UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K
(Mark One)
x ANNUAL REPORT UNDER SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
or
o TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File No. 0-27443
BAYOU CITY EXPLORATION, INC.
(Exact name of registrant as specified in its charter)
NEVADA | 61-1306702 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
632 Adams Street — Suite 700, Bowling Green, KY | 42101 | |
(Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code (270) 842-2421
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered |
Securities registered pursuant to section 12(g) of the Act:
Common Stock, $0.005 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 o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes o 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 past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files) Yes o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained in this form, 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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated Filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer o | Accelerated filer o |
Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company x |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2010, the last day of the registrant’s most recently completed second quarter, was $757,430.
As of March 30, 2011 the registrant had 29,003,633 shares of Common Stock, par value $0.005 per share, and 0 shares of Preferred Stock, par value $0.001 per share, subscribed or outstanding.
DOCUMENTS INCORPORATED BY REFERENCE None.
FORM 10-K | |||||
TABLE OF CONTENTS | |||||
PART I | |||||
ITEM 1 | Business | 1 | |||
ITEM 1A | Risk Factors | 4 | |||
ITEM 1B | Unresolved Staff Comments | 4 | |||
ITEM 2 | Properties | 4 | |||
ITEM 3 | Legal Proceedings | 7 | |||
ITEM 4 | (Removed and Reserved) | 7 | |||
PART II | |||||
ITEM 5 | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 8 | |||
ITEM 6 | Selected Financial Data | 9 | |||
ITEM 7 | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 9 | |||
ITEM 7A | Quantitative Disclosures About Market Risk | 12 | |||
ITEM 8 | Financial Statements and Supplementary Data | 12 | |||
ITEM 9 | Change in and Disagreements with Accountants on Accounting and Financial Disclosure | 12 | |||
ITEM 9A | Controls and Procedures | 12 | |||
ITEM 9B | Other Information | 13 | |||
PART III | |||||
ITEM 10 | Directors, Executive Officers and Corporate Governance | 14 | |||
ITEM 11 | Executive Compensation | 15 | |||
ITEM 12 | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 17 | |||
ITEM 13 | Certain Relationships and Related Transactions, and Director Independence | 18 | |||
ITEM 14 | Principal Accountant Fees and Services | 18 | |||
PART IV | |||||
ITEM 15 | Exhibits, Financial Statement Schedules | 19 | |||
SIGNATURES | 21 |
PART I
Development of the Company
Bayou City Exploration, Inc., (the “Company”), a Nevada corporation, was organized in November 1994, as Gem Source, Incorporated (“Gem Source”), and subsequently changed the Company’s name to Blue Ridge Energy, Inc. in June 1996. On June 8, 2005 the Company again changed its name to Bayou City Exploration, Inc.
In 2007, the Company announced that Robert D. Burr had been appointed President and Chief Executive Officer of the Company by the Board on an interim basis as of April 3, 2007, while the Company searched for new executive management. In January 2010, the Company announced the Board’s appointment of Stephen C. Larkin as the new Chief Financial Officer. The appointment ran through December 31, 2010 and will be extended automatically each year for twelve months unless terminated by either party within ninety days of the anniversary date. At a special meeting of the Board of Directors on July 6, 2010, Robert D. Burr tendered his resignation as President and Chief Executive Officer and from the Board of Directors, effective immediately. At the special meeting, the Board approved the appointment of Charles T. Bukowski Jr. to replace Mr. Burr as our new President and Chief Executive Officer, effective as of July 1, 2010. The initial term of this appointment was from July 1, 2010 to December 31, 2010 and it will automatically extend each year for twelve months thereafter unless terminated by either of the parties within ninety days of the anniversary date.
All of our periodic report filings with the Securities and Exchange Commission (“SEC”) pursuant to Section 13 or 15(d) of the Securities and Exchange Act of 1934, as amended, are available through the SEC web site located at www.sec.gov, including our annual reports on Form 10-K, quarterly reports on Form 10-QSB, current reports on Form 8-K and any amendments to those reports. The Company will also make available to any stockholder, without charge, copies of its Annual Report on Form 10-K as filed with the SEC and a copy of its Code of Ethics. For copies of this, or any other filings, please contact: Stephen C. Larkin at Bayou City Exploration, Inc., 632 Adams Street — Suite 700, Bowling Green, Kentucky 42101 or call (270) 842-2421.
Overview of Business
The Company is engaged in the oil and gas business primarily in the gulf coast of Texas, east Texas, south Texas, and Louisiana. During 2010, the Company changed its core business strategy. The Company’s primary business objective now focuses on the management of partnerships which are created to explore and develop reserves. In this new business plan, the Company will manage partnerships that purchase interests in exploratory wells as well as interests in producing oil and gas properties with undrilled reserves. This growth strategy is based on selling partnership interests to third party investors who will essentially assume the costs associated with the drilling of additional wells in exchange for interests in a partnership that holds a majority of the working interest derived from the wells they finance. The Company acts as the Managing General Partner for these partnerships and maintains a partnership interest or a working interest position outside of the partnership in each program for which we pay our proportionate share of the actual cost of drilling, testing, and completing the project and subsequent operating expenses to the extent that we retain a portion of the working interest. The Company believes this strategy will allow for a reduction of financial risk for the Company in drilling new wells, while still receiving income from present production in addition to income from any new successful new drilling.
When the Company undertakes a drilling project, a calculation is made to estimate the costs associated with drilling the well. The Company then forms and sells interest in a partnership that will acquire working interest in the well and undertake drilling operations. The Company typically enters into turnkey contracts with the partnerships it manages, pursuant to which we agree to undertake the drilling and completion of the partnerships’ well(s), for a fixed price, to a specific formation or depth. As such, each partnership essentially prepays a fixed amount for the drilling and completion of a specified number of wells which the Company records as revenue.
In addition to our current business strategy described above, the Company also owns certain oil and gas interests as of December 31, 2010 that have developed into revenue producing properties. The Company intends to use cash generated by these properties in addition to the revenues from our direct investment partnerships to cover its ongoing operational needs and restructuring of the balance sheet.
On July 17, 2009 the Company renewed a line of credit from Blue Ridge Group, Inc. (“Blue Ridge Group”) in the amount of $500,000 to finance the Company’s operations. As of December 31, 2010 the Company no longer has a liability balance under this line of credit arrangement. The line of credit was paid in full on March 1, 2010. During the 4th quarter, 2007, Peter Chen, a minority shareholder loaned the Company $100,000 to finance the Company’s operations. The Company executed a promissory note on October 4, 2007; the note is due on demand and bears an interest rate of 0%. The Company currently funds its operations through revenues it receives as the manager of several oil and gas partnerships it sponsors, profits from turnkey contracts associated with operations on those partnerships, and production payments it receives from its oil and gas holdings.
1
Competition, Markets and Regulations
Competition: The oil and gas industry is highly competitive in all its phases. The sale of interests in oil and gas projects, like those engaged in by the Company, is also very competitive. Major and independent oil and gas companies actively bid for desirable oil and gas prospects. Many of our competitors possess substantially greater financial resources, personnel, and budgets than the Company, which may affect its ability to compete, and many of these companies are substantially larger than the Company.
Markets: The price obtainable for oil and gas production from the Company’s properties and the partnerships it manages is affected by market factors beyond the control of the Company. Such factors include the extent of domestic production, the level of imports of foreign oil and gas, the general level of market demand on a regional, national and worldwide basis, domestic and foreign economic conditions that determine levels of industrial production, political events in foreign oil-producing regions, variations in governmental regulations and tax laws and the imposition of new governmental requirements upon the oil and gas industry. There can be no assurance that oil and gas prices will not decrease in the future, thereby decreasing net revenues from the Company’s properties. Changes in oil and gas prices can impact the Company’s determination of proved reserves and the Company’s calculation of the standardized measure of discounted future net cash flows relating to oil and gas reserves. In addition, demand for oil and gas in the United States and worldwide may affect the Company’s level of production. From time to time, a surplus of gas or oil supplies may exist, the effect of which may be to reduce the amount of hydrocarbons that the Company may produce and sell, while such an oversupply exists. In recent years, initial steps have been taken to provide additional gas pipelines from Canada to the United States. If additional Canadian gas is brought to the United States market, it could create downward pressure on United States gas prices.
Environmental Regulation
As the managing general partner of the Company’s drilling partnerships, the Company’s operations are subject to environmental protection regulations established by federal, state, and local agencies that may necessitate significant capital outlays that, in turn, would materially affect the financial position and business operations of the Company. These regulations, enacted to protect against waste, conserve natural resources and prevent pollution, could necessitate spending funds on environmental protection measures, rather than on drilling operations. Because these laws and regulations change frequently and are becoming increasingly more stringent, the costs to the Company of compliance with existing and future environmental regulations and the overall impact on the Company’s operations or financial condition cannot be predicted, but are likely to increase. Furthermore, if any penalties or prohibitions were imposed on the Company for violating such regulations, the Company’s operations could be adversely affected.
Partnerships managed by the Company currently hold interest in properties upon which such partnerships have or intend to explore for and produce oil and natural gas. Such properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, as well as state laws governing the management of oil and natural gas wastes. Under such laws, the Company and its managed partnerships could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination.
CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for the waste of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
Climate Change Legislation and Greenhouse Gas Regulation.
Studies in recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. Many nations have agreed to limit emissions of greenhouse gases (“GHGs”) pursuant to the United Nations Framework Convention on Climate Change, and the Kyoto Protocol. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of crude oil, natural gas, and refined petroleum products, are considered GHGs regulated by the Kyoto Protocol. Although the United States is currently not participating in the Kyoto Protocol, several states have adopted legislation and regulations to reduce emissions of GHGs. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect our operations and demand for crude oil and natural gas. On December 7, 2009, the Environmental Protection Agency (“EPA”) issued a finding that serves as the foundation under the Clean Air Act to issue rules that would result in federal GHGs regulations and emissions limits under the Clean Air Act, even without Congressional action. On September 29, 2009, the EPA also issued a GHG monitoring and reporting rule that requires certain parties, including participants in the oil and gas industry, to monitor and report their GHG emissions, including methane and carbon dioxide, to the EPA. The emissions will be published on a register to be made available on the Internet. These regulations may apply to the operations engaged in by our managed partnerships. The EPA has proposed two other rules that would regulate GHGs, one of which would regulate GHGs from stationary sources, and may affect the oil and gas exploration and production industry and the pipeline industry. The EPA’s finding, the GHG reporting rule, and the proposed rules to regulate the emissions of GHGs would result in federal regulation of carbon dioxide emissions and other GHGs, and may affect the outcome of other climate change lawsuits pending in United States federal courts in a manner unfavorable to the oil and gas industry.
2
Proposed Regulation.
Various legislative proposals are being considered in Congress and in the legislatures of various states, which, if enacted, may significantly and adversely affect the petroleum and gas industries. Such proposals involve, among other things, the imposition of price controls on all categories of natural gas production, the imposition of land use controls, such as prohibiting drilling activities on certain federal and state lands in protected areas, as well as other measures. At the present time, it is impossible to predict what proposals, if any, will actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals will have on the Company’s operations.
Federal Regulation of Natural Gas
The transportation and sale of natural gas in interstate commerce is heavily regulated by agencies of the federal government. The following discussion is intended only as a summary of the principal statutes, regulations and orders that may affect the production and sale of natural gas from the Company properties.
Federal Energy Regulatory Commission Orders
Several major regulatory changes have been implemented by the Federal Energy Regulatory Commission (“FERC”) from 1985 to the present that affect the economics of natural gas production, transportation and sales. In addition, the FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry that remain subject to the FERC’s jurisdiction. In April 1992, the FERC issued Order No. 636 pertaining to pipeline restructuring. This rule requires interstate pipelines to unbundle transportation and sales services by separately stating the price of each service and by providing customers only the particular service desired, without regard to the source for purchase of the gas. The rule also requires pipelines to (i) provide nondiscriminatory “no-notice” service allowing firm commitment shippers to receive delivery of gas on demand up to certain limits without penalties, (ii) establish a basis for release and reallocation of firm upstream pipeline capacity and (iii) provide non-discriminatory access to capacity by firm transportation shippers on a downstream pipeline. The rule requires interstate pipelines to use a straight fixed variable rate design. The rule imposes these same requirements upon storage facilities. FERC Order No. 500 affects the transportation and marketability of natural gas. Traditionally, natural gas has been sold by producers to pipeline companies, which then resell the gas to end-users. FERC Order No. 500 alters this market structure by requiring interstate pipelines that transport gas for others to provide transportation service to producers, distributors and all other shippers of natural gas on a nondiscriminatory, “first-come, first-served” basis (“open access transportation”), so that producers and other shippers can sell natural gas directly to end-users. FERC Order No. 500 contains additional provisions intended to promote greater competition in natural gas markets.
It is not anticipated that the marketability of and price obtainable for natural gas production from the Company’s properties will be significantly affected by FERC Order No. 500. Gas produced from the Company’s properties normally will be sold to intermediaries who have entered into transportation arrangements with pipeline companies. These intermediaries will accumulate gas purchased from a number of producers and sell the gas to end-users through open access pipeline transportation.
