the Company on January 1, 2011.
Concentrations
There is a ready market for the sale of crude oil and natural gas. During 2009 and 2008, each of our fields sold all of its oil production to one purchaser for each field and all of its natural gas production to one purchaser for each field. However, because alternate purchasers of oil and natural gas are readily available at similar prices, we believe that the loss of any of our purchasers would not have a material adverse effect on our financial results
Accounting estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.
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
The Company accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, all costs associated with property acquisitions, successful exploratory wells, all development wells, including dry hole development wells, and asset retirement obligation assets are capitalized. Additionally, interest is capitalized while wells are being drilled and the underlying property is in development. Costs of exploratory wells are capitalized pending determination of whether each well has resulted in the discovery of proved reserves. Oil and natural gas mineral leasehold costs are capitalized as incurred. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells, and oil and natural gas production costs. Capitalized costs of proved properties including associated salvage are depleted on a well-by-well or field-by-field (common reservoir) basis using the units-of-production method based upon proved producing oil and natural gas reserves. The depletion rate is the current period production as a percentage of the total proved producing reserves. The depletion rate is applied to the net book value of property costs to calculate the depletion expense. Proved reserves materially impact depletion expense. If the proved reserves decline, then the depletion rate (the rate at which we record depletion expense) increases, reducing net income. Dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs with gain or loss recognized upon sale. A gain (loss) is recognized to the extent the sales price exceeds or is less than original cost or the carrying value, net of impairment. Oil and natural gas properties are also subject to impairment at the end of each reporting period. Unproved property costs are excluded from depletable costs until the related properties are developed. See impairment discussed in “Long-lived assets and intangible assets” below.
We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to 10 years.
Long-lived assets and intangible assets
The Company accounts for intangible assets in accordance with the applicable Accounting Standards Codification (“ASC”). Intangible assets that have defined lives are subject to amortization over the useful life of the assets. Intangible assets held having no contractual factors or other factors limiting the useful life of the asset are not subject to amortization but are reviewed at least annually for impairment or when indicators suggest that impairment may be needed. Intangible assets are subject to impairment review at least annually or when there is an indication that an asset has been impaired. While there are prospects for possible capital funding (either debt or equity), much is left to the market and outside instability. As such, at this time, management cannot anticipate with a comfortable degree of certainty if the appropriate amount of funding will be achieved and any funding will be diverted fully to its E&P activities. This will further postpone the Company’s ability to dedicate financial as well as human resources to its technology division in the short term future. As such, the Company has eliminated the division entirely.
For unproved property costs, management reviews these investments for impairment on a property-by-property basis if a triggering event should occur that may suggest that impairment may be required.
The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the carrying amount of the asset, including any intangible assets associated with that asset, exceeds its estimated future undiscounted net cash flows, the Company will recognize an impairment loss equal to the difference between its carrying amount and its estimated fair value. The fair value used to calculate the impairment for producing oil and natural gas field that produces from a common reservoir is first determined by comparing the undiscounted future net cash flows associated with total proved properties to the carrying value of the underlying evaluated property. If the cost of the underlying evaluated property is in excess of the undiscounted future net cash flows, the future net cash flows are discounted at 10%, which the Company believes approximates fair value, to determine the amount of impairment.
The Company recorded $342,666 and $2,775,696; respectively for 2009 and 2008 upon determining that the Crockett County gas project required impairment.
Asset retirement obligation
In accordance with the ASC, the Company recognizes the fair value of the liability for asset retirement costs in an entity’s balance sheet, as both a liability and an increase in the carrying values of such assets, in the periods in which such liabilities can be reasonably estimated. The present value of the estimated future asset retirement obligation (“ARO”), as of the date of acquisition or the date at which a successful well is drilled, is capitalized as part of the costs of proved oil and natural gas properties and recorded as a liability. The asset retirement costs are depleted over the production life of the oil and natural gas property on a unit-of-production basis.
The ARO is recorded at fair value and accretion expense is recognized as the discounted liability is accreted to its expected settlement value. The fair value of the ARO liability is measured by using expected future cash outflows discounted at the Company’s credit adjusted risk free interest rate.
Amounts incurred to settle plugging and abandonment obligations that are either less than or greater than amounts accrued are recorded as a gain or loss in current operations. Revisions to previous estimates, such as the estimated cost to plug a well or the estimated future economic life of a well, may require adjustments to the ARO and are capitalized as part of the costs of proved oil and natural gas property.
The following table is a reconciliation of the ARO liability for continuing operations for the twelve months ended December 31 2009, 2008, and 2007:
| |
|
December 31:
|
|
| |
|
2009
|
|
|
2008
|
|
|
2007
(As Restated)
|
|
|
Asset retirement obligation at beginning of period
|
|
$ |
20,120 |
|
|
$ |
— |
|
|
$ |
— |
|
|
Liabilities incurred
|
|
|
628 |
|
|
|
18,551 |
|
|
|
— |
|
|
Revisions to previous estimates
|
|
|
12,706 |
|
|
|
— |
|
|
|
— |
|
|
Accretion expense
|
|
|
1,523 |
|
|
|
1,569 |
|
|
|
— |
|
|
Asset retirement obligation at end of period
|
|
$ |
34,977 |
|
|
$ |
20,120 |
|
|
$ |
— |
|
Income taxes
The Company accounts for income taxes in accordance with ASC 740 “Income Taxes” which requires an asset and liability approach for financial accounting and reporting of income taxes. Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws and regulations. Deferred tax assets include tax loss and credit carry forwards and are reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
On January 1, 2007, the Company adopted the FASB Interpretation on accounting for uncertainty in income taxes. The interpretation prescribes a measurement process for recording in the financial statements uncertain tax positions taken or expected to be taken in a tax return. Additionally, the interpretation provides guidance regarding uncertain tax positions relating to derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company will classify any interest and penalties associated with income taxes as interest expense.
Stock based compensation
Beginning January 1, 2006, the Company adopted the FASB standard for accounting for stock based compensation to account for its issuance of warrants to key partners, directors and officers. The standard requires all share-based payments, including employee stock options, warrants and restricted stock, be measured at the fair value of the award and expensed over the requisite service period (generally the vesting period). The fair value of common warrants granted to key partners, directors and officers is estimated at the date of grant using the Black-Scholes option pricing model by using the historical volatility of comparable public companies. The calculation also takes into account the common stock fair market value at the grant date, the exercise price, the expected life of the common stock option or warrant, the dividend yield and the risk-free interest rate.