State Regulations
Production of any oil and gas from the Company’s property is affected by state regulations. States in which the Company operates have statutory provisions regulating the production and sale of oil and gas, including provisions regarding deliverability. Such statutes, and the regulations promulgated in connection therewith, are generally intended to prevent waste of oil and gas and to protect correlative rights to produce oil and gas between owners of a common reservoir. State regulatory authorities also regulate the amount of oil and gas produced by assigning allowable rates of production to each well or proration unit.
Operating Hazards and Insurance
General: The oil and gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures and discharges of toxic gases. The occurrence of any of these events could result in substantial losses to the Company due to severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The occurrence of a significant event it could materially and adversely affect our future revenues from any given prospect.
Recent Terrorist Activities and the Potential for Military and Other Actions: The continued threat of terrorism and the impact of retaliatory military and other action by the United States and its allies might lead to increased political, economic and financial market instability and volatility in prices for oil and natural gas, which could affect the market for our exploration and production operations. In addition, future acts of terrorism could be directed against companies operating in the United States, and it has been reported that terrorists might be targeting domestic energy facilities. While we believe that the risk to our energy assets is minimal, there is no assurance that we can completely secure our assets or completely protect them against a terrorist attack. These developments have subjected our operations to increased risks and, depending on their ultimate magnitude, could have a material adverse effect on our business. In particular, we might experience increased capital or operating costs to implement increased security for our energy assets.
3
Employees
The Company has two employees, Charles T. Bukowski, its President and Chief Executive Officer, and Stephen C. Larkin, its Chief Financial Officer, both of whom are employed by the Company full time.
ITEM 1A. RISK FACTORS
The Company is a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act, and as such, is not required to provide the information required under this Item.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
ITEM 2. PROPERTIES
Principal Office
The Company’s principal office is located at 632 Adams Street — Suite 700, Bowling Green, Kentucky 42101, in office space owned by Blue Ridge Group, which has common employees with the Company. At this time, the Company does not pay Blue Ridge Group for use of this space, and it is not subject to a formal rental agreement. In the event the Company is not able to continue to use its current office space, it is likely new space would be acquired on substantially different terms.
The Company also leases two office suites located in Allen, Texas from RMB Jupiter Office Park, Ltd. The leases for the office suites are each for one year terms, one which commenced on July 15, 2010 and the other on January 15, 2011. The Company pays base rent in the amount of $1,380 per month for each suite.
Disclosure of Reserves
Net Proved Oil and Gas Reserves
In January 2009, the SEC adopted new rules related to modernizing reserve calculation and disclosure requirements for oil and gas companies, which became effective prospectively for annual reporting periods ending on or after December 31, 2009. In addition to expanding the definition and disclosure requirements for crude oil and natural gas reserves, the new rule changes the requirements for determining quantities of crude oil and natural gas reserves. The new rule requires disclosure of crude oil and natural gas proved reserves by significant geographic area, using the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period, rather than end-of-period prices, and allows the use of reliable technologies to estimate proved crude oil and natural gas reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Reserve and related information for 2010 is presented consistent with the requirements of the new rule.
Presented below are the estimates of the Company’s proved oil and natural gas reserves as of December 31, 2010 based upon a report prepared by Pressler Petroleum Consultants, Inc. (“PPC”). All of the Company’s proved reserves are located in the United Sates.
Summary of Oil and Gas Reserves as of December 31, 2010
Future Net Revenue, $ | ||||
Reserve Category | Oil (Bbls*) | Gas (Mcf**) | Undiscounted | Present Worth at 10% |
Proved Developed Producing | 760 | 2,470 | $32,458 | $31,507 |
Proved Developed Non-Producing | 0 | 4,319 | 11,536 | 10,104 |
Total Net Proved Reserves | 760 | 6,789 | $43,994 | $41,611 |
________________________
*Bbls: Barrels of oil
**Mcf: Thousand cubic feet of gas
As specified by the SEC regulations, when calculating economic producibility, the base product price must be the 12-month average price, calculated as the un-weighted arithmetic average of the first-day-of-the-month price for each month within the prior 12-month period. The benchmark base prices used for this evaluation were $79.43 per barrel of oil for West Texas Intermediate oil at Cushing, Oklahoma, and $4.38 per Million British thermal units (MMBtu) for natural gas at Henry Hub, Louisiana. The oil and gas prices were adjusted on each well based on deductions such as quality, energy content, and basis differential, as appropriate. Prices for oil and natural gas were held constant throughout the remaining life of the properties.
4
Qualifications of Technical Persons and Internal Controls Over the Reserves Estimation Process
Reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. Future prices received for production may vary, perhaps significantly, from the prices assumed for the purposes of estimating the standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows should not be construed as the market value of the reserves at the dates shown. The 10% discount factor required to be used under the provisions of applicable accounting standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry. The standardized measure of discounted future net cash flows is materially affected by assumptions about the timing of future production, which may prove to be inaccurate.
The reserve estimates reported herein were prepared by independent engineers of Pressler Petroleum Consultants (PPC). The process performed by PPC engineers to prepare reserve amounts included their estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue, based in part on data provided by the Company. The estimates of reserves were determined by accepted industry methods. Methods utilized by PPC in preparing the estimates include extrapolation of historical production trends and analogy to similar producing properties. PPC believes the assumptions, data, methods and procedures utilized in preparing the estimates were appropriate for the purpose served by their report, and that it utilized all methods and procedures it considered necessary to prepare this report.
The Company’s internal control over the preparation of reserve estimates is a process designed to provide reasonable assurance regarding the reliability of the Company’s reserve estimates in accordance with SEC regulations. The preparation of reserve estimates are created by a third party consultant, PPC, and overseen by the Company’s President and Chief Executive Officer, Charles Bukowski. PPC performs evaluations based on accepted engineering standards. Reserves were determined by decline curve projection in the case of established production. For behind the pipe zones, reserves were calculated based on production and review of offset wells in the area and by reviewing calculated volumetric data. These specific reserve estimates were performed by Mr. Daniel L. Wilson, P.E., who has more than 35 years of related experience while working for various large and independent oil companies concentrating solely on estimating reserves. Charles Bukowski, who oversees the reserve estimates presented by PPC, has been working with oil companies for over 27 years, including both major oil companies (Mobil Oil Corp) and smaller independent oil companies. He is the sole person for the Company that reviews and approves the reserve estimates.
Proved Undeveloped Reserves.
At this time the Company has no undeveloped properties under lease.
Oil and Gas Production, Production Prices and Production Costs.
The following table summarizes the sales volumes of the Company’s net oil and gas production expressed in barrels of oil. Equivalent barrels of oil were obtained by converting gas to oil on the basis of their relative energy content — six thousand cubic feet of gas equals one barrel of oil. During 2010, 2009, and 2008 the average selling price for natural gas was $5.06, $4.44 and $9.11 per Mcf, respectively, and the average selling price for oil was $75.69, $58.47, and $99.65 per barrel, respectively.
Net Production For the Year 12/31/2010 | Net Production For the Year 12/31/2009 | Net Production For the Year 12/31/2008 | ||||||||||
Net Volumes (Equivalent Barrels) | 7,489.00 | 35,431.00 | 6,833.00 | |||||||||
Average Sales Price per Equivalent Barrel | $ | 33.79 | $ | 28.78 | $ | 42.12 | ||||||
Average Production Cost per Equivalent Barrel (includes production taxes) | $ | 6.79 | $ | 1.88 | $ | 3.12 |
The Average Production Cost per Equivalent Barrel represents the Lease Operating Expenses divided by the Net Volumes in equivalent barrels. Lease Operating Expenses include normal operating costs such as pumper fees, operator overhead, salt water disposal, repairs and maintenance, chemicals, equipment rentals, production taxes and ad valorem taxes.
Drilling and Other Exploratory and Development Activities.
A partnership managed by the Company drilled 1 exploratory well and the Company drilled 1 developmental well in year 2010. In 2009 the Company drilled 3 exploratory and 2 developmental wells. As of December 31, 2010 four of these wells are in production, one has not produced since October 2010, and the two other wells have been determined to be dry holes which have been plugged and abandoned. The Company did not drill any wells in 2008.
5
Present Activities.
Two partnerships managed by the Company drilled one well in 2011. Post drill analysis was favorable and the well is currently being completed as March 30, 2011.
Delivery Commitments.
The Company is not currently committed to providing a fixed and determinable quantity of oil or gas under any existing contract.
Oil and Gas Properties, Wells, Operations, and Acreage.
During 2010, the Company participated in the drilling of two new wells and one of those wells was determined to be a dry hole and has been plugged and abandoned.
As of December 31, 2010, the Company owned a direct working interest in four producing wells, being the Chapman #75-1, the Rooke B-1, the Garcitas #1, and the Rooke #2. All other wells in which the Company previously owned direct participation working interest have been abandoned and plugged with the exception of the Rooke #1, which stopped producing in October 2010 and has yet to be plugged.
The following tables summarize by geographic area the Company’s developed and undeveloped acreage and gross and net interests in producing oil and gas wells as of December 31, 2010. Productive wells are producing wells and wells capable of production. Wells that are dually completed in more than one producing horizon are counted as one well.
DEVELOPED AND UNDEVELOPED ACREAGE
Developed Acreage | Undeveloped Acreage | |||||||||||||||
Geographic Area: | Gross Acres | Net Acres | Gross Acres | Net Acres | ||||||||||||
Texas | 433.13 | 38.75 | -0- | -0- | ||||||||||||
Totals | 433.13 | 38.75 | -0- | -0- |
PRODUCTIVE WELLS
Gross Wells | Net Wells | |||||||||||||||
Geographic Area: | Oil | Gas | Oil | Gas | ||||||||||||
Texas | 2 | 2 | .19 | .18 | ||||||||||||
Totals | 2 | 2 | .19 | .18 |
Key Properties
The working interest owned by the Company, either directly or through the partnerships we manage, is owned jointly with other working interest partners. Management does not believe any of these burdens materially detract from the value of the properties or materially interfere with their use. The following are the primary properties held by the Company as of December 31, 2010.
Developed Properties:
Chapman No. 75-1: The Company owns an 8% working interest in 1 well located in Nueces County, Texas which began production in October 2009. The well produces about 350 Mcf per day.
Garcitas #1: The Company owns a 9.5% working interest in 1 well located in Jackson & Victoria County, Texas. The well began production in March 2010. The well produces about 20 Bbls per day.
Rooke B-1: The Company owns a 9.5% working interest in 1 well located in Refugio County, Texas which began production in February 2010. The well produces about 400 Mcf and 5 Bbls per day.
Rooke #2: The Company owns a 9.5% working interest in 1 well located in Refugio County, Texas which began production in May 2010. The well produces about 25 Bbls and 80 Mcf per day.
Dry Holes and Abandonment of Properties during 2010
In 2010 there was $37,430 in dry hole or abandonment expenses, which included a $2,000 refund of a prepaid expense previously recognized as a dry hole cost in 2009. In addition, the Rooke #1, which has not produced since October 2010, will have anticipated abandonment costs to be recognized in 2011.
6
Title to Properties
In the normal course of business, the operator of each lease has the responsibility of examining the title on behalf of all working interest partners. Titles to all significant producing properties of the Company have been examined by various attorneys. The properties are subject to royalty, overriding royalty and other interests customary in the industry.
The working interest owned by the Company, either directly or through the partnerships we manage, is owned jointly with other working interest partners or is subject to various royalty and overriding royalty interest, which generally range in total between 20%-30% on each property. Management does not believe any of these burdens materially detract from the value of the properties or materially interfere with their use.
ITEM 3. LEGAL PROCEEDINGS
There are no material pending legal or governmental proceedings relating to our Company or properties to which we are a party, and to our knowledge, there are no material proceedings to which any of our directors, executive officers, affiliates or shareholders are a party adverse to us or have a material interest adverse to us.
ITEM 4. (REMOVED AND RESERVED)
7
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
The Common Stock of the Company is quoted on the OTC Market Groups, Inc. OTCQB (the “OTCQB”) under the symbol “BYCX.” The following table shows the high and low bid information for our Common Stock for each quarter ended during the last two fiscal years. This information has been obtained from the OTC Bulletin Board. The quotations below reflect inter-dealer prices, without retail mark-up, mark-down or commission, and may not necessarily represent actual transactions.
High Bid | Low Bid | |||||||
March 31, 2009 | $ | 0.012 | $ | 0.012 | ||||
June 30, 2009 | 0.04 | 0.001 | ||||||
September 30, 2009 | 0.06 | 0.01 | ||||||
December 31, 2009 | 0.075 | 0.01 | ||||||
March 31, 2010 | $ | 0.13 | $ | 0.01 | ||||
June 30, 2010 | 0.06 | 0.01 | ||||||
September 30, 2010 | 0.065 | 0.02 | ||||||
December 31, 2010 | 0.03 | 0.00 |
Dividend Information
No cash dividends have been declared or paid on the Company’s Common Stock since the Company’s inception. The Company has not paid, nor does it intend to pay, cash dividends on its Common Stock in the foreseeable future. We intend to retain earnings, if any, for the future operation and development of our business. The Company’s dividend policy will be subject to any restrictions placed on it in connection with any debt offering or significant long-term borrowing.
Recent Sales of Unregistered Securities
In August 2010, the Company issued 2,350,000 shares of its common stock to a former officer and director upon exercise of stock options, resulting in cash proceeds to the Company of $23,500.
These securities were issued without registration under the Securities Act in reliance upon the exemptions provided in Section 4(2) or Section 3(a)(10) of the Securities Act. An appropriate legend, if necessary, was affixed to the share certificates issued in all of the above transactions effected in reliance upon Section 4(2). The Company believes that the recipient was an “accredited investor” within the meaning of Rule 501(a) of Regulation D under the Securities Act, or had such knowledge and experience in financial and business matters as to be able to evaluate the merits and risks of an investment in our common stock. The recipient had adequate access, through their relationships with the Company and its officers and directors, to information about the Company. The transaction described above did not involve general solicitation or advertising.
Shareholder Information
As of April 5, 2011, there were 549 shareholders of record of the Company’s Common Stock. The number of registered shareholders excludes any estimate by us of the number of beneficial owners of shares of Common Stock held in “street name.”
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Securities authorized for issuance under equity compensation plans
The following table sets forth certain information, as of December 31, 2010, concerning securities authorized for issuance under the Company’s 2005 Stock Option and Incentive Plan.
Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) | Weighted-average exercise price of outstanding options, warrants and rights (b) | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) | |||||||||
Equity compensation plans approved by security holders | 2,500,000 | $ | 0.02 | 2,150,000 | ||||||||
Equity compensation plans not approved by security holders | 0 | 0 | 0 | |||||||||
Total | 2,500,000 | $ | 0.02 | 2,150,000 |
ITEM 6. SELECTED FINANCIAL DATA
The Company is a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act, and as such, is not required to provide the information required under this Item.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in an understanding of the Company’s financial position and results of operations for each year of the two year periods ended December 31, 2010 and 2009. The financial statements and the notes thereto, which follow, contain detailed information that should be referred to in conjunction with the following discussion.
Financial Statements and Use of Estimates: In preparing financial statements, management is required to select appropriate accounting policies and make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Actual results could differ from those estimates.
Stock Options: Effective January 1, 2006, the Company accounts for stock options in accordance with revised Statement of Financial Accounting Standards (SFAS) No. 123, Share-Based Payment (SFAS 123(R) (ASC 718 and 505). Accordingly, stock compensation expense of $12,559 was required to be recognized in the year ended December 31, 2010 and stock compensation expense of $70,665 was required to be recognized in the year ended December 31, 2009.
Under SFAS 123(R) (ASC 718 and 505), the fair value of options is estimated at the date of grant using a Black-Scholes-Merton (“Black-Scholes”) option-pricing model, which requires the input of highly subjective assumptions including the expected stock price volatility. Volatility is determined using historical stock prices over a period consistent with the expected term of the option. The Company utilizes the guidelines of Staff Accounting Bulletin No. 107 (SAB 107) of the Securities and Exchange Commission relative to “plain vanilla” options in determining the expected term of option grants. SAB 107 permits the expected term of “plain vanilla” options to be calculated as the average of the option’s vesting term and contractual period. The Company has used this method in determining the expected term of all options. The Company has several awards that provide for graded vesting. The Company recognizes compensation cost for awards with graded vesting on a straight-line basis over the requisite service period for the entire award. The amount of compensation expense recognized at any date is at least equal to the portion of the grant date value of the award that is vested at that date.
Oil and Gas Activities: The accounting for upstream oil and gas activities (exploration and production) is subject to special accounting rules that are unique to the oil and gas business. There are two methods to account for oil and gas business activities, the successful efforts method and the full cost method. The Company has elected to use the successful efforts method. A description of our policies for oil and gas properties, impairment and direct expenses is located in Note 1 to our financial statements.
The successful efforts method reflects the volatility that is inherent in exploring for oil and gas resources in that costs of unsuccessful exploratory efforts are charged to expense as they are incurred. These costs primarily include seismic costs (G&G costs), other exploratory costs (carrying costs) and exploratory dry hole costs. Under the full cost method, these costs would be capitalized and then expensed (depreciated/amortized) over time.
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Oil and Gas Reserves: The term proved oil and gas reserves is defined by the SEC in Rule 4-10(a) (22) of Regulation S-X adopted under the Securities Act of 1933, as amended (the “Act”). In general, proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological or engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices based on an unweighted 12-month average and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.
Our estimates of proved reserves materially impact depletion expense. If proved reserves decline, then the rate at which we record depletion expense increases. A decline in estimates of proved reserves may result from lower prices, new information obtained from development drilling and production history; mechanical problems on our wells; and catastrophic events such as explosions, hurricanes and floods. Lower prices also may make it uneconomical to drill wells or produce from fields with high operating costs. In addition, a decline in proved reserves may impact our assessment of our oil and natural gas properties for impairment.
Our proved reserves estimates are a function of many assumptions, all of which could deviate materially from actual results. As such, reserves estimates may vary materially from the ultimate quantities of crude oil and natural gas actually produced.
Capitalized Prospect Costs: The Property and Equipment balance on the Company’s balance sheets, if any, include oil and gas property costs that are excluded from capitalized costs being amortized. These amounts represent investments in undeveloped leasehold acreage and work-in-progress exploratory wells. The Company excludes these costs on a property-by-property basis until proved reserves are found, until the lease term expires, or if it is determined that the costs are impaired. All costs excluded are reviewed annually to determine if any of these conditions have occurred; if so, the capitalized amount is transferred to abandonment expense and recorded to the statement of operations.
Impairments: In accordance with FASB ASC 360-10-35, long lived assets, such as oil and gas properties and equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount of the fair value less costs to sell and are no longer depreciated or depleted.
The application of this guidance did not result in any impairment of the oil and gas properties of the Company for the periods presented.
Results of Operations
The Company reported a net income of $532,395 in 2010, as compared to a net income of $783,073 in 2009. The decrease in the net income is primarily due to the fact that the Company had a large depletion, amortization, and depreciation expense for its producing wells when the reserve report came out for the year end 2010 due to a change in the estimates in calculating depreciation and depletion. The new estimate showed considerable decrease in total reserves. On a per share basis the Company had a net income of $0.02 per share in 2010 and a net income of $0.03 per share in 2009.
Operating Revenues: Operating revenues totaled $1,446,168, in 2010 as compared to $1,025,300 in 2009 which is a 41% increase from 2009. The increase is mainly the result of the sale of the Company’s interest in the Sien Gas Unit #1 (the “Sien #1 well”).
Direct Operating Costs: Direct operating costs for the producing oil and gas wells totaled $51,955 in 2010 compared to $99,596 in 2009. This decrease in expense is primarily due to the sale of the Sien #1 well and relief from related operating costs for the year.
Other Operating Expenses: Other operating expenses include abandonment and dry hole costs, marketing costs, depreciation, depletion and amortization expense. Other operating expenses increased by approximately 309% to $452,451 in 2010 compared to $110,693 in 2009. This increase of $341,758 was made up of an increase of $298,128 in depletion and amortization costs and $105,783 in marketing costs offset by a decrease of $62,153 in abandonment and dry hole costs.
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General And Administrative Costs: General and administrative costs were $421,907 in 2010 compared to $374,284 for 2009, an increase of $47,623, or an increase of 12.7%. The increase is due mainly to an increase resulting from the increases in executive salaries.
Other Income Net: Other income in excess of other expenses decreased by a net of $329,805 in 2010 from 2009. The change was due to forgiveness of debt, which was $167,344, and collection of $170,537 in bad debts in 2009. In 2010 the Company only recorded $2,064 for forgiveness of debt and $22,028 worth of miscellaneous income. In early 2009 the Company aggressively settled most of its accounts payable with companies it had not been able to pay for several years and was able to obtain forgiveness of $170,537 of the payables in exchange for immediate payment. The Company also aggressively pursued its outstanding accounts receivables and was able to collect a large amount of these as well in 2009.
Income Taxes: The Company had no federal or state income tax liability or benefit in 2010 or in 2009 as a result of a large net operating loss carry forward from years 2009 and prior. Based on the amount of net losses in 2009 and prior, a full valuation allowance has been recorded against the deferred tax assets associated with the net operating loss carry forwards. The Company has an estimated net operating loss carry forward of $8,334,000 and $8,834,000 as of December 31, 2010 and 2009 respectively. Under Internal Revenue Code (IRC) Section 382, a change in ownership occurred on December 31, 2004 with the issue of the additional shares in a private placement transaction. This rule will limit the net operating loss carry forward amount to $267,000 per year. These net operating losses begin expiring in 2019 if not utilized.
Assets: The Company’s total assets increased $105,574 from $526,617 as of December 31, 2009 to $632,191 as of December 31, 2010. Property costs decreased $194,122 primarily due to a large increase in depreciation and depletion. The Company’s main reason for the increase was from current assets increasing $299,696 from $217,650 as of December 31, 2009 to $517,346 as of December 31, 2010 resulting from the cash sale of the Sien #1 well for $1,000,000.
Liabilities: The Company’s liabilities decreased to $272,097 as of December 31, 2010 compared to $742,977 as of December 31, 2009. The Company reduced its accounts payable and accrued expenses by $45,881, reduced its accounts payable to related parties by $50,000, and reduced its notes payable to related parties by $375,000. During 2010, the entire reduction in notes payable to related parties were related to the amounts owed to Blue Ridge Group, Inc. which were paid in full in 2010.
The Company’s liabilities as of December 31, 2010 included $172,097 in trade payables and accrued expenses of which $84,906 in trade payables and accrued expenses and $100,000 in notes payable were due to related parties.
Stockholders’ Equity: Total stockholder’s equity of the Company increased $576,454 to a surplus of $360,094 at December 31, 2010. This increase is mainly the result of the 2010 net operating profit of $532,395.
Liquidity and Capital Resources
The Company’s current ratio (current assets / current liabilities) was 2.01 to 1 as of December 31, 2010 compared to .29 to 1 as of December 31, 2009. The change in the current ratio from 2009 to 2010 is the result a significant decrease in current liabilities due to the Company paying off a large portion in accounts payable with the cash flow from sale of the Sien #1 well as well as revenues from the producing wells.
The Company’s sources of cash during 2010 were primarily from the $1,000,000 in the cash sale of the Sien #1 well and $260,127 from oil and gas revenue. The Company’s sources of cash during 2009 were $1,025,000 from oil and gas revenue associated with its interests in the oil and gas wells.
During 2010 the Company relied primarily upon the proceeds from the sale of the Sien #1 well and in 2009 the Company relied primarily upon the revenues from the sale of oil and gas production from its well interests to fund its operations. Management intends to fund further growth with the sale of interests in partnerships for which the Company serves (or will serve) as the Managing General Partner. Each of the managed partnerships are expected to enter into turnkey contracts with the Company for drilling operations. The Company believes that revenue from the turnkey contracts will be sufficient to fund their ongoing business; however, based on previous years’ expenses, the Company’s current cash resources will not be enough to fund their operations for the next 12 months unless new partnerships are formed during 2011 to undertake future drilling operations.
As of December 31, 2010 the Company has no contractual obligations that will encumber their cash flow into the future.
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Off Balance Sheet Arrangements
The Company does not participate in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structure finance or special purpose entities (SPEs), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As of December 31, 2010 and 2009, the Company was not involved in any unconsolidated SPE transactions or any other off-balance sheet arrangements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act, and as such, is not required to provide the information required under this Item.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The response to this item is set forth herein in a separate section of this Report, beginning on Page F-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act) as of the end of the period covered by this report (the “Evaluation Date”). Based on such evaluation, our management, including our CEO and CFO, concluded that our disclosure controls and procedures were effective, at a reasonable assurance level, as of the Evaluation Date, to ensure that information required to be disclosed in reports that we file or submit under that Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our CEO and CFO, in a manner that allows timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control Over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined rule 13a-15(f) of the Exchange Act. The Company’s internal control system is designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. The Company's internal control over financial reporting includes those policies and procedures that:
· | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; |
· | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and |
· | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. |
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
An evaluation was performed under the supervision and with the participation of the Company’s management, including the CEO and CFO, of the effectiveness of the design and operation of the Company’s procedures and internal control over financial reporting as of December 31, 2010. In making this assessment, the Company used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on that evaluation, the Company’s management, including the CEO and CFO, concluded that the Company’s internal controls over financial reporting were effective and there were no materials weaknesses as of December 31, 2010.
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Attestation Report of the Registered Public Accounting Firm
This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by the Company’s registered public accounting firm pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act, wherein non-accelerated filers are exempt from Sarbanes-Oxley internal control audit requirements.
Changes in Internal Controls over Financial Reporting
There were no changes in our internal control over financial reporting, that occurred during the year ended December 31, 2010, that has materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Inherent Limitations of Internal Controls
There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention and overriding of controls and procedures. A control system, no matter how well conceived and operated, can only provide reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of the control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur due to human error or mistake. Additionally, controls, no matter how well designed, could be circumvented by the individual acts of specific persons within the organization. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated objectives under all potential future conditions.
Management is aware that there is a lack of segregation of duties at the Company due to the small number of employees dealing with general administrative and financial matters. This constitutes a deficiency in the internal controls. Management has decided that considering the employees involved, the control procedures in place, and the outsourcing of certain financial functions, the risks associated with such lack of segregation were low and the potential benefits of adding additional employees to clearly segregate duties did not justify the expenses associated with such increases. Management periodically reevaluates this situation. In light of the Company’s current cash flow situation, the Company does not intend to increase staffing to mitigate the current lack of segregation of duties within the general administrative and financial functions.