The Company from time to time may issue stock options, warrants and restricted stock to acquire goods or services from third parties. Restricted stock, options or warrants issued are recorded on the basis of their fair value, which is measured as of the date issued. The options or warrants are valued using the Black-Scholes option pricing model on the basis of the market price of the underlying equity instrument on the “valuation date,” which for options and warrants related to contracts that have substantial disincentives to non-performance, is the date of the contract, and for all other contracts is the vesting date. Expense related to the options and warrants is recognized on a straight-line basis over the shorter of the period over which services are to be received or the vesting period.
The Company recognized stock-based compensation expense from warrants granted to directors and business partners for the twelve months ended December 31, 2009, 2008, and 2007 of $27,792, $342,730, and $109,000, respectively.
Earnings per share
Basic earnings per share are computed using the weighted average number of common shares outstanding. Diluted earnings per share reflect the potential dilutive effects of common stock equivalents such as options, warrants and convertible securities. Due to the Company incurring a net loss from continuing operations during the twelve months ended December 31, 2009, 2008and 2007 basic and diluted net loss per share are the same as all potentially dilutive common stock equivalents are anti-dilutive. The company excluded 2,420,000, 4,713,557, and 10,362,226 warrants from the calculation for the years ended December 31, 2009, 2008, and 2007 as the exercise prices were in excess of the average closing price of the Company’s common stock for those periods.
Note 3 – Oil and natural gas properties
Oil and natural gas properties are comprised as follows:
| |
|
|
|
| |
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
(As Restated)
|
|
|
Proved property – purchased wells
|
|
$ |
3,022,153 |
|
|
$ |
2,623,534 |
|
|
$ |
— |
|
|
Proved property – drilled wells
|
|
|
1,756,442 |
|
|
|
1,746,727 |
|
|
|
— |
|
|
Total oil and natural gas properties, cost
|
|
|
4,780,889 |
|
|
|
4,372,555 |
|
|
|
2,294 |
|
|
Less: accumulated depreciation , depletion and impairment
|
|
|
(3,969,920 |
) |
|
|
(3,336,207 |
) |
|
|
— |
|
|
Oil and natural gas properties, net
|
|
$ |
807,381 |
|
|
$ |
1,031,757 |
|
|
$ |
— |
|
Depletion expense for the years ended December 31, 2009, 2008, and 2007 was $290,344; $562,808, and none, respectively. During the years ended December 31, 2009, 2008, and 2007, the Company recorded impairment losses of $342,366, $2,775,696, and none, respectively.
Note 4 –Loans payable to related parties
Loans payable to related parties as of December 31, 2009, 2008 and 2007 are as follows.
| |
|
December 31:
|
|
| |
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Loans payable to former CEO and shareholder
|
|
$ |
404,623 |
|
|
$ |
1,636,536 |
|
|
$ |
1,377,882 |
|
|
Totals, loans payable to related parties
|
|
$ |
404,623 |
|
|
$ |
1,636,536 |
|
|
$ |
1,377,882 |
|
The loans payable are due on demand and do not bear interest.
Note 5 – Unsecured notes payable to related parties
Unsecured notes payable to related parties as of December 31, 2009, 2008 and 2007 are as follows.
| |
|
December 31:
|
|
| |
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Notes payable to a shareholder and director, unsecured, 10% interest payable at maturity, due on December 31, 2010
|
|
$ |
305,000 |
|
|
$ |
160,000 |
|
|
$ |
— |
|
|
Note payable to an affiliate of a shareholder and director, unsecured, 10% interest payable at maturity, due on December 31, 2010
|
|
|
50,000 |
|
|
|
223,673 |
|
|
$ |
— |
|
|
Totals, notes payable to related parties
|
|
$ |
355,000 |
|
|
$ |
383,673 |
|
|
$ |
— |
|
The notes payable to a shareholder and director matured on December 31, 2010. Under the terms of a notes payable extension agreement between the Company and the note holder, the notes and the accrued interest on the notes were extended on December 31, 2010, and converted into a Senior Secured Convertible debenture.
The note payable to an affiliate of a shareholder and director was extended by 90 days on December 31, 2010. The note and the accrued interest were paid on March 22, 2011.
Note 6 – Line of credit payable to Wells Fargo Bank
On October 7, 2008, the Company executed an unsecured Business Line of Credit Agreement with Wells Fargo Bank, National Association. The Credit Agreement provides the Company with a line of credit facility in the aggregate amount of $96,761. Interest on the loan is payable monthly, at the rate of 10.0% per annum. Payments of $2,055, including interest, are due on the line of credit and the line matures on October 13, 2013. The line of credit was personally guaranteed by the Company’s former CEO and shareholder.
During the year ended December 31, 2010, the Company defaulted on its monthly loan payments to Wells Fargo Bank and the loan was referred to the Bank’s workout department. The Company has negotiated an informal repayment program with the Bank’s workout department whereby the Bank will not institute collection actions provided the Company continues to make monthly principal payments of $2,200 monthly to the Bank. As of December 31, 2009, the Company was current on the terms of this line of credit.
| |
|
December 31:
|
|
| |
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Line of credit payable to Wells Fargo Bank, 10% interest payable at maturity, due on October 13, 2013
|
|
$ |
85,444 |
|
|
$ |
94,353 |
|
|
$ |
81,860 |
|
Note 7 – Separation Settlement Payable to former officer and shareholder
On May 15, 2009, the Company entered into a “Separation Agreement and General Release of Claims” with Jon Fullenkamp (“Fullenkamp”) and the Virgin Family Trust. The terms of the Agreement include (a) termination of an employment agreement between the Company and Fullenkamp; (b) payment of all accrued salaries, unreimbursed expenses, and shareholder advances previously made by Fullenkamp; (c) reduction of shareholder advances from estimated balance owed at the time of settlement of $1,665,375 to a balance of $500,000 (the “Separation Settlement”); (d) Payment terms of the Separation Settlement of $10,000 monthly commencing June 1, 2009, and payable over a fifty (50) month period, including imputed interest at the rate of 3.52% per annum; (e) cancellation of 2,000,000 shares of preferred stock, convertible at the rate of 100 shares of common, (d) lockup agreement with respect to all shares owned directly or indirectly by Fullenkamp for a period of five years, (e) Fullenkamp was to cooperate with the Company to recover misappropriated funds and agreed to bring litigation or induce others to bring litigation against the Company.