ITEM 9B. OTHER INFORMATION
None.
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PART III
Directors and Executive Officers
The following individuals currently serve as directors and/or executive officers of our Company. All directors of the Company hold office until the next annual meeting of shareholders or until their successors have been elected and qualified. The executive officers of our Company are appointed by our Board of Directors and hold office until their death, resignation or removal from office.
Director | Age | Company Position or Office | Director Since | |||||||
Charles T. Bukowski | 50 | Director, President and CEO | 2010 | |||||||
Stephen C. Larkin | 51 | Director and CFO | 2009 | |||||||
Travis Creed | 44 | Chairman | 2010 |
CHARLES T. BUKOWSKI, JR, age 50, was appointed Director of the Company as well as our President and Chief Executive Officer in July 2010. Mr. Bukowski graduated from Texas A&M University with a Bachelor’s degree in 1982 and a Master’s degree in 1984 (4.0 GPA), both in geology. The next 12 years he was employed as a geologist with Mobil Oil working a variety of both exploration and production assignments including South Texas, East Texas, Oklahoma, South Louisiana, and Mississippi. While at Mobil he generated and drilled over 100 wells, including the first horizontal well in Lavaca County. Mr. Bukowski was the first geologist at Mobil in Houston to do both the geological and 3D seismic interpretations for his projects.
In 1996, Mr. Bukowski joined Edge Petroleum where he utilized 3D seismic, advanced AVO processing and advanced interpretation software to lead a team that drilled 23 successful wells. He co-authored the first published successful use of AVO in South Texas and the resulting paper won several industry awards including SEG’s Best Paper Award in 2001. While at Edge he interpreted over 800 sq. miles of 3D seismic data, mostly in South Texas and South Louisiana.
In 2000, Mr. Bukowski joined Alta Resources as Exploration Manager. While at Alta he drilled numerous successful wells and was involved in making five new field discoveries. Mr. Bukowski left Alta in 2007 to start and become President of Beachcomber Oil and Gas Inc. where he generated exploration projects including a 63 square mile 3D program in Kansas. He consulted for industry partners interpreting their 3D seismic datasets, and evaluated third party prospects, and assisted in calculating reserve estimates.
STEPHEN C. LARKIN, age 51, serves as a director and the Chief Financial Officer of the Company. Since November 22, 2010, Mr. Larkin also currently serves as a director and the President of Blue Ridge Group, Inc., and served as its Chief Financial Officer prior to his appointment as its President. Prior to joining the Company from August 1998 until June 2008, Mr. Larkin spent 10 years as President and CEO of Sensus Precision Die Casting, Inc. and President, CEO and Chairman of the Board Sensus Rongtai (Yangzhou) Precision Die Casting, Ltd. (a Chinese subsidiary of Sensus Precision Die Casting, Inc.) and managed all aspects of the company. Mr. Larkin spent a total of 21 years with Sensus Metering Systems, Inc. (parent company to Sensus Precision Die Casting, Inc.) in positions ranging from Controller and CFO of one of their divisions (for seven years), to Vice President of Operations (for four years) then finally with Sensus Precision Die Casting Company as their President and CEO. Prior to that Mr. Larkin spent almost six years with Ernst and Young CPA’s both in the Lansing Michigan office and the Tampa Florida office and held the position of Senior Manager-Auditing when he left. Mr. Larkin earned a B.A. Degree from Michigan State University in Accounting in 1981, an MBA Degree from Michigan State University in Operations Management in 1989 and an Executive MBA from the University of New Hampshire in International Business in 1997. Mr. Larkin also passed the CPA exam in May 1982 and was granted a CPA license in May 1982 in the State of Florida.
TRAVIS N. CREED, age 44, was appointed director in July 2010, and is a licensed attorney. Mr. Creed also serves as Senior Vice President - Real Property Division and General Counsel for Blue Ridge Group, Inc. Mr. Creed holds degrees from Westminster College and the University of Arkansas School of Law. In addition to the practice of law, Mr. Creed has owned an electrical contracting company, a mortgage trading company and a real estate development company. He has experience in banking including founding and serving as President of Pinnacle Resources, a wholly owned subsidiary of Pinnacle Bank in Little Rock, Arkansas. Mr. Creed currently serves as Senior VP and General Counsel for Blue Ridge Group, Inc. in Bowling Green, Kentucky.
Family Relationships
There are no family relationships between any of our directors and executive officers.
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Involvement In Certain Legal Proceedings
During the past ten years, none of the Company's officers or directors were involved in any legal proceedings that are material to an evaluation of the ability or integrity of such directors and officers.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires the Company’s officers and directors and persons who own more than 10% of a registered class of the Company’s equity securities to file reports of ownership and changes in ownership with the Securities and Exchange Commission (“SEC”). Officers, directors and greater than 10% stockholders are required by SEC regulation to furnish the Company with copies of all Section 16(a) forms filed by them. Based solely on our review of the copies of such forms received by us with respect to fiscal year 2010, or written representations from certain reporting persons, we believe all of our officers and directors and persons who own more than 10% of our Common Stock have met all applicable filing requirements, except as described in this paragraph. Stephen Larkin, who was appointed to serve as our Chief Financial Officer on June 30, 2009, filed his Form 3 late on July 12, 2010. Charles T. Bukowski, Jr., our President, Chief Executive Officer and director, filed a late Form 4 on August 16, 2010 reporting one transaction that should have been reported earlier. Robert D. Burr, our former President, Chief Executive Officer and director, filed a late Form 4 on July 21, 2010 reporting four transactions that should have been reported earlier. Harry J. Peters, a former director, filed a late Form 4 on July 21, 2010 reporting several transactions that should have been reported earlier. Gregory B. Shea, a former director, filed a late Form 4 on July 21, 2010 reporting several transactions that should have been reported earlier. Blue Ridge Group, Inc., a former stockholder that held in excess of 10% of the Company’s common stock, filed its Form 3 late on August 24, 2010 and a late Form 4 on August 25, 2010 reporting four transactions that should have been reported earlier.
Code of Ethics for Financial Executives
On April 14, 2011, the Company's Board of Directors approved a Code of Ethics. A form of the Code of Ethics is attached as Exhibit 14.1 to this report. The Company will provide a copy of this policy free of charge upon written request to Stephen C. Larkin at Bayou City Exploration, Inc., 632 Adams Street — Suite 700, Bowling Green, Kentucky 4210.
Board Committees and Financial Expert
The Company does not currently maintain separate audit, nominating or compensation committees. When necessary, the entire Board of Directors performs the tasks that would be required of those committees. Furthermore, we do not have a qualified financial expert serving on the Board of Directors at this time, because we have not been able to hire a qualified candidate and we have inadequate financial resources at this time to hire such an expert.
Summary Compensation Table
The below table lists the compensation of the Company's principal executive officers who served the Company in such capacities during the fiscal year ended December 31, 2010.
SUMMARY COMPENSATION TABLE
Name and Principal Position | Year | Salary ($) | Option Awards ($) | Total ($) | ||||||||||
Robert D. Burr, | 2010 | 45,000 | — | $ | 45,000 | |||||||||
President and CEO(1) | 2009 | 67,500 | 32,804 | $ | 100,304 | |||||||||
Charles T. Bukowski, | 2010 | 60,000 | 3,071 | $ | 72,559 | |||||||||
President and CEO(2) | 2009 | — | — | $ | — | |||||||||
Stephen C. Larkin, | 2010 | 60,000 | 4,740 | $ | 60,000 | |||||||||
Chief Financial Officer | 2009 | 22,500 | 7,418 | $ | 34,084 |
______________________
(1) | Mr. Burr resigned as President and CEO effective July 1, 2010. |
(2) | Mr. Bukowski was appointed to replace Robert D. Burr as President and CEO of the Company effective July 1, 2010. |
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Narrative Disclosure to Summary Compensation Table
Until his resignation in July 2010, Robert Burr received a base salary of $90,000. Charles Bukowski, our current President and CEO, receives a base salary of $120,000, which he began receiving in July 2010. Our Chief Financial Officer, Stephen Larkin, currently receives a base salary of $90,000 per year. This was increased on July 1, 2010 from a previous salary of $30,000 per year. As part of the Company’s compensation package, its officers are from time to time awarded stock options. In 2009, Mr. Burr and Mr. Larkin received stock options as part of a decision on the part of the Board to cancel outstanding stock options that were substantially “out of the money” and issue new stock options on terms more in line with the Company’s stock price at that time. The Board uses the stock options as an incentive to its officers and believes this practice to be comparable to other public companies. In May of 2009, the Board awarded Mr. Burr an option to purchase 2,350,000 shares of common stock at an exercise price of $0.01 per share. In May 2009, Mr. Larkin was also awarded an option to purchase 1,000,000 shares of common stock at an exercise price of $0.01 per share. Mr. Burr’s options vested immediately, whereas Mr. Larkin’s vested over a two year period. All stock option awards were issued pursuant to the Company’s 2005 Stock Option and Incentive Plan. In 2010, Mr. Bukowski was awarded 500,000 stock options in connection with his appointment as the Company’s President and Chief Executive Officer. Mr. Bukowski’s options vest over a two-year period and have a $0.05 exercise price. Each of our named executive officers’ stock option awards have a ten year term, beginning on the award date.
There were no employment agreements in place as of December 31, 2010.
Stock Option Plan
On February 22, 2005, the Board of Directors approved the Bayou City Exploration, Inc. (formerly Blue Ridge Energy, Inc.) 2005 Stock Option and Incentive Plan (the “Stock Option Plan”). The Stock Option Plan allows for the granting of stock options to eligible directors, officers, employees, consultants and advisors.
Effective January 1, 2006, the Company accounts for the Plan in accordance with revised Statement of Financial Accounting Standards (SFAS) No. 123, Share-Based Payment (SFAS 123(R). Accordingly, stock compensation expense has been recognized in the statement of operations based on the grant date fair value of the options for the period ended December 31, 2010. Prior to January 1, 2006, the Company accounted for stock compensation cost under the Plan in accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, (APB 25) as permitted by SFAS 123 as originally issued. Under APB 25, stock compensation expense was recognized only if the options had intrinsic value (difference between option exercise price and the fair market value of the underlying stock) at the date of grant. As the Company issued all options with an exercise price equal to the grant date market value of the underlying stock, no compensation expense had previously been recorded by the Company.
The maximum number of shares with respect to which options may be awarded under the Stock Option Plan is seven million (7,000,000) common shares of which approximately 2,150,000 shares remain available for grant as of December 31, 2010. The following table shows more information about our Stock Option Plan.
Outstanding Equity Awards
The following table shows information regarding awards granted to each of our named executive officers and directors under our Stock Option Plan outstanding as of December 31, 2010.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
OPTION AWARDS
Name | 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 Exercise Date | |||||||||||||
Charles T. Bukowski, President and CEO | 166,667 | 333,333 | — | $ | 0.05 | 07/01/20 | ||||||||||||
Stephen C. Larkin, Director and CFO | 666,667 | 333,333 | — | $ | 0.01 | 05/18/19 | ||||||||||||
Travis N. Creed, Chairman | 333,333 | 166,667 | — | $ | 0.01 | 07/01/20 |
Director Compensation
During 2010, the directors of the Company were not compensated for their services as directors of the Company.
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ITEM 12. | SECURITIES OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
The following table sets forth the ownership, as of March 28, 2011, of our Common Stock by each person known by us to be the beneficial owner of more than 5% of our outstanding Common Stock, each of our directors and executive officers; and all of our directors and executive officers as a group. The information presented below regarding beneficial ownership of our Common Stock has been presented in accordance with the rules of the SEC and is not necessarily indicative of ownership for any other purpose. This table is based upon information derived from our stock records. Unless otherwise indicated in the footnotes to this table and subject to community property laws where applicable, we believe that each of the shareholders named in this table has sole voting and investment power with respect to the shares indicated as beneficially owned. Except as otherwise listed below, the address of each person is c/o Bayou City Exploration, Inc., 632 Adams Street — Suite 700, Bowling Green, Kentucky 42101. Except as set forth below, applicable percentages are based upon 29,003,633 shares of Common Stock outstanding as of March 28, 2011.
Name of | Amount and Nature of | Percent | ||||||
Beneficial Owner | Beneficial Ownership (4) | of Class | ||||||
Charles T. Bukowski (1) | 189,167 | 0.6 | % | |||||
Stephen C. Larkin (2) | 1,062,844 | 3.5 | % | |||||
Travis N. Creed (3) | 500,000 | 1.7 | % | |||||
All directors, nominees and officers as a group (3 persons) | 1,752,011 | 5.8 | % |
_____________________
(1) Mr. Bukowski’s beneficial ownership interest includes vested options for the purchase of 166,667 shares plus 22,500 shares in his personal portfolio.
(2) Mr. Larkin’s beneficial ownership interest includes vested options for the purchase of 1,000,000 shares plus 62,844 shares in his personal portfolio.
(3) Mr. Creed’s beneficial ownership interest includes vested options for the purchase of 500,000 shares.
(4) These beneficial ownerships represent vested options and options exercisable within 60 days of April 5, 2011.