At the time of the agreement, Fullenkamp was owed the sum of approximately $1,665,375 in shareholder advances which were settled for $500,000, resulting in a gain on the settlement of this debt of $1,199,748. After the first payment of $10,000 the company recorded a discount of 3.25% on $490,000, the minimum federal rate in the amount of $34,373 against the note. The discount is amortized to interest expense over the period of estimated maturity. During the year ended December 31, 2009, the Company recorded interest expense of $8,997 and the note had an unamortized discount of $24,476. During the year ended December 31, 2009, the Company paid $51,004 of the principal of the Separation Settlement, reducing the outstanding balance as of December 31, 2009 to $404,623.
During the year ended December 31, 2009, Fullenkamp filed a lawsuit against the Company. The Company subsequently filed a lawsuit against Fullenkamp and others on January 19, 2010, in Midland County, Texas.
On March 24, 2011 the Company, James Capital Energy, LLC and other related parties entered into a comprehensive Settlement Agreement with Jon Fullenkamp. Under the Settlement Agreement, Victory agreed to i) dismiss Jon Fullenkamp from the Texas lawsuit with prejudice, ii) provide him with a general release from all acts related thereto, and iii) pay him $30,000 over 70 days. In turn, Jon Fullenkamp agreed to i) dismiss with prejudice the lawsuit he filed against the Company and others in California; ii) transfer to Victory 2,000,000 shares of Victory preferred stock; iii) transfer to Victory 400,000 warrants for Victory common stock; iv) transfer to James Capital Energy, LLC 16,144,563 shares of Victory common stock; v) voluntarily appear for his deposition to discuss events that occurred at the Adams-Baggett Ranch; vi) waive the claim he had to the $430,000 severance payment under the May 15, 2009 Separation Agreement; and vii) provide Victory James Capital Energy, LLC and other related parties with a general release
Note 8 – Liability for Unauthorized Preferred Stock Issued
During the year ended December 31, 2006, the Company authorized 10,000,000 shares of Preferred Stock, convertible to common stock at the rate of 100 shares of common for every share of preferred. During 2006, the Company issued 715, 517 of this preferred stock for cash of $246,950. The Company subsequently issued additional preferred stock and had several preferred shareholders convert their shares into common stock during the years ended December 31, 2009, 2008, and 2007.
During the course of the Company’s internal investigation, it was determined by the Company’s legal counsel that the preferred shares had not been duly authorized by the State of Nevada. Since the Company had issued and received consideration for the preferred stock, notwithstanding that the stock was not legally authorized, the Company reclassified the preferred stock into a liability. The Company has offered to settle the debt with the remaining holders of the unauthorized preferred stock by honoring the terms of conversion of one share of preferred into 100 shares of common stock.
The preferred stock liability as of the December 31, 2009, 2008, and 2007 is as follows:
| |
|
December 31,
|
|
| |
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Liability for unauthorized preferred stock
|
|
$ |
85,654 |
|
|
$ |
32,1591 |
|
|
$ |
217,614 |
|
Note 9 – Income Taxes
As a result of net operating losses and the inability to record a benefit for its deferred income tax assets, the Company has no income tax provision for the years ended December 31, 2009, 2008 and 2007.
The Internal Revenue Code of 1986, as amended, imposes substantial restrictions on the utilization of net operating losses in the event of an “ownership change” of a corporation. Accordingly, a company’s ability to use net operating losses may be limited as prescribed under Internal Revenue Code Section 382 (“IRC Section 382”). Events which may cause limitations in the amount of the net operating losses that the company may use in any one year include, but are not limited to, a cumulative ownership change of more than 50% over a three-year period. There have been transactions that have changed the Company’s ownership structure since inception that may have resulted in one or more ownership changes as defined by the Internal Revenue Code of 1986.
At December 31, 2009, 2008, and 2007, the Company had available Federal and state net operating loss and capital loss carry forwards to reduce future taxable income. The net operating loss carryovers available were approximately $2,373,000, $1,700,000, and $714,000 for federal and for state purposes, respectively. The Federal net operating loss carry forward begins to expire in 2025. Capital loss carryovers may only be used to offset capital gains. The capital loss carryover available was $50,900 for each of those years and will expire in 2010.
Given the Company’s history of net operating losses, management has determined that it is more-likely-than-not the Company will not be able to realize the tax benefit of the carry forwards. Current standards require that a valuation allowance be established when it is more likely than not that all or a portion of deferred tax assets will not be realized.
Accordingly, the Company has recorded a full valuation allowance against its net deferred tax assets at December 31, 2009, 2008 and 2007. Upon the attainment of taxable income by the Company, management will assess the likelihood of realizing the tax benefit associated with the use of the carry forwards and will recognize a deferred tax asset at that time. For the years ended December 31, 2009, 2008 and 2007, the valuation allowance increased / (decreased) by ($120,800), $1,651,300 and $3,505,974, respectively.
Significant components of the Company’s deferred income tax assets are as follows:
| |
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
Net operating and capital loss carry forwards
|
|
$ |
824,100 |
|
|
$ |
595,000 |
|
|
$ |
259,980 |
|
|
Property
|
|
|
159,000 |
|
|
|
152,400 |
|
|
|
— |
|
|
Accounts payable and accrued expenses
|
|
|
70,200 |
|
|
|
469,500 |
|
|
|
381,600 |
|
|
Malfeasance Loss
|
|
|
265,700 |
|
|
|
251,000 |
|
|
|
— |
|
|
Equity based compensation
|
|
|
4,125,900 |
|
|
|
4,089,000 |
|
|
|
3,264,600 |
|
|
AR and prepaid expenses
|
|
|
(8,300 |
) |
|
|
— |
|
|
|
— |
|
|
Valuation allowance
|
|
|
(5,436,600 |
) |
|
|
(5,557,400 |
) |
|
|
(3,757,200 |
) |
|
Net deferred income tax asset
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Reconciliation of the effective income tax rate to the U.S. statutory rate is as follows:
| |
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
Tax benefit at the U.S. statutory income tax
|
|
|
34.0 |
% |
|
|
34.0 |
% |
|
|
34.0 |
% |
|
State income tax net of federal benefit
|
|
|
0.0 |
% |
|
|
0.0 |
% |
|
|
0.0 |
% |
|
Permanent differences
|
|
|
(59.9 |
)% |
|
|
(19.6 |
)% |
|
|
0.0 |
% |
|
Change in valuation allowance
|
|
|
25.9 |
% |
|
|
(14.4 |
)% |
|
|
(34.0 |
)% |
|
Effective tax rate
|
|
|
0.0 |
% |
|
|
0.0 |
% |
|
|
0.0 |
% |
The Company adopted authoritative guidance in accordance with GAAP which addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under the current accounting guidelines, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. Current accounting guidelines also provide guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and require increased disclosures. At the date of adoption, and as December 31, 2009, 2008, and 2007 the Company does not have a liability for unrecognized tax benefits.