17
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Related Party Transactions
The Company has an unwritten agreement with Blue Ridge Group pursuant to which it pays a quarterly management fee in the amount of $11,018. This fee is based on the time and salaries of Blue Ridge Group’s employees for work performed for the Company. The Company and Blue Ridge Group share common management as well as office space. The Company’s Chief Financial Officer and director, Stephen Larkin, serves as President and Chief Executive Officer of Blue Ridge Group. Travis Creed, who is also a director of the Company, is Senior Vice President – Real Property Division and General Counsel of Blue Ridge Group.
In January and March of 2010, the Company entered into five Purchase of Interest Agreements to sell its interest in the Sien Gas Unit #1 (referred to as the Sien #1 well herein), located in Aransas County, Texas, for total proceeds of $1,000,000. Each of the purchasers of the Company’s interest was, at the time of purchase, a related party. Blue Ridge Group was the managing partner of two of the purchasing partnership entities – the 2009 Production and Drilling Program, L.P. and the 2009/2010 Production and Drilling Program, L.P. The other three purchasing entities, the Argyle Energy 2009-VI Year End Production Program, L.P. and the AE 2009/2010-VI Year End Production Program, L.P., which are managed by Argyle Energy, Inc., and Burrite, Inc., are controlled by Robert Burr. At the time of the sales, Mr. Burr was President of Blue Ridge Group, Argyle Energy, Inc. and Burrite, Inc as well as President, Chief Executive Officer and a director of the Company. In light of the material relationship between the Company and each of the purchasers, the Board of Directors required a third party appraisal of the Company’s interest in the Sien #1 well, which appraised the interest at $1,000,000.
Director Independence
Our securities are not currently listed on a national securities exchange or interdealer quotation system which would require that the Board of Directors include a majority of directors that are “independent.” Furthermore, Travis Creed is the only member of our Board of Directors that would qualify as an “independent” director as such term is defined in the Nasdaq Global Market listing standards.
ITEM 14. PRINCIPAL ACCOUNTANTING FEES AND SERVICES
The Company hired Killman, Murrell & Company, PC (“Killman”) as its independent auditors for auditing the Company’s financial statements for the year ended December 31, 2010 and December 31, 2009. It is not anticipated that the auditors will be present at the Annual Meeting.
Audit Fees
The Company incurred $19,000 in fees from Killman for the review of three 2010 quarterly 10-Q reports and will pay approximately $30,000 for its annual December 31, 2010 audit. The Company incurred $22,000 in fees from Killman for the review of the three 2009 quarterly 10-Q reports and $30,000 from Killman for auditing the Company’s financial statements for December 31, 2009 and review of the annual 10-K.
Audit Related Fees
We incurred no fees or expenses for the 2010 and 2009 fiscal years for professional services rendered by Killman other than the fees disclosed above under the caption “Audit Fees” for assurance and related services relating to performance of the audit or review of our financial statements.
Tax Fees
We incurred no fees or expenses for the 2010 and 2009 fiscal years for professional services rendered by Killman for tax compliance, tax advice, or tax planning.
All Other Fees
We incurred no other fees or expenses for the 2010 and 2009 fiscal years for any other products or professional services rendered by Killman other than as described above.
18
Administration of Engagement of Auditor
The Company does not currently maintain a separate audit committee. When necessary, the entire Board of Directors performs the tasks that would be required of such committees. As such, at its regularly scheduled and special meetings, the Board of Directors considers and pre-approves any audit and non-audit services to be performed by our independent accountants.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) | Financial Statements |
The following documents are filed as part of this Annual Report on Form 10-K beginning on the pages referenced below:
Page | |
Report of Independent Registered Public Accounting Firm | F-1 |
Balance Sheets as of December 31, 2010 and 2009 | F-2 |
Statements of Operations for the years ended December 31, 2010 and 2009 | F-3 |
Statements of Changes in Stockholders’ Equity | F-4 |
Statements of Cash Flows for the years ended December 31, 2010 and 2009 | F-5 |
Notes to Financial Statements | F-6 – F18 |
19
(b) | Exhibits |
The following exhibits are filed with this Annual Report on Form 10-K or are incorporated by reference as described below.
Exhibit | Description |
3.1 | Articles of Incorporation of Gem Source, Incorporated dated November 30, 1994 (incorporated by reference to Exhibit 3(i) of the Company’s Registration Statement on Form 10-SB (Amendment No. 2) filed with the Commission on January 19, 2000). |
3.2 | Certificate of Amendment to the Articles of Incorporation of Gem Source, Incorporated filed June 17, 1996 (incorporated by reference to Exhibit 3(i) of the Company’s Registration Statement on Form 10-SB (Amendment No. 2) filed with the Commission on January 19, 2000). |
3.3 | Certificate of Designation of Series E Preferred Stock of Blue Ridge Energy, Inc. filed June 17, 2002* |
3.4 | Certificate of Amendment to the Articles of Incorporation of Blue Ridge Energy, Inc. filed October 11, 2004* |
3.5 | Certificate of Amendment to the Articles of Incorporation of Blue Ridge Energy, Inc. filed June 9, 2005* |
3.6 | Bylaws of Gem Source, Incorporated adopted December 2, 1994 (incorporated by reference to Exhibit 3(ii) of the Company’s Registration Statement on Form 10-SB (Amendment No. 2) filed with the Commission on January 19, 2000). |
10.1 | Services Agreement between Bayou City Exploration, Inc. and Source Capital Group, Inc. dated effective March 1, 2011.* |
10.2 | Limited Partnership Agreement of Bayou City Louisiana Drilling Program, L.P. dated July 8, 2010.* |
10.3 | Turnkey Drilling Contract between Bayou City Exploration, Inc. and Bayou City Louisiana Drilling Program, L.P. dated July 8, 2010.* |
10.4 | Limited Partnership Agreement of 2011 Bayou City Two Well Drilling Program, L.P. dated January 10, 2011.* |
10.5 | Turnkey Drilling Contract between Bayou City Exploration, Inc. and 2011 Bayou City Two Well Drilling Program, L.P. dated January 10, 2011.* |
10.6 | Limited Partnership Agreement of 2011-B Bayou City Two Well Drilling Program, L.P. dated March 4, 2011.* |
10.7 | Turnkey Drilling Contract between Bayou City Exploration, Inc. and 2011-B Bayou City Two Well Drilling Program, L.P. dated March 4, 2011.* |
10.8 | Limited Partnership Agreement of 2011 Bayou City Two Well Drilling and Production Program, L.P. dated March 18, 2011.* |
10.9 | Turnkey Drilling Contract between Bayou City Exploration, Inc. and 2011 Bayou City Two Well Drilling and Production Program, L.P. dated March 18, 2011.* |
10.10 | 2005 Stock Option and Incentive Plan (incorporated by reference to Exhibit A of the Company’s Definitive Proxy filed May 2, 2005). |
10.11 | Non-Qualified Stock Option Agreement between the Company and Robert D. Burr, dated May 18, 2009.(1)* |
10.12 | Non-Qualified Stock Option Agreement between the Company and Stephen Larkin, dated May 18, 2009.(1)* |
10.13 | Non-Qualified Stock Option Agreement between the Company and Travis Creed, dated May 18, 2009.(1)* |
10.14 | Non-Qualified Stock Option Agreement between the Company and Kevin Cline, dated May 18, 2009.* |
10.15 | Non-Qualified Stock Option Agreement between the Company and Charles Bukowski, dated August 3, 2010.(1)* |
10.16 | Purchase of Interest Agreement by and between 2009 Production and Drilling Program, L.P. and the Company, dated January 4, 2010.* |
10.17 | Purchase of Interest Agreement by and between Argyle Energy 2009-VI Year End Production Program, L.P. and the Company, dated January 4, 2010.* |
10.18 | Purchase of Interest Agreement by and between 2009/10 Production & Drilling Program, L.P. and the Company, dated March 1, 2010.* |
10.19 | Purchase of Interest Agreement by and between Burrite, Inc. and the Company, dated March 1, 2010.* |
10.20 | Purchase of Interest Agreement by and between AE 2009/2010-VI Year End Production Program, L.P. and the Company, dated March 1, 2010.* |
10.21 | Lease between RMB Jupiter Office Park, Ltd. and Bayou City Exploration, Inc. dated July 15, 2010.* |
10.22 | Lease between RMB Jupiter Office Park, Ltd. and Bayou City Exploration, Inc. dated January 15, 2011.* |
14.1 | Code of Ethics* |
23.1 | Consent of Pressler Petroleum Consultants, Inc.* |
31.1 | Certification of Principal Executive Officer of Periodic Report pursuant to Rule 13a-14a/Rule 14d-14(a).* |
31.2 | Certification of Principal Financial Officer of Periodic Report pursuant to Rule 13a-14a/Rule 14d-14(a).* |
32.1 | Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350.* |
32.2 | Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350.* |
99.1 | Report of Pressler Petroleum Consultants, Inc.* |
_______________________
* Filed herewith.
(1) Signifies a management agreement.
20
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Bayou City Exploration, Inc. | ||||
By: | /s/ Charles T. Bukowski | |||
Chief Executive Officer and President | ||||
April 14, 2011 | ||||
By: | /s/ Stephen C. Larkin | |||
Chief Financial Officer | ||||
April 14, 2011 | ||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in capacities and the dates indicated.
By: | /s/ Charles T. Bukowski | By: | /s/ Stephen C. Larkin | |||
Charles T. Bukowski, Director | Stephen C. Larkin, Director | |||||
April 14, 2011 | April 14, 2011 | |||||
By: | /s/ Travis N. Creed | |||||
Travis N. Creed, Director April 14, 2011 |
21
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Bayou City Exploration, Inc.
Bowling Green, Kentucky
We have audited the accompanying balance sheets of Bayou City Exploration, Inc. as of December 31, 2010 and 2009, and the related statements of operations, stockholders’ equity (deficit), and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 Bayou City Exploration, Inc. as of December 31, 2010 and 2009, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
/s/ Killman, Murrell & Company, P.C. | ||||
Killman, Murrell & Company, P.C. | ||||
Odessa, Texas | ||||
April 14, 2011
F-1
BAYOU CITY EXPLORATION, INC.
December 31, | December 31, | |||||||
2010 | 2009 | |||||||
ASSETS | ||||||||
CURRENT ASSETS: | ||||||||
Cash | $ | 491,708 | $ | 51,704 | ||||
Accounts receivable: | ||||||||
Trade and other (net of allowance for doubtful accounts - $0 as of December 31, 2010 and $37,468 as of December 31, 2009) | 20,118 | 165,946 | ||||||
Prepaid expenses and other | 5,520 | - | ||||||
TOTAL CURRENT ASSETS | 517,346 | 217,650 | ||||||
OIL & GAS PROPERTIES, NET | 114,845 | 308,967 | ||||||
TOTAL ASSETS | $ | 632,191 | $ | 526,617 | ||||
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT): | ||||||||
CURRENT LIABILITIES: | ||||||||
Accounts payable and accrued expenses | $ | 87,191 | $ | 133,071 | ||||
Accounts payable - related party | 84,906 | 134,906 | ||||||
Notes payable - related parties | 100,000 | 475,000 | ||||||
TOTAL CURRENT LIABILITIES | 272,097 | 742,977 | ||||||
TOTAL LIABILITIES | 272,097 | 742,977 | ||||||
STOCKHOLDERS' EQUITY (DEFICIT): | ||||||||
Preferred stock, $0.001 par value; 5,000,000 shares authorized; No shares issued and outstanding as of December 31, 2010 and December 31, 2009 | - | - | ||||||
Common stock, $0.005 par value; 150,000,000 shares authorized; 29,003,633 shares issued and outstanding at December 31, 2010 and 26,653,633 December 31, 2009 | 145,018 | 133,268 | ||||||
Additional paid in capital | 13,395,739 | 13,363,430 | ||||||
Accumulated deficit | (13,180,663 | ) | (13,713,058 | ) | ||||
TOTAL STOCKHOLDERS' EQUITY (DEFICIT) | 360,094 | (216,360 | ) | |||||
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT) | $ | 632,191 | $ | 526,616 |
See accompanying independent auditor’s report
and notes to financial statements
F-2
BAYOU CITY EXPLORATION, INC.
Years Ended December 31 | ||||||||
2010 | 2009 | |||||||
OPERATING REVENUES: | ||||||||
Oil and gas sales | $ | 260,127 | $ | 1,025,300 | ||||
Gain on sale of oil and gas properties | 1,186,041 | - | ||||||
TOTAL OPERATING REVENUES | 1,446,168 | 1,025,300 | ||||||
OPERATING COSTS AND EXPENSES: | ||||||||
Lease operating expenses and production taxes | 51,955 | 99,596 | ||||||
Abandonment and dry hole costs | 37,430 | 99,583 | ||||||
Depletion and amortization | 309,238 | 11,110 | ||||||
Marketing costs | 105,783 | - | ||||||
General and administrative costs | 421,908 | 374,284 | ||||||
TOTAL OPERATING COSTS | 926,314 | 584,573 | ||||||
OPERATING INCOME | 519,854 | 440,727 | ||||||
OTHER INCOME (EXPENSE): | ||||||||
Interest expense | (11,551 | ) | (45,304 | ) | ||||
Forgiveness of debt | 2,064 | 167,344 | ||||||
Bad debt recovery | - | 170,537 | ||||||
Miscellaneous income | 22,028 | 49,769 | ||||||
NET INCOME BEFORE INCOME TAX | 532,395 | 783,073 | ||||||
Income tax provision | - | - | ||||||
NET INCOME | $ | 532,395 | $ | 783,073 | ||||
NET INCOME PER COMMON SHARE - BASIC AND DILUTED | $ | 0.02 | $ | 0.03 | ||||
Weighted Average Common Shares Outstanding - | ||||||||
Basic | 27,619,386 | 26,653,633 | ||||||
Diluted | 28,032,908 | 26,653,633 | ||||||
See accompanying independent auditor’s report
and notes to financial statements
F-3
BAYOU CITY EXPLORATION, INC.