Note 10 – Stockholders’ Equity
For the year ended December 31, 2007:
Common stock
During 2007, the Company issued to third parties 29,542,066 shares of common stock with a weighted average fair value of $0.3282 per share, total value of $9,696,165 in exchange for services.
During 2007, the Company issued 8,500,000 shares of common stock to holders of 85,000 shares of the unauthorized preferred stock, at the stated conversion rate of 100:1.
Warrants
During 2007, the Company granted 600,000 warrants to purchase the Company’s common stock with an exercise price of $0.25 per share in connection with the consulting services rendered. These warrants expire in fifteen years from the date of grant. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $21,000.
During 2007, the Company granted 800,000 warrants to purchase the Company’s common stock with an exercise price of $0.25 per share in connection with the consulting services rendered. These warrants expire in ten years from the date of grant. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $88,000.
For the year ended December 31, 2008:
Common stock
During 2008, the Company issued to a third party 715,000 shares of common stock with a fair value of $0.0700 per share, total value of $50,050 in exchange for cash.
During 2008, the Company issued to a third party 200,000 shares of common stock with a fair value of $0.0500 per share, total value of $10,000 in exchange for cash.
During 2008, the Company issued to third parties 15,500,000 shares of common stock with a weighted average fair value of $0.1397 per share, total value of $2,067,223 in exchange for services.
During 2008, the Company issued 2,000,000 shares of common stock with a fair value of $0.1950 per share, total value of $390,000, to settle litigation with a third party.
During 2008, the Company issued to a third party 2,000,000 shares of common stock pursuant to his exercise of 2,000,000 warrants at an exercise price of $0.05 per share, total value of $100,000.
During 2008, the Company issued to a third party 1,000,000 shares of common stock pursuant to its exercise of 1,000,000 warrants at an exercise price of $0.25 per share, total value of $250,000.
During 2008, the Company issued 53,741,381 shares of common stock to holders of 537,414 shares of the unauthorized preferred stock, at the stated conversion rate of 100:1.
During 2008, the Company issued 19,767,863 shares of common stock with a fair value of $0.20 per share, total value of $3,953,573 as a 25% stock dividend to the shareholders of record as of May 1, 2008. Two (2) shares of common stock were subsequently retired.
Warrants
During 2008, the Company granted 3,293,557 warrants to purchase the Company’s common stock with an exercise price of $0.25 per share in connection with the consulting services rendered. These warrants expire in fifteen years from the date of grant. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $182,730.
During 2008, the Company granted 2,000,000 warrants to purchase the Company’s common stock with an exercise price of $0.05 per share in connection with the consulting services rendered. These warrants expire in five years from the date of grant. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $160,000.
For the year ended December 31, 2009:
Common stock
No common stock was issued, converted, or retired in 2009.
Warrants
During 2009, the Company granted 548,669 warrants to purchase the Company’s common stock with an exercise price of $0.25 per share in connection with the consulting services rendered. These warrants expire in fifteen years from the date of grant. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $3,162.
During 2009, the Company granted 5,100,000 warrants to purchase the Company’s common stock with an exercise price of $0.01 per share to the Company’s board of directors in connection with the services rendered. These warrants expire in five years from the date of grant. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $24,630.
Note 11 – Stock Warrants
At December 31, 2007, warrants shares outstanding were as follows:
| |
|
|
|
|
Weighted
Average
Exercise Price
|
|
|
Balance at January 1, 2007
|
|
|
1,020,000 |
|
|
$ |
0.31 |
|
|
Granted
|
|
|
1,400,000 |
|
|
$ |
0.25 |
|
|
Exercised
|
|
|
— |
|
|
|
— |
|
|
Cancelled
|
|
|
— |
|
|
|
— |
|
|
Balance at December 31, 2007
|
|
|
2,420,000 |
|
|
$ |
0.28 |
|
At December 31, 2008, warrants shares outstanding were as follows:
| |
|
|
|
|
Weighted
Average
Exercise Price
|
|
|
Balance at January 1, 2008
|
|
|
2,420,000 |
|
|
$ |
0.28 |
|
|
Granted
|
|
|
5,293,557 |
|
|
$ |
0.17 |
|
|
Exercised
|
|
|
(3,000,000 |
) |
|
$ |
(0.12 |
) |
|
Cancelled
|
|
|
— |
|
|
|
— |
|
|
Balance at December 31, 2008
|
|
|
4,713,557 |
|
|
$ |
0.26 |
|
At December 31, 2009, warrants shares outstanding were as follows:
| |
|
|
|
|
Weighted
Average
Exercise Price
|
|
|
Balance at January 1, 2009
|
|
|
4,713,557 |
|
|
$ |
0.26 |
|
|
Granted
|
|
|
5,648,669 |
|
|
$ |
0.03 |
|
|
Exercised
|
|
|
— |
|
|
|
— |
|
|
Cancelled
|
|
|
— |
|
|
|
— |
|
|
Balance at December 31, 2009
|
|
|
10,362,226 |
|
|
$ |
0.14 |
|
The following table summarizes information about stock warrants outstanding and exercisable as of December 31, 2007:
| |
|
|
|
|
|
|
|
Range of
Exercise
|
|
Number
of Shares
Underlying
Warrants
|
|
|
Weighted
Average
Exercise
Price
|
|
|
Weighted
Average
Remaining
Contractual
Life (in years)
|
|
|
|
|
|
Weighted
Average
Exercise
Price
|
|
|
$0.25 - $0.35
|
|
|
2,420,000 |
|
|
$ |
0.28 |
|
|
|
10.19 |
|
|
|
2,420,000 |
|
|
$ |
0.28 |
|
|
|
|
|
2,420,000 |
|
|
|
|
|
|
|
|
|
|
|
2,420,000 |
|
|
|
|
|
The following table summarizes information about stock warrants outstanding and exercisable as of December 31, 2008:
| |
|
|
|
|
|
|
|
Range of
Exercise
|
|
Number
of Shares
Underlying
Warrants
|
|
|
Weighted
Average
Exercise
Price
|
|
|
Weighted
Average
Remaining
Contractual
Life (in years)
|
|
|
|
|
|
Weighted
Average
Exercise
Price
|
|
|
$0.25 - $0.35
|
|
|
4,713,557 |
|
|
$ |
0.26 |
|
|
|
12.89 |
|
|
|
4,713,557 |
|
|
$ |
0.26 |
|
|
|
|
|
4,713,557 |
|
|
|
|
|
|
|
|
|
|
|
4,713,557 |
|
|
|
|
|
The following table summarizes information about stock warrants outstanding and exercisable as of December 31, 2009:
| |
|
|
|
|
|
|
|
Range of
Exercise
|
|
Number
of Shares
Underlying
Warrants
|
|
|
Weighted
Average
Exercise
Price
|
|
|
Weighted
Average
Remaining
Contractual
Life (in years)
|
|
|
|
|
|
Weighted
Average
Exercise
Price
|
|
|
$0.01 - $0.25
|
|
|
10,362,226 |
|
|
$ |
0.14 |
|
|
|
8.64 |
|
|
|
10,362,226 |
|
|
$ |
0.14 |
|
|
|
|
|
10,362,226 |
|
|
|
|
|
|
|
|
|
|
|
10,362,226 |
|
|
|
|
|
All future changes in the fair value of these warrants will be recognized currently in earnings until such time as the warrants are exercised or expire. These common stock purchase warrants do not trade in an active securities market, and as such, we estimate the fair value of these warrants using the Black-Scholes option pricing model using the following assumptions:
| |
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Risk free rate
|
|
|
1.67%-3.85 |
% |
|
|
2.25%-3.99 |
% |
|
|
4.11%-4.42 |
% |
|
Expected life
|
|
5 -15 years
|
|
|
10-15 years
|
|
|
10-15 years
|
|
|
Volatility
|
|
|
542.7%-585.4 |
% |
|
|
515.3%-539.4 |
% |
|
|
491.1%-497.1 |
% |
|
Dividend yield
|
|
|
0 |
% |
|
|
0 |
% |
|
|
0 |
% |
Expected volatility is based primarily on historical volatility. Historical volatility was computed using weekly pricing observations for recent periods that correspond to the remaining life of the warrants. We believe this method produces an estimate that is representative of our expectations of future volatility over the expected term of these warrants. We currently have no reason to believe future volatility over the expected remaining life of these warrants is likely to differ materially from historical volatility. The expected life is based on the remaining term of the warrants. The risk-free interest rate is based on U.S. Treasury securities.
At December 31, 2009, 2008, and 2007 the aggregate intrinsic value of the warrants outstanding and exercisable was zero.
Note 12 – Commitments and Contingencies
Leases
On June 15, 2008, the Company leased facilities located in Solana Beach, California under a lease that expires on June 15, 2010. The lease has a base monthly rent of $3,625.
Future minimum rental payments required under the non-cancelable operating leases described above as of December 31, 2009 are $21,750 for the year ended December 31, 2010.
Rent expense for the years ended December 31, 2009, 2008, and 2007, was $43,500, $21,750, and none, respectively.
Litigation
The Company has filed litigation to pursue acts of malfeasance against the Company, and it is subject to other cases that have arisen in the ordinary course of business, the majority of which have resulted from its thorough restructuring efforts. Many of these claims have been resolved. Management believes individually such litigation and claims will not have a material adverse impact on our financial position or our results of operations but these matters are subject to inherent uncertainties and management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position and the results of operations for the period in which the effect becomes reasonably estimable.
The following describes legal action being pursued by the Company and against the Company.
|
|
·
|
Victory Energy Corporation and James Capital Energy, LLC filed a lawsuit in Midland County, Texas, under Cause No. CV-47230, against Jim Dial, Jon Fullenkamp, Remuda Operating Company and other parties related to Jim Dial. The lawsuit alleges fraud, breach of fiduciary duty, and other claims that Victory and JCE allege against these parties. This lawsuit seeks to recover damages in excess of $10.0 million, plus punitive damages.
|
On December 9, 2010, the Superior Court for the State of Texas entered a final judgment against the following defendants: Jim Dial; 1st Texas Natural Gas Company, Inc.; Universal Energy Resources, Inc.; Grifco International, Inc.; and Precision Drilling & Exploration, Inc. The court held that each of these defendants knowingly and intentionally perpetuated a fraud on the plaintiffs. Additionally, the court found that each defendant breached their contract with the plaintiffs, breached their fiduciary duty to the plaintiffs, and committed acts in violation of the Texas Oil and Gas Proceeds Payment Act.
The final judgment awards Victory Energy Corporation and James Capital Energy, LLC, the plaintiffs, compensatory damages against five of the defendants in the amount of $5.6 million, jointly. The court also awarded punitive damages against each of these defendants in the amount of $2.2 million per defendant, for a total punitive damage award of $11.2 million. Additionally, the court awarded the plaintiffs pre-judgment interest and attorney fees.
On March 24, 2011 the Company, James Capital Energy, LLC and other related parties entered into a comprehensive Settlement Agreement with Jon Fullenkamp. Under the Settlement Agreement, Victory agreed to i) dismiss Jon Fullenkamp from the Texas lawsuit with prejudice, ii) provide him with a general release from all acts related thereto, and iii) pay him $30,000 over 70 days. In turn, Jon Fullenkamp agreed to i) dismiss with prejudice the lawsuit he filed against the Company and others in California; ii) transfer to Victory 2,000,000 shares of Victory preferred stock; iii) transfer to Victory 400,000 warrants for Victory common stock; iv) transfer to James Capital Energy, LLC 16,144,563 shares of Victory common stock; v) voluntarily appear for his deposition to discuss events that occurred at the Adams-Baggett Ranch; vi) waive the claim he had to the $430,000 severance payment under the May 15, 2009 Separation Agreement; and vii) provide Victory James Capital Energy, LLC and other related parties with a general release.