Bayou City Exploration Inc | |||||||||||
Statements of Stockholders' Equity (Deficit) | |||||||||||
Years Ended December 31, 2010 and 2009 |
Common Stock | Additional | |||||||||||||||||||
Shares | Amount | Paid in Capital | Accumulated Deficit | Total | ||||||||||||||||
Balance at 12/31/2008 | 26,653,633 | $ | 133,268 | $ | 13,284,765 | $ | (14,496,131 | ) | $ | (1,078,098 | ) | |||||||||
Interest on non-interest bearing note payable to shareholder | - | - | 8,000 | - | 8,000 | |||||||||||||||
Stock options granted | - | - | 70,665 | - | 70,665 | |||||||||||||||
Net income | - | - | - | 783,073 | 783,073 | |||||||||||||||
Balance at 12/31/2009 | 26,653,633 | 133,268 | 13,363,430 | (13,713,058 | ) | (216,360 | ) | |||||||||||||
Stock options granted | - | - | 12,559 | - | 12,559 | |||||||||||||||
Interest on non-interest bearing note payable to shareholder | - | - | 8,000 | - | 8,000 | |||||||||||||||
Stock options exercised | 2,350,000 | 11,750 | 11,750 | - | 23,500 | |||||||||||||||
Net income | - | - | - | 532,395 | 532,395 | |||||||||||||||
Balance at 12/31/2010 | $ | 29,003,633 | $ | 145,018 | $ | 13,395,739 | $ | (13,180,663 | ) | $ | 360,094 |
See accompanying independent auditor’s report
and notes to financial statements
F-4
BAYOU CITY EXPLORATION, INC.
Years Ended December 31 | ||||||||
2010 | 2009 | |||||||
CASH FLOW FROM OPERATING ACTIVITIES: | ||||||||
Net Income (Loss) | $ | 532,395 | $ | 783,073 | ||||
Adjustments to reconcile net income (loss) to net cash flows used in operating activities: | ||||||||
Depreciation, depletion, and amortization | 309,238 | 11,110 | ||||||
Interest contributed by shareholder | 8,000 | 8,000 | ||||||
Gain on sale of oil and gas properties | (1,186,041 | ) | - | |||||
Stock option expense | 12,559 | 70,665 | ||||||
Forgiveness of debt | (2,064 | ) | (167,344 | ) | ||||
Change in operating assets and liabilities: | ||||||||
Accounts receivable - trade | 145,829 | 44,728 | ||||||
Prepaid expense and other assets | (5,520 | ) | - | |||||
AFE advances - JIB owners | - | (51,186 | ) | |||||
Accounts payable - related party | (50,000 | ) | (111,392 | ) | ||||
Accounts payable and accrued liabilities | (43,816 | ) | (54,375 | ) | ||||
Long term liability - P&A costs | - | (43,806 | ) | |||||
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES | (279,420 | ) | 489,473 | |||||
CASH FLOW FROM INVESTING ACTIVITIES: | ||||||||
Purchase of oil and gas properties | (654,076 | ) | (314,242 | ) | ||||
Proceeds from sale of assets | 1,725,000 | - | ||||||
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES | 1,070,924 | (314,242 | ) | |||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Proceeds from exercising stock options | 23,500 | - | ||||||
Proceeds on related party line of credit | 25,000 | 65,450 | ||||||
Payments on related party line of credit | (400,000 | ) | (207,019 | ) | ||||
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES | (351,500 | ) | (141,569 | ) | ||||
NET INCREASE IN CASH | 440,004 | 33,662 | ||||||
CASH AT BEGINNING OF YEAR | 51,704 | 18,042 | ||||||
CASH AT END OF YEAR | $ | 491,708 | $ | 51,704 | ||||
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||||
Cash paid for interest | $ | 3,551 | $ | 37,304 | ||||
Cash paid for federal income taxes | $ | - | $ | - |
See accompanying independent auditor’s report
and notes to financial statements
F-5
BAYOU CITY EXPLORATION, INC.
December 31, 2010 and 2009
1. OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Bayou City Exploration, Inc., (the “Company”), a Nevada corporation, was organized in November 1994, as Gem Source, Incorporated (“Gem Source”), and subsequently changed the Company’s name to Blue Ridge Energy, Inc. in June 1996. On June 8, 2005, the Company again changed its name to Bayou City Exploration, Inc.
The Company is engaged in the oil and gas business primarily in the gulf coast of Texas, east Texas, south Texas, and Louisiana.
During 2010, the Company changed its core business strategy. The Company’s primary business objective now focuses on the management of partnerships which are created to explore and develop oil and gas reserves. In connection with this new business plan, the Company will manage partnerships that purchase interests in exploratory wells as well as interests in producing oil and gas properties with undrilled reserves. This growth strategy is based on selling partnership interests to third party investors who will essentially assume the costs associated with the drilling of additional wells in exchange for interests in a partnership that holds a majority of the working interest derived from the wells they finance. The Company acts as the Managing General Partner for these partnerships and maintains a partnership interest or a working interest position outside of the partnership in each program for which we pay our proportionate share of the actual cost of drilling, testing, and completing the project and subsequent operating expenses to the extent that we retain a portion of the working interest. The Company believes this strategy will allow for a reduction of financial risk for the Company in drilling new wells, while still receiving income from present production in addition to income from any new successful new drilling. As of December 31, 2010, the Company held interest in one partnership.
When the Company undertakes a drilling project, a calculation is made to estimate the costs associated with drilling the well. The Company then forms and sells interest in a partnership that will acquire working interest in the well and undertake drilling operations. The Company typically enters into turnkey contracts with the partnerships it manages, pursuant to which we agree to undertake the drilling and completion of the partnerships’ well(s), for a fixed price, to a specific formation or depth. As such, each partnership essentially prepays a fixed amount for the drilling and completion of a specified number of wells which the Company records as revenue.
In addition to our current business strategy described above, the Company also owns certain oil and gas interests as of December 31, 2010 that have developed into revenue producing properties. The Company intends to use cash generated by these properties in addition to the revenues from our partnerships to cover its ongoing operational needs and restructuring of the balance sheet.
Recently Issued Accounting Standards
The FASB established the FASB Accounting Standards Codification (“Codification”) as the source of authoritative U.S. generally accepted accounting principles (“GAAP”) recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements issued for interim and annual periods ending after September 15, 2009. The codification has changed the manner in which U.S. GAAP guidance is referenced, but did not have an impact on our financial position, results of operations or cash flows.
In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2010-06, “Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements.” This ASU requires some new disclosures and clarifies some existing disclosure requirements about fair value measurement as set forth in Accounting Standards Codification (“ASC”) 820. ASU 2010-06 amends ASC 820 to now require: (1) a reporting entity should disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; and (2) in the reconciliation for fair value measurements using significant unobservable inputs, a reporting entity should present separately information about purchases, sales, issuances, and settlements. In addition, ASU 2010-06 clarifies the requirements of existing disclosures. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Early application is permitted. The Company will comply with the additional disclosures required by this guidance upon its adoption in January 2010.
F-6
Also in January 2010, the FASB issued Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas—Oil and Gas Reserve Estimation and Disclosures.” This ASU amends the “Extractive Industries—Oil and Gas” Topic of the Codification to align the oil and gas reserve estimation and disclosure requirements in this Topic with the SEC’s Release No. 33-8995, “Modernization of Oil and Gas Reporting Requirements (Final Rule),” discussed below. The amendments are effective for annual reporting periods ending on or after December 31, 2009, and the adoption of these provisions on December 31, 2009 did not have a material impact on our financial statements.
SEC’s Final Rule on Oil and Gas Disclosure Requirements
On December 31, 2008, the Securities and Exchange Commission, referred to in this report as the SEC, issued Release No. 33-8995, “Modernization of Oil and Gas Reporting Requirements (Final Rule),” which revises the disclosures required by oil and gas companies. The SEC disclosure requirements for oil and gas companies have been updated to include expanded disclosure for oil and gas activities, and certain definitions have also been changed that will impact the determination of oil and gas reserve quantities. The provisions of this final rule are effective for registration statements filed on or after January 1, 2010, and for annual reports for fiscal years ending on or after December 31, 2009.
In August 2009, the FASB issued ASU No. 2009-05, “Fair Value Measurements and Disclosures (Topic 820) — Measuring Liabilities at Fair Value,” related to fair value measurement of liabilities. This update provides clarification that in circumstances in which a quoted price in an active market for an identical liability is not available, a reporting entity is required to measure fair value using one or more valuation techniques. This guidance is effective for the first reporting period beginning after issuance.
In June 2009, the FASB issued guidance under ASC 105, “Generally Accepted Accounting Principles.” This guidance established a new hierarchy of GAAP sources for non-governmental entities under the FASB Accounting Standards Codification. The Codification is the sole source for authoritative U.S. GAAP and supersedes all accounting standards in U.S. GAAP, except for those issued by the SEC. The guidance was effective for financial statements issued for reporting periods ending after September 15, 2009. The adoption had no impact on the Company’s financial position, cash flows or results of operations.
In May 2009, the FASB issued guidance under ASC 855 “Subsequent Events,” which sets forth: (1) the period after the balance sheet date during which management of reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. The guidance was effective on a prospective basis for interim or annual financial periods ending after June 15, 2009.
In April 2009, the FASB updated its guidance under ASC 820, “Fair Value Measurements and Disclosures,” related to estimating fair value when the volume and level of activity for an asset or liability have significantly decreased and identifying circumstances that indicate a transaction is not orderly. The guidance was effective for interim and annual reporting periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009. The adoption of this guidance did not have any impact on the Company’s results of operations.
Also in April 2009, the FASB updated its guidance under ASC 825, “Financial Instruments,” which requires disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This guidance also requires those disclosures in summarized financial information at interim reporting periods. The guidance was effective for interim reporting periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009.
F-7
The FASB updated its guidance under ASC 805, “Business Combinations,” in April 2009, which addresses application issues on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This guidance was effective for business combinations occurring on or after the beginning of the first annual period on or after December 15, 2008.
In June 2008, the FASB updated its guidance under ASC 260, “Earnings Per Share.” This guidance clarified that all unvested share-based payment awards with a right to receive non-forfeitable dividends are participating securities and provides guidance on how to allocate earnings to participating securities and compute basic earnings per share using the two-class method. This guidance was effective for fiscal years beginning after December 15, 2008. The Company adopted this guidance on January 1, 2009. The adoption did not have a material impact on the Company’s earnings per share calculations.
In March 2008, the FASB issued guidance under ASC 815, “Derivatives and Hedging,” which changes the disclosure requirements for derivative instruments and hedging activities. Entities will be required to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related items affect an entity’s financial position, operations and cash flows. This guidance was effective as of the beginning of an entity’s fiscal year that begins after November 15, 2008. The Company adopted this guidance on January 1, 2009.
Revenue Recognition
Under the sales method, oil and gas revenue is recognized when produced and sold. Management fees are recognized under the accrual method and recorded when earned. Prospect fees charged under joint participation agreements are recorded after execution.
Accounts Receivable
Accounts receivable are from oil and gas sales produced and sold during the reporting period but awaiting cash payment. Based upon a review of trade receivables as of December 31, 2010, a total of $0 was considered potentially uncollectible, this compares to $37,468 at December 31, 2009. A reserve for uncollectible receivables was recognized for this amount and is included in operating costs of the Company’s 2010 and 2009 statement of operations. Receivables are reviewed quarterly, and if any are deemed uncollectible, they are written off as bad debts.
Managed Limited Partnerships
Prior to 2004 and starting again in 2010, the Company managed limited partnerships for which it serves as the Managing General Partner. The Company normally participates for 10% of the limited partnerships as the Managing General Partner and accounts for the investment under the equity method. Revenues received and changes in the partnership investments are recorded as oil and gas revenues and net assets, respectively. As of December 31, 2010, the Company held interest in one partnership.
Oil and Gas Properties
The Company follows the successful efforts method of accounting for oil and gas producing activities. Under the successful efforts method of accounting, costs which relate directly to the discovery of oil and gas reserves are capitalized. These capitalized costs include:
(1) | the costs of acquiring mineral interest in properties, | ||
(2) | costs to drill and equip exploratory wells that find proved reserves, | ||
(3) | costs to drill and equip development wells, and | ||
(4) | costs for support equipment and facilities used in oil and gas producing activities. |
These costs are depreciated, depleted or amortized on the unit of productions method, based on estimates of recoverable proved developed oil and gas reserves. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed.