The Company will continue to pursue its claims against the remaining defendants, Remuda Operating Company, Ozona Natural Gas, LLC, Taylor Drilling and Ronnie Taylor.
|
|
·
|
The Company is an Intervener in a case pending in Crockett County, Texas under cause No. 08-04-07047-CV, and styled Oz Gas Corporation v Universal Energy Resources, Inc., et al, in which the plaintiff is seeking to establish ownership of the 155-2 well on the grounds that the well was illegally drilled on property belonging to the plaintiff. The Company intervened in this action to protect its interests in the 155-2 well and to recover its share of suspended money now being held in the court’s registry. On information and belief the court is holding funds in excess of $100,000.00 from the 155-2 well pending the outcome of this action.
|
|
|
·
|
On November 25, 2009, Jon Fullenkamp (“Fullenkamp”) filed a lawsuit in Orange County, California, against Victory, James Capital Energy, LLC, two of the Company’s directors, Bob Miranda and Ron Zamber, and other parties alleging fraud, breach of contract, libel, slander and other claims. After several attempts to amend the complaints were rejected by the Court, on February 17, 2011, the Court accepted the Fullenkamp complaint.
|
|
|
This matter, as well as the civil action filed in Midland County, Texas has been resolved through the comprehensive Settlement Agreement, as discussed herein.
|
|
|
·
|
On September 6, 2010, the Company and its operator, Cambrian Management, Ltd. (“Cambrian”), were named in a case pending in Midland, Texas under case No. 10-09-07213. The plaintiffs allege that the Company and Cambrian, along with other defendants, were trespassers on their land and drilled a well (#115-8) on land belonging to the plaintiffs. The plaintiffs claim trespass and unjust enrichment by certain defendants because of the drilling of the #115-8 well.
|
Discovery is ongoing on this matter and a trial has not been set at this time. Victory and Cambrian are in the process of completing some title work to decide which direction to go on this case. If the Company is not victorious in this case, it risks losing its investment in the well #115-8.
|
|
·
|
On March 18, 2011, the Company filed a lawsuit against its former independent auditor, John Kinross-Kennedy, CPA, for professional negligence in the audits of the company’s 2006 through 2007 financial statements, and the preparation of the 2008 quarterly forms 10Q. The lawsuit seeks compensatory damages, costs of suit, and other relief as may be deemed just and proper by the Court.
|
|
Note 13–
|
Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited)
|
The following disclosures provide unaudited information required by the FASB standard on oil and gas producing activities.
Results of operations from oil and natural gas producing activities
The Company’s oil and natural gas properties are located within the United States. The Company currently has no operations in foreign jurisdictions. Results of operations from oil and natural gas producing activities are summarized below for the years ended December 31:
| |
|
December 31:
|
|
| |
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Revenues
|
|
$ |
512,607 |
|
|
$ |
1,642,631 |
|
|
$ |
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating, production, and royalties
|
|
|
196,520 |
|
|
|
934,534 |
|
|
$ |
— |
|
|
Impairment of oil and natural gas reserves
|
|
|
342,366 |
|
|
|
2,775,696 |
|
|
$ |
— |
|
|
Accretion of asset retirement obligation
|
|
|
1,523 |
|
|
|
1,569 |
|
|
$ |
— |
|
|
Depletion, depreciation and amortization
|
|
|
290,344 |
|
|
|
562,808 |
|
|
$ |
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals, costs incurred
|
|
|
830,753 |
|
|
|
4,274,607 |
|
|
$ |
— |
|
| |
|
|
|
|
|
|
|
|
|
$ |
— |
|
|
Pre-tax income (loss) from producing activities
|
|
|
(318,146 |
) |
|
|
(2,631,976 |
) |
|
$ |
— |
|
|
Results of oil and natural gas producing activities (excluding overhead and interest costs)
|
|
$ |
(318,146 |
) |
|
$ |
(2,631,976 |
) |
|
$ |
— |
|
Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below for the years ended December 31, 2009, 2008, and 2007:
| |
|
December 31:
|
|
| |
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$ |
395,000 |
|
|
$ |
4,351,710 |
|
|
$ |
— |
|
|
Unproved
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
Exploration costs
|
|
|
289,430 |
|
|
|
4,911,182 |
|
|
|
|
|
|
Development costs
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
Asset retirement obligations
|
|
|
13,334 |
|
|
|
18,551 |
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals costs incurred
|
|
$ |
697,764 |
|
|
$ |
9,281,443 |
|
|
$ |
— |
|
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, 2009 and 2008, and the related discounted future net cash flows are based on estimates prepared by independent petroleum engineers. The reserves as of December 31, 2009 were derived from reserve estimates prepared by the independent reserve engineer; James Nicolson. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission. In 2009 the SEC issued guidance requiring oil and gas companies to calculate the value of proved reserves using prices that were calculated as the average price of the first day of the twelve months in the year. This guidance differed from the previous standard of valuing prices according to the end of year prices. The guidance does not require that prior year information be revised for the new method. As a result, this change in methods of pricing should be taken into account while reviewing the comparable information for 2009 and 2008 within this disclosure.
Standardized measure
The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved oil and natural gas reserves for the years ended December 31, 2009, 2008 and 2007 are shown below:
| |
|
December 31:
|
|
| |
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Natural gas:
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
| Proved developed and undeveloped reserves (mcf): |
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
824,460 |
|
|
|
— |
|
|
|
— |
|
|
Purchase of natural gas properties in place
|
|
|
59,249 |
|
|
|
634,973 |
|
|
|
— |
|
|
Discoveries and extensions
|
|
|
|
|
|
|
329,436 |
|
|
|
— |
|
|
Revisions
|
|
|
(28,540 |
) |
|
|
|
|
|
|
|
|
|
Production
|
|
|
(106,469 |
) |
|
|
(139,949 |
) |
|
|
— |
|
|
Proved reserves, at beginning of year
|
|
|
824,460 |
|
|
|
— |
|
|
|
— |
|
|
Proved reserves, at end of year
|
|
|
748,700 |
|
|
|
824,460 |
|
|
|
— |
|
| |
|
December 31:
|
|
| |
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Future cash inflows
|
|
$ |
3,601,210 |
|
|
$ |
4,130,550 |
|
|
$ |
— |
|
|
Future costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(360,120 |
) |
|
|
(413,150 |
) |
|
|
— |
|
|
Development
|
|
|
(1,666,490 |
) |
|
|
(1,839,010 |
) |
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash flows
|
|
|
1,574,600 |
|
|
|
1,878,390 |
|
|
|
— |
|
|
10% annual discount for estimated timing of cash flow
|
|
|
(757,480 |
) |
|
|
(846,750 |
) |
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted cash flow
|
|
$ |
817,120 |
|
|
$ |
1,031,640 |
|
|
$ |
— |
|
The rules promulgated by the SEC regarding the price used to calculate future net values changed whereby in 2008, the December 31, 2008 price was used and in 2009, the average price for the year was used. Product prices for gas respectively for 2009 and 2008 were $4.81//MMBTU and $5.01/MMBTU, respectively. In neither year was the Company allowed to value assets attributable to Proved Undeveloped or Probable Reserves because of the SEC guidelines requiring available capital to monetize the projects.
Future income taxes are based on year-end statutory rates, adjusted for tax basis of oil and natural gas properties and availability of applicable tax assets, such as net operating losses. A discount factor of 10% was used to reflect the timing of future net cash flows.
The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair value may also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and may require a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
Changes in standardized measure
Included within standardized measure are reserves purchased in place. The purchase of reserves in place includes undeveloped reserves which were acquired at minimal value that have been estimated by independent reserve engineers to be recoverable through existing wells utilizing equipment and operating methods available to the Company and that are expected to be developed in the near term based on an approved plan of development contingent on available capital.
Changes in the standardized measure of future net cash flows relating to proved oil and natural gas reserves for the years ended December 31 is summarized below:
| |
|
December 31:
|
|
| |
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Increase (decrease)
|
|
|
|
|
|
|
|
|
|
|
Sale of natural gas, net of natural gas operating expenses
|
|
$ |
(316,492 |
) |
|
$ |
(708,099 |
) |
|
$ |
— |
|
|
Purchase of natural gas properties in place
|
|
|
52,110 |
|
|
|
1,145,521 |
|
|
|
— |
|
|
Discoveries, extensions and improved recovery, net of future production and development costs
|
|
|
— |
|
|
|
594,318 |
|
|
|
— |
|
|
Accretion of discount
|
|
|
124,897 |
|
|
|
— |
|
|
|
— |
|
|
Net change in sales prices, net of production costs
|
|
|
(75,135 |
) |
|
|
— |
|
|
|
— |
|
|
Net increase (decrease)
|
|
|
(214,620 |
) |
|
|
1,031,740 |
|
|
|
— |
|
|
Standardized measure of discounted future cash flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10% annual discount for estimated timing of cash flow
|
|
|
1,031,740 |
|
|
|
— |
|
|
|
— |
|
|
Standardized measure of discounted cash flow
|
|
$ |
817,120 |
|
|
$ |
1,031,740 |
|
|
$ |
— |
|
Note 14 – Subsequent Events
Entry into a Partnership agreement with James Capital Energy, LLC and James Capital Consulting, LLC
On December 31, 2009, the Company entered into a Partnership Agreement with James Capital Consulting, LLC (“JCC”) and James Capital Energy, LLC (“JCE”), pursuant to which the Partners memorialized their agreement pursuant to which they formed and created a general partnership under the Texas Revised Partnership Act (the “Partnership”) on January 1, 2008. The initial purpose of the partnership is to acquire, own and dispose of oil, gas, and other mineral properties including permits, licenses, leases, and all other types of rights of every nature and character in connection therewith and incident thereto, and to explore, develop and operate such properties in accordance with such rights for the production of oil, gas and other minerals and, in connection therewith, to save, store, treat, transport and market oil, gas and other minerals and the products derived therefrom. Pursuant to the terms of the Agreement, the Company will serve as Managing Partner of the Partnership, and as such has full power and authority to transact the business of the Partnership. The name of the partnership was subsequently amended to become Aurora Energy Partners, A Texas General Partnership.
Judgment Award in Favor of the Company
On December 9, 2010, the District Court for the State of Texas, County of Midland, entered a Final Judgment As To Jim Dial, 1st Texas Natural Gas Company, Inc., Universal Energy Resources, Inc., Grifco International, Inc., and Precision Drilling & Exploration, Inc. (the “Final Judgment”) in the case of James Capital Energy, LLC (“JCE”) and Victory Energy Corporation (the “Company” and together with JCE, the “Plaintiffs”) vs. Jim Dial, 1st Texas Natural Gas Company, Inc., Universal Energy Resources, Inc., Jon Fullenkamp, Ozona Natural Gas Company, LLC, Remuda Operating Company, Grifco International, Inc., and Precision Drilling & Exploration, Inc.
The Final Judgment enters judgment against Defendants Jim Dial, 1st Texas Natural Gas Company, Inc., Universal Energy Resources, Inc., Grifco International, Inc., and Precision Drilling & Exploration, Inc., all of whom failed to file an answer or other responsive pleading to the litigation (the “Defaulting Defendants”). The Final Judgment awards Plaintiffs damages against the Defaulting Defendants in the total amount of $17,183,987. The damages are comprised of compensatory damages in the amount of $5,611,225 against the Defaulting Defendants jointly and severally, prejudgment interest of $225,218 and attorney fees in the amount of $125,094. The Court also awarded punitive damages against each Defaulting Defendant in the amount of $2,244,490, for a total punitive damage award of $11,222,450. The Final Judgment further imposes a constructive trust over all the funds and properties of the Defaulting Defendants owed to Plaintiffs.
The Court held that each of the Defaulting Defendants knowingly and intentionally perpetuated a fraud on the Plaintiffs. Additionally, the Court held that each of the Defaulting Defendants breached their contract with the Plaintiffs, breached their fiduciary duty to the Plaintiffs, and committed acts in violation of the Texas Oil and Gas Proceeds Payment Act.