F-8
The costs of acquiring unproved properties are capitalized as incurred and carried until the property is reclassified as a producing oil and gas property, or considered impaired as discussed below. The Company annually assesses its unproved properties to determine whether they have been impaired. If the results of this assessment indicate impairment, a loss is recognized by providing a valuation allowance. When an unproved property is surrendered, the costs related thereto are first charged to the valuation allowance, with any additional balance expensed to operations.
The costs of drilling exploration wells are capitalized as wells in progress pending determination of whether the well has proved reserves. Once a determination is made, the capitalized costs are charged to expense if no reserves are found or, otherwise reclassified as part of the costs of the Company’s wells and related equipment. In the absence of a determination as to whether the reserves that have been found can be classified as proved, the costs of drilling such an exploratory well are not carried as an asset for more than one year following completion of drilling. If after a year has passed, and the Company is unable to determine that proved reserves have been found, the well is assumed to be impaired, and its costs are charged to expense. At December 31, 2010 the Company had $0 in capitalized costs pending determination, but at December 31, 2009, the Company had $186,000 in costs capitalized pending determination. During 2010, the wells were drilled and the costs were transferred to capitalized costs of producing oil and gas properties.
Accounting for Asset Retirement Obligations
The Company follows the provisions of Statement of Financial Accounting Standards (SFAS) No. 143(ASC 410), Accounting for Asset Retirement Obligations. SFAS No. 143(ASC 410) requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Prior to 2005, management determined that any future costs related to plugging and abandonment of producing wells would be substantially offset by the value of equipment removed from the well site and such estimates were immaterial to the financial statements. Therefore, no liability was recorded prior to 2005. Due to continued rising rig and fuel costs, a detailed estimate was made in the second quarter of 2005 to determine how these rising service costs would affect future plugging and abandonment costs. As a result of this analysis, management concluded that a liability should be recorded within the financial statements under the provisions of SFAS 143(ASC 410). These costs are evaluated annually and adjusted accordingly under the guidelines of SFAS 143(ASC 410). As of December 31, 2009, the assets have been fully impaired. The Pedigo well was plugged and abandoned in 2009 and the Company paid its share of the costs and returned the balance of the liability in the amount of $45,000 to miscellaneous income in 2009. As of December 31, 2010 the Company had no liability established for any of their wells that are currently in production.
Surrender or Abandonment of Developed Properties
Normally, no separate gain or loss is recognized if only an individual item of equipment is abandoned or retired or if only a single lease or other part of a group of proved properties constituting the amortization base is abandoned or retired as long as the remainder of the property or group of properties continues to produce oil or gas. The asset being abandoned or retired is deemed to be fully amortized, and its cost is charged to accumulated depreciation, depletion or amortization. When the last well on an individual property or group of properties with common geological structures ceases to produce and the entire property or property group is abandoned, gain or loss, if any, is recognized. Abandonment and dry hole costs were $37,430 and $99,583 for the years ended December 31, 2010 and 2009, respectively.
Other Dispositions
Upon disposition or retirement of property and equipment other than oil and gas properties, the cost and related accumulated depreciation are removed from the accounts and the gain or loss thereon, if any, is credited or charged to expense. The Company recognizes the gain or loss on the sale of either a part of a proved oil and gas property or of an entire proved oil and gas property constituting a part of a field upon the sale or other disposition of such. The unamortized cost of the property or group of properties, a part of which was sold or otherwise disposed of, is apportioned to the interest sold and interest retained on the basis of the fair value of those interests.
F-9
Impairment of Long-Lived Assets
The Company follows the provisions of ASC Subtopic 360-35, “Property, Plant and Equipment – Subsequent Measurement.” Consequently, the Company reviews its long-lived assets to be held and used, including oil and gas properties accounted for under the successful efforts method of accounting. Whenever events or circumstances indicate the carrying value of those assets may not be recoverable, an impairment loss for proved properties and capitalized exploration and development costs is recognized. The Company assesses impairment of capitalized costs, or carrying amount, of proved oil and gas properties by comparing net capitalized costs to undiscounted future net cash flows on a field-by-field basis using known expected prices, based on set agreements. If impairment is indicated based on undiscounted expected future cash flows, then impairment is recognizable to the extent that net capitalized costs exceed the estimated fair value of the property. Fair value of the property is estimated by the Company using the present value of future cash flows discounted at 10%, in accordance with SFAS No. 69 (ASC 932-235), “Disclosures about Oil and Gas Producing Activities,”
Income (Loss) Per Common Share
The Company calculates basic earnings per common share (“Basic EPS”) using the weighted average number of common shares outstanding for the period.
The following table provides the numerators and denominators used in the calculation of Basic EPS for the years ended December 31, 2010 and 2009:
2010 | 2009 | |||||||
Income (loss) from operations | $ | 532,395 | $ | 783,073 | ||||
Less preferred stock dividends | -0- | -0- | ||||||
Income (loss) available to common stockholders | $ | 532,395 | $ | 783,073 | ||||
Common stock outstanding for the full year | 27,619,386 | 26,653,633 | ||||||
Assumed exercise of stock options | 413,522 | -0- | ||||||
Weighted average common shares outstanding | 28,032,908 | 26,653,633 |
Stock Options
Effective January 1, 2006, the Company accounts for stock options in accordance with revised Statement of Financial Accounting Standards (SFAS) No. 123, Share-Based Payment (SFAS 123(R) (ASC 718 and 505). Accordingly, stock compensation expense has been recognized in the statement of operations based on the grant date fair value of the options for the period ended December 31, 2006 and thereafter.
Under SFAS 123(R) (ASC 718 and 505), the fair value of options is estimated at the date of grant using a Black-Scholes-Merton (“Black-Scholes”) option-pricing model, which requires the input of highly subjective assumptions including the expected stock price volatility. Volatility is determined using historical stock prices over a period consistent with the expected term of the option. The Company utilizes the guidelines of Staff Accounting Bulletin No. 107 (SAB 107) of the Securities and Exchange Commission relative to “plain vanilla” options in determining the expected term of option grants. SAB 107 permits the expected term of “plain vanilla” options to be calculated as the average of the option’s vesting term and contractual period.
The Company has used this method in determining the expected term of all options. The Company has several awards that provide for graded vesting. The Company recognizes compensation cost for awards with graded vesting on a straight-line basis over the requisite service period for the entire award. The amount of compensation expense recognized at any date is at least equal to the portion of the grant date value of the award that is vested at that date.
F-10
Concentrations of Credit Risk Arising From Cash Deposits in Excess of Insured Limits
The Company maintains its cash balances in one financial institution located in Bowling Green, Kentucky. The balances are insured by the Federal Deposit Insurance Corporation for up to $250,000. At December 31, 2010 the cash balances were at $491,708.
Advertising
The Company expenses advertising costs as these are incurred. Marketing expenses totaled $105,783 and $0 in 2010 and 2009 respectively.
Income Taxes
There is no provision for income taxes for the years ended December 31, 2010 and 2009. Income taxes are provided for under the liability method in accordance with SFAS No. 109, (ASC 740) “Accounting for Income Taxes,” which takes into account the differences between financial statement treatment and tax treatment of certain transactions. It is uncertain as to whether the Company will generate sufficient future taxable income to utilize the net deferred tax assets, therefore for financial reporting purposes, a valuation allowance of $3,538,000 and $3,702,000 has been recognized to offset the net deferred tax assets at December 31, 2010 and December 31, 2009, respectively.
Fair Value of Financial Instruments
The carrying cash value and cash equivalents, receivables, prepaids, accounts payable, notes payable and advances payable approximate their fair value. Management is of the opinion that the Company is not exposed to significant interest or credit risk arising from these financial instruments.
Reclassifications
Certain accounts in prior-year financial statements have been reclassified for comparative purposes to conform with the presentation in the current-year financial statements.
2. RELATED PARTY TRANSACTIONS
A. Common Stock Transactions
As of December 31, 2010, there are 29,003,633 shares of common stock issued and outstanding. Of all the shareholders of record, no single entity owns five percent or more.
B. Payables and Notes Payable to Related Parties.
As of December 31, 2010 and December 31, 2009 the Company had the following debts and obligations to related parties:
December 31, 2010 | December 31, 2009 | |||||||
Drilling Advances payable to Gulf Coast Drilling Co. | -0- | 50,000 | ||||||
Payable to minority shareholders for operating capital | 85,000 | 85,000 | ||||||
Line of Credit payable to Blue Ridge Group for operating capital | -0- | 375,000 | ||||||
Note payable to minority shareholder | 100,000 | 100,000 | ||||||
Total Payable or Notes Payable to Related Parties | $ | 185,000 | $ | 610,000 |
The line of credit payable to Blue Ridge Group was executed by the Company on July 17, 2009, in the amount of $500,000 to finance the Company’s operations. The line of credit provides for interest at the rate of 8% per annum on the unpaid outstanding balance and is due upon demand. If no demand for payment is made by Blue Ridge Group, the line of credit balance plus all accrued unpaid interest is due July 17, 2010. The balance of the line of credit was $0 and $375,000 for the years ended December 31, 2010 and 2009 respectively. The Company paid the line in full with all accrued interest on March 1, 2010 including interest of $3,551.
During the fourth quarter of 2007, Peter Chen, a minority shareholder loaned the Company $100,000 to finance the Company’s operations. The Company executed a promissory note on October 4, 2007; the note is due on demand and bears an interest rate of 0%. The Company charges interest at 8.0% or $8,000 and regards it as interest expense and additional paid in capital. As of December 31, 2010 and 2009, the Company owed Gulf Coast Drilling Company (an affiliate of Blue Ridge Group) $0 and $50,000, respectively, in monies that were in excess of Blue Ridge Group’s participation interest in the well.
F-11
3. OIL AND GAS PROPERTIES
Oil and gas properties, stated at cost, consisted of the following:
December 31 | ||||||||
2010 | 2009 | |||||||
Proved oil and gas properties | $ | 429,000 | $ | 129,000 | ||||
Investment in partnerships | - | 21,000 | ||||||
Unproved oil and gas properties | - | 186,000 | ||||||
Total oil and gas properties | 429,000 | 336,000 | ||||||
Less accumulated depletion and amortization | (314,000 | ) | (27,000 | ) | ||||
Less impairment | - | - | ||||||
Net oil and gas properties | $ | 115,000 | $ | 309,000 |
Depletion and amortization expense was $309,238 and $11,110 during the years ended 2010 and 2009, respectively. The increase of $298,158 was due mainly to the fact that the producing wells new reserve report changed drastically from December 31, 2009 to much lower anticipated reserves.
During 2010 and 2009, the Company provided for abandonment and dry hole costs of $37,430 and $99,596, respectively. The amount for 2009 was related to the Powers Well drilled in the third quarter of 2009 which was a dry hole. The 2010 amount represents the 10% ownership in a partnership that produced a dry hole at the end of 2010.
4. OPERATING LEASE
The Company entered into an operating lease agreement on July 12, 2010 and rental expenses were $9,660 for the year.
5. INCOME TAXES
The tax effect of significant temporary differences representing the net deferred tax liability at December 31, 2010 and 2009 were as follows:
2010 | 2009 | |||||||
Net operating loss carry forward | $ | 3,167,000 | $ | 3,357,000 | ||||
Intangible Drilling Costs | (92,000 | ) | --- | |||||
Depletion, depreciation and amortization | 114,000 | 1,000 | ||||||
Stock based compensation | 349,000 | 344,000 | ||||||
Valuation allowance | (3,538,000 | ) | (3,702,000 | ) | ||||
Net deferred tax liability | $ | --- | $ | --- |
The Company recorded $-0- as income tax expense for the years ended December 31, 2010 and 2009, as a result of net operating losses to offset its taxable income. Further, no income tax benefit has been recognized due to the uncertainty of the Company’s ability to recognize the benefit from the net operating losses and, therefore, has recorded a full valuation allowance against the deferred tax assets.
F-12
The benefit (expense) for income taxes is different from the amount computed by applying the U.S. statutory corporate federal income tax rate to pre-tax loss as follows:
2010 | 2009 | |||||||||||||||
Amount | Percent | Amount | Percent | |||||||||||||
Income tax benefit (tax expense) computed at the statutory rate | $ | (181,000 | ) | 34.0 | % | $ | (266,000 | ) | 34.0 | % | ||||||
Increase (reduction) in tax benefit resulting from: | ||||||||||||||||
State and local income taxes, net of federal tax effect | (21,000 | ) | 4.0 | % | (31,000 | ) | 4.0 | % | ||||||||
Adjustment for book to tax changes | 38,000 | (0.0 | )% | 4,000 | (38.0 | )% | ||||||||||
Permanent items | --- | (0.0 | )% | --- | (0.0 | )% | ||||||||||
Valuation allowance (increase) decrease | 164,000 | (38.0 | )% | 293,000 | (38.0 | )% | ||||||||||
Income tax benefit (expense) | $ | --- | --- | $ | --- | --- |
The Company has an estimated net operating loss carry forward of $8,334,000 and $8,834,000 as of December 31, 2009 and 2008 respectively. These net operating loss carry forwards will begin expiring in 2019 unless utilized sooner. Under Internal Revenue Code (IRC) Section 382, a change in ownership occurred on December 31, 2004 with the issuance of the additional shares from the private stock placement. As of December 31, 2004, the net operating loss (NOL) carry forward amount was $3,341,000. The Section 382 rule will limit the use of this December 31, 2004 NOL carry forward to $267,000 per year.