Sale of 10% Senior Secured Convertible Debentures
Between October 15, 2010, and February 18, 2011, the Company entered into agreements with 20 accredited investors for the sale by the Company of an aggregate of $1,005,000 of 10% Senior Secured Convertible Debentures (the “Debentures”) which are convertible into an aggregate of 201,000,000 shares of the Company’s common stock at a conversion price of $0.005 per share of common stock, subject to adjustment. The maturity date of the Debentures is September 30, 2013, but may be extended at the sole discretion of the Company to December 31, 2013. The Debentures are immediately convertible by the holder into shares of the Company’s common stock at a conversion price of $0.005 per share, subject to customary adjustments for stock splits, stock dividends, recapitalizations and the like. The Company has the right to force conversion of the Debenture if, among other things, the closing sales price of the Company’s common stock is equal to or exceeds $0.025 for twenty (20) consecutive trading days. In connection with this offering, the Company also issued five (5) year warrants to purchase an aggregate of 1,005,000 shares of the Company’s common stock at an exercise price of $0.005 per share, subject to adjustment, to the investors.
The proceeds of $1,005,000 are allocated to working capital. The Debentures are secured under the terms of a Security Agreement by a security interest in all of the Company’s personal property.
Extension of Notes Payable to Related Party and Issuance of 10% Senior Secured Convertible Debenture
On December 31, 2010, Victory Energy Corporation (the “Company”) entered into a Loan Extension Agreement (the “Agreement”) with Visionary Investments, LLC (“Visionary”) to convert various unsecured promissory notes held by Visionary (the “Notes”) into a 10% Senior Secured Convertible Debenture (the “Debenture”). The sole member of Visionary is Ronald Zamber, a director and major stockholder of the Company.
The Notes have a total principal amount of $497,000 and have accumulated interest in the amount of $55,275. In consideration of the loan extension, the Notes and all accumulated interest were cancelled and the Company issued the Debenture to Visionary with a total face value of $552,275. The Debenture bears interest at the rate of 10% per year payable at maturity. The maturity date of the Debenture is September 30, 2013, but may be extended at the sole discretion of the Company to December 31, 2013. The Debenture is immediately convertible by the holder into shares of the Company’s common stock at a conversion price of $0.005 per share, subject to customary adjustments for stock splits, stock dividends, recapitalizations and the like. The Company has the right to force conversion of the Debenture if, among other things, the closing sales price of the Company’s common stock is equal to or exceeds $0.025 for twenty (20) consecutive trading days. The total number of shares of common stock issuable upon conversion of the Debenture is 110,455,000.
Investment in Option to Acquire Oil & Gas Mineral Interests
On December 31, 2010, the Company entered into an Option Agreement with Santiago Resources, LP, 1519 Partners, LP, Via Fortuna Minerals, LLC, Wesley G. Ritchie, and Barrier Island Minerals, LLC (collectively, the “Optionors”), whereby the Optionors granted the Company an option to acquire an oil and gas lease in a mineral interest owned by the Optionors in Padre Island, Texas.
The Option Agreement gives the Company the exclusive right to acquire an oil and gas lease in the Optionors’ mineral interest for a period of one (1) year from the effective date of the Option Agreement (the “Option Period”). During the Option Period, the Optionors may not enter into any oil and gas lease in the mineral interest which would otherwise prevent the Company from exercising its option under the Option Agreement. Pursuant to the terms of the Option Agreement, the Company will have full access to the land during the Option Period and may, among other things, conduct geophysical or seismic testing of the land to ascertain the potential gas reserves of the mineral interest. As consideration for the option, the Company has agreed to pay the Optionors the amount of Twenty-Five Thousand Dollars ($25,000.00).
Tom McCall is the president of Santiago Resources, LP. Tom McCall is also a partner in The McCall Firm; a Texas-based law firms (the “McCall Firm”). The McCall Firm serves as the Company’s legal counsel in the State of Texas and is currently prosecuting certain litigation on behalf of the Company. Dave McCall, Tom’s brother, is the president of 1519 Partners, LP. Dave McCall is also a partner in the McCall Firm. As previously reported, The McCall Firm serves as the Company’s legal counsel in the State of Texas.
Investment in Assignment of Working Interest in Oil Exploration Project in Jones County, Texas
On February 14, 2011, the Company, through its Aurora Energy Partners affiliate (“Aurora”), executed a Partial Assignment, Bill of Sale and Conveyance (the “Assignment”) with C.O. Energy assigning to Aurora Energy Partners a working interest in two oil and gas leases located in Jones County, Texas (the “Leases”). Pursuant to the Assignment, Aurora is entitled to a two and one-half percent (2½%) working interest in the Leases, including an interest in all production and all personal property located on the land covered by the Leases. The Assignment is effective February 1, 2011.
On February 14, 2011, Aurora and C.O. Energy also entered into a letter of intent whereby the parties anticipate C. O. Energy will convey to Aurora a one and one-half percent (1½%) working interest in a new oil and gas exploration project located in Jones County, Texas (the “Project”). In addition to this working interest in the Project, Aurora will have the option to purchase, accompanied with a right of first refusal, an interest in each prospect well developed on the Project by C. O. Energy. The letter of intent is non-binding and is contingent upon the parties reaching a definitive agreement.
Victory Energy Corporation (the “Company”) is the managing partner of Aurora and has a fifteen percent (15%) partnership interest in Aurora.
Settlement of Litigation
On March 24, 2011 the Company, James Capital Energy, LLC and other related parties entered into a comprehensive Settlement Agreement with Jon Fullenkamp. Under the Settlement Agreement, Victory agreed to i) dismiss Jon Fullenkamp from the Texas lawsuit with prejudice, ii) provide him with a general release from all acts related thereto, and iii) pay him $30,000 over 70 days. In turn, Jon Fullenkamp agreed to i) dismiss with prejudice the lawsuit he filed against the Company and others in California; ii) transfer to Victory 2,000,000 shares of Victory preferred stock; iii) transfer to Victory 400,000 warrants for Victory common stock; iv) transfer to James Capital Energy, LLC 16,144,563 shares of Victory common stock; v) voluntarily appear for his deposition to discuss events that occurred at the Adams-Baggett Ranch; vi) waive the claim he had to the $430,000 severance payment under the May 15, 2009 Separation Agreement; and vii) provide Victory James Capital Energy, LLC and other related parties with a general release.