6. COMMITMENTS AND CONTINGENCIES
Commitments
The Company nor any of its properties is subject to any material pending legal proceedings.
Contingencies
The oil and gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures and discharges of toxic gases. The occurrence of any of these events could result in substantial losses to the Company due to severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The occurrence of a significant event it could materially and adversely affect our future revenues from any given prospect.
7. STOCKHOLDERS’ EQUITY
Authorization to Issue Shares — Preferred and Common
The Company is authorized to issue two classes of stock that are designated as common and preferred stock. On October 8, 2004, a Special Meeting of Stockholders was held requesting the approval of an Amendment to the Company’s Articles of Incorporation to increase the authorized shares of Common Stock from 20,000,000 shares to 150,000,000 shares. The amendment was approved at the Special Meeting of Stockholders. As of December 31, 2009, the Company was authorized to issue 155,000,000 shares of stock, 150,000,000 being designated as common stock, $0.005 par value, and 5,000,000 shares designated as preferred stock, $0.001 par value.
F-13
Stock Options
On February 22, 2005, the Board of Directors adopted the 2005 Plan, the purposes of which are to (i) attract and retain the best available personnel for positions of responsibility within the Company, (ii) provide additional incentives to employees of the Company, (iii) provide directors, consultants and advisors of the Company with an opportunity to acquire a proprietary interest in the Company to encourage their continuance of service to the Company and to provide such persons with incentives and rewards for superior performance more directly linked to the profitability of the Company’s business and increases in shareholder value, and (iv) generally to promote the success of the Company’s business and the interests of the Company and all of its stockholders, through the grant of options to purchase shares of the Company’s Common Stock and other incentives. Subject to adjustments upon changes in capitalization or merger, the maximum aggregate number of shares which may be optioned and sold or otherwise awarded under the 2005 Plan is seven million (7,000,000) common shares. The Board of Directors administers the 2005 Plan. Generally, awards of options under the 2005 plan vest immediately or on a graded basis over a 5 year term. The maximum contractual period of options granted is 10 years. The 2005 Plan will terminate on February 22, 2015. As of December 31, 2010, approximately 2,150,000 shares are available for grant. Issuance of common stock from the exercise of stock options will be made with new shares from authorized shares of the Company.
In 2009, the Board of Directors decided that with the current stock options strike price compared to the current market price, that the outstanding options were simply not an incentive anymore to the current employees and directors. Therefore, in May of 2009 the Company decided to cancel the outstanding options to the current employees and directors and issue new ones. As a result, the Company cancelled 2,968,750 options and issued 6,000,000 options to its current employees, directors and key consultants and advisors of the Company and expensed $71,000 in relation to issuance of these options. All options were issued at the strike price of $.01, with varying vesting terms. In 2010, there were 500,000 shares issued to Mr. Bukowski at $0.05 strike price and 1,750,000 options expired. All options granted have a ten year term. In 2010 the Company had 666,667 shares vest and realized a stock option expense of $12,559.
At December 31, 2010 there were options, fully vested and expected to vest, to purchase 2,500,000 shares with a weighted average exercise price of $0.018 having an intrinsic value of $45,000 and a weighted contractual term of 8.67 years. At December 31, 2009, there were options to purchase 6,100,000 shares with a weighted average exercise price of $0.028, an intrinsic value of $287,000 and a weighted average contractual term of 9.23 years.
For the years ended December 31, 2010 and 2009 there was $12,559 and $70,665 stock based compensation expense, respectively. The stock based compensation was valued using the Black-Scholes pricing model using the following assumptions:
Estimated Fair Value | $0.014 - $0.048 | ||
Expected Life | 10 years | ||
Risk Free Interest Rate | 1.09% - 5.00% | ||
Volatility | 100% - 303% | ||
Dividend Yield | --- |
When calculating stock-based compensation expense the Company must estimate the percentage of non-vested stock options that will be forfeited due to normal employee turnover. Since its adoption of SFAS 123(R) (ASC 718 and 505) on January 1, 2006, the Company initially used a forfeiture rate of 20% and increased its forfeiture rate to 50% during the third quarter 2006. This was due to the Company experiencing a number of resignations of senior management personnel, each of whom had been awarded options which, in many cases, had not vested and therefore will be forfeited. In the future the Company will use an appropriate estimate for the forfeiture rate at the time options are being granted.
F-14
The following table provides a summary of the stock option activity for all options for the year ended December 31, 2010.
Number of Weighted Average | Options Exercise Price | |||||||
Options at December 31, 2009 | 6,100,000 | 0.03 | ||||||
Options expired or cancelled in 2010 | (1,750,000 | ) | (0.01 | ) | ||||
Options exercised in 2010 | (2,350,000 | ) | (0.01 | ) | ||||
Options issued 2010 | 500,000 | 0.025 | ||||||
Options at December 31, 2010 | 2,500,000 | 0.02 | ||||||
Options exercisable at December 31, 2010 | 1,166,667 | 0.02 |
8. FAIR VALUE ESTIMATES
In February 2007 the FASB issued SFAS No. 157 (ASC 820) “Fair Value Measurements”. The objective of SFAS 157 (ASC 820) is to increase consistency and comparability in fair value measurements and to expand disclosures about fair value measurements. SFAS 157 (ASC 820) defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS 157 (ASC 820) applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements.
The Company measures its options at fair value in accordance with SFAS 157 (ASC 820). SFAS 157 (ASC 820) specifies a valuation hierarchy based on whether the inputs to those valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect the Company’s own assumptions. These two types of inputs have created the following fair value hierarchy:
Level 1 – Quoted prices for identical instruments in active markets;
Level 2 – Quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets; and
Level 3 – Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable.
This hierarchy requires the Company to minimize the use of unobservable inputs and to use observable market data, if available, when estimating fair value. The fair value of the options held for sale at December 31, 2010, was as follows:
Quoted Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Total | |||||||||||||
Options | (Level 1) | (Level 2) | (Level 3) | |||||||||||||
2010 | $ | --- | $ | 12,559 | $ | --- | $ | 12,559 | ||||||||
2009 | $ | --- | $ | 70,665 | $ | --- | $ | 70,665 |
The Provisions of SFAS 157 are effective for fair value measurements made in fiscal years beginning after November 15, 2007. Options were valued using the Black-Scholes model.
F-15
9. SUPPLEMENTAL INFORMATION ON OIL & GAS (Unaudited)
Capitalized Costs Relating to Oil and Gas | December 31, | |||||||
Producing Activities | 2010 | 2009 | ||||||
Unproved oil and gas properties | $ | - | $ | 186,000 | ||||
Proved oil and gas properties | 429,000 | 149,000 | ||||||
Less accumulated depreciation, depletion amortization, and impairment | (314,000 | ) | (26,000 | ) | ||||
Net capitalized costs | $ | 115,000 | $ | 309,000 | ||||
Costs incurred in Oil and Gas Producing Activities For the years ended | ||||||||
Property acquisition costs | ||||||||
Proved | $ | - | $ | 47,000 | ||||
Unproved | - | 186,000 | ||||||
Exploration costs | 65,000 | 67,000 | ||||||
Development costs | 50,000 | 35,000 | ||||||
Amortization rate per equivalent barrel of production | $ | 56.73 | $ | 16.50 | ||||
Results of Operation for Oil and Gas Producing Activities for the years ended | ||||||||
Oil and gas sales | $ | 260,000 | $ | 25,000 | ||||
Gain on sale of oil and gas properties | 1,186,000 | 1,000,000 | ||||||
Impairment, abandonment, and dry hole costs | (37,000 | ) | (100,000 | ) | ||||
Production costs | (52,000 | ) | (100,000 | ) | ||||
Depreciation, depletion and amortization | (309,000 | ) | (11,000 | ) | ||||
1,048,000 | 814,000 | |||||||
Income tax expense | - | - | ||||||
Results of operations for oil and gas producing | ||||||||
Activities (excluding corporate overhead and | ||||||||
Financing costs) | $ | 1,048,000 | $ | 814,000 |
Reserve Information
The estimates of proved oil and gas reserves utilized in the preparation of the financial statements were prepared by independent petroleum engineers. Such estimates are in accordance with guidelines established by the SEC and the FASB. All of our reserves are located in the United States.
In 2009, the SEC issued its final rule on the modernization of oil and gas reporting, and the FASB adopted conforming changes to ASC Topic 932, “Extractive Industries”, to align the FASB’s reserves requirements with those of the SEC. The final rule is now in effect for companies with fiscal years ending on or after December 31, 2009.
As it affects our reserve estimates and disclosures, the final rule:
· | amends the definition of proved reserves to require the use of average commodity prices based upon the prior 12-month period rather than year-end prices (Oil - $79.43 Bbls; Gas – $4.38 Mcf for year ended December 31, 2010); |
· | expands the type of technologies available to establish reserve estimates and categories; |
· | modifies certain definitions used in estimating proved reserves; |
· | permits disclosure of probable and possible reserves; |
· | requires disclosure of internal controls over reserve estimations and the qualifications of technical persons primarily responsible for the preparation or audit of reserve estimates; |
· | permits disclosure of reserves based on different price and cost criteria, such as futures prices or management forecasts; and |
· | requires disclosure of material changes in proved undeveloped reserves, including a discussion of investments and progress made to convert proved undeveloped reserves to proved developed reserves |
F-16
We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. In addition, a portion of our proved reserves are classified as proved developed nonproducing and proved undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced.
The following table sets forth estimated proved oil and gas reserves together with the changes therein for the year ended December 31, 2010:
Oil (bbls) | Gas (mcf) | |||||||
Proved developed and undeveloped reserves | ||||||||
Beginning of year | 1,380 | 35,459 | ||||||
Revisions of previous estimates | 398 | (2,078 | ) | |||||
Improved recovery | - | - | ||||||
Purchases of minerals in place | - | - | ||||||
Extensions and discoveries | - | - | ||||||
Production | (1,019 | ) | (26,592 | ) | ||||
Sales | - | - | ||||||
End of Year | 760 | 6,789 | ||||||
Proved developed reserves | ||||||||
Beginning of year | 1,381 | 35,459 | ||||||
End of Year | 760 | 6,789 | ||||||
Standardized measure of Discounted Future | ||||||||
Net Cash Flows at December 31, 2010 | ||||||||
Future cash inflows | $ | 86,141 | ||||||
Future production costs | (41,667 | ) | ||||||
Future development costs | (480 | ) | ||||||
Future income tax expenses | - | |||||||
43,994 | ||||||||
Future net cash flows | ||||||||
10% annual discount for estimated timing of cash flows | (2,383 | ) | ||||||
Standardized Measures of Discounted Future | ||||||||
Net Cash Flows Relating to Proved Oil and Gas Reserves | $ | 41,611 |
The Company also owns a royalty interest of 8.073375% in the Sien #1 well. The reserve report is not available at this time. Production for the years 2010 and 2009 are as follows, please note 2010 only had 2 months of production and had already sold off some of their royalty interest in January 2010.
2010 | 2009 | |||||||
Beginning of year | $ | 115,070 | $ | - | ||||
Sales of oil and gas produced, net of production costs | (201,442 | ) | (15,877 | ) | ||||
Net changes in prices and production costs | 119,730 | - | ||||||
Extensions, discoveries, and improved recovery, less related costs | 1,369 | - | ||||||
Development costs incurred during the year which were previously estimated | 1,620 | - | ||||||
Net change in estimated future development costs | (480 | ) | - | |||||
Revisions of previous quantity estimates | - | - | ||||||
Net change from purchases and sales of minerals in place | 5,744 | 130,947 | ||||||
Accretion of discount | - | - | ||||||
Net change in income taxes | - | - | ||||||
Other | - | - | ||||||
End of year | $ | 41,611 | $ | 115,070 |
F-17
The Company also owns a royalty interest of 8.073375% in the Sien #1 well. The reserve report is not available at this time. Production for the years 2010 and 2009 are as follows, please note 2010 only had 2 months of production and had already sold off some of their royalty interest in January 2010.
2009 | Net Oil Volume | Oil Revenue | Net Gas Volume | Gas Revenue | ||||||||||||
2,690.14 | 134,202.27 | 191,716.03 | 806,266.60 | |||||||||||||
2010 | ||||||||||||||||
30.07 | 671.52 | 7,788.32 | 52,412.01 |
As of January 1, 2010 the Company agreed to sell their interest in the well to five related parties for a combined total of $1,000,000.
10. SUBSEQUENT EVENTS:
In May 2009, the FASB issued SFAS No. 165 (ASC 855), subsequent events (“ASC 855”). ASC 855 establishes general standards of accounting for and disclosure of events after the balance sheet date but before financial statements are issued or are available to be issued. The adoption in the fourth quarter of 2009 did not have any material impact on the Company’s financial statements. Accordingly, the Company evaluated subsequent events through April 14, 2011, the date the financial statements were issued.
Formation of New Limited Partnerships.
Subsequent to the year ended December 31, 2010, the Company has formed and serves as the managing general partner of three limited partnerships: the 2011 Bayou City Two Well Drilling Program, L.P., the 2011-B Bayou City Two Well Drilling Program, L.P., and the 2011 Bayou City Two Well Drilling and Production Program, L.P.
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