10-K 1 bayou_10k-123112.htm FORM 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

(Mark One)

ANNUAL REPORT UNDER SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

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 þ

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 £ No þ

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 þ 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 þ 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 þ

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2012, the last day of the registrant’s most recently completed second quarter, was $870,129.

As of March 21, 2013 the registrant had 990,230 shares of Common Stock, par value $0.005 per share, issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE None.

FORM 10-K

TABLE OF CONTENTS

PART I		2
ITEM 1.	BUSINESS	2
ITEM 1A.	RISK FACTORS	7
ITEM 1B.	UNRESOLVED STAFF COMMENTS	7
ITEM 2.	PROPERTIES	7
ITEM 3.	LEGAL PROCEEDINGS	11
ITEM 4.	MINE SAFETY DISCLOSURES	11
PART II		11
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	11
ITEM 6.	SELECTED FINANCIAL DATA	12
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	13
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	16
ITEM 8.	FINANCIAL STATEMENTS and supplementary data	16
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	16
ITEM 9a.	CONTROLS AND PROCEDURES	16
ITEM 9B.	OTHER INFORMATION	18
PART III		18
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	18
ITEM 11.	EXECUTIVE COMPENSATION	19
ITEM 12.	SECURITIES OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	21
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	22
ITEM 14.	PRINCIPAL ACCOUNTANTing FEES AND SERVICES	23
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	23
SIGNATURES		26

INTRODUCTORY COMMENT

Throughout this Annual Report on Form 10-K (this "Report”), the terms “we,” “us,” “our,” or the “Company” refers to Bayou City Exploration, Inc., a Nevada corporation.

FORWARD LOOKING STATEMENTS

When used in this Report, the words “may,” “will,” “expect,” “anticipate,” “continue,” “estimate,” “intend,” and similar expressions are intended to identify forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) regarding events, conditions and financial trends which may affect the Company’s future plans of operations, business strategy, operating results and financial position. Such statements are not guarantees of future performance and are subject to risks and uncertainties described herein and actual results may differ materially from those included within the forward-looking statements. Additional factors are described in the Company’s other public reports and filings with the Securities and Exchange Commission (the “SEC”). Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date made. The Company undertakes no obligation to publicly release the result of any revision of these forward-looking statements to reflect events or circumstances after the date they are made or to reflect the occurrence of unanticipated events.

This Report contains certain estimates and plans related to us and the industry in which we operate, which assume certain events, trends and activities will occur and the projected information based on those assumptions. We do not know that all of our assumptions are accurate. If our assumptions are wrong about any events, trends and activities, then our estimates for future growth for our business may also be wrong. There can be no assurance that any of our estimates as to our business growth will be achieved.

The following discussion and analysis should be read in conjunction with our financial statements and the notes associated with them contained elsewhere in this Report. This discussion should not be construed to imply that the results discussed in this Report will necessarily continue into the future or that any conclusion reached in this Report will necessarily be indicative of actual operating results in the future. The discussion represents only the best assessment of management.

PART I

ITEM 1. business

Development of the Company

Bayou City Exploration, Inc., a Nevada corporation (the “Company”), was organized in November 1994, as Gem Source, Incorporated and in June 1996 changed its name to Blue Ridge Energy, Inc. On June 8, 2005, the Company again changed its name to Bayou City Exploration, Inc.

Overview of Business

The Company is primarily engaged in the oil and gas exploration business, and focuses its operations in the gulf coast of Texas, east Texas, south Texas, and Louisiana. The Company also serves as the Managing Member and Investment Manager of funds organized as limited liability companies to acquire portfolios of mortgage notes and land contracts secured by real estate (the “Mortgage Notes and Land Contracts”). Nevertheless, most of our business resources are focused upon the management of partnerships created to explore and develop oil and gas reserves. We manage partnerships that purchase interests in exploratory wells and/or interests in producing oil and gas properties with undrilled reserves. Our growth strategy is based on sponsoring partnerships in which third party investors purchase an interest. These partnerships then assume the costs associated with the drilling of oil and gas wells in exchange for units in a partnership that holds a portion of the working interest derived from the wells they finance. We act as the managing general partner for these partnerships and typically maintain a 10% interest in such partnerships, but may also maintain 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. We believe this strategy allows for a reduction of financial risk associated with drilling new wells, while enabling us to earn income from present production in addition to income from any successful new drilling.

Oil and Gas Drilling Partnerships and Properties

When we undertake a drilling project, a calculation is made to estimate the costs associated with drilling the project well(s). The Company then forms and sells interest in a partnership that will acquire working interest in the wells and undertake drilling operations. We typically enter into turnkey contracts with the partnerships we manage, 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 (each, a “Turnkey Agreement”). As such, each partnership essentially prepays a fixed amount for the drilling and completion of a specified number of wells, which we record as revenue.

As of December 31, 2012, we served as the managing general partner of eight limited partnerships formed for the purpose of oil and gas exploration and drilling. The Company has entered into Turnkey Agreements with each of these partnerships pursuant to which we receive turnkey fees for drilling the partnerships’ wells and, if applicable, completing the wells (the “Turnkey Fees”).

The 2011 Bayou City Two Well Drilling Program, L.P. (the “2011 Drilling Program”) was formed in Kentucky on January 10, 2011, and planned to acquire up to a 2.125% working interest in two oil and gas wells known as the Miller Prospect Well and the Squeeze Box Prospect Well in Colorado County, Texas. The 2011 Drilling Program has acquired a 1.78% working interest in the wells. The Company paid for and holds a 10% interest in this partnership and receives management fees equal to the excess, if any, of the Turnkey Fees over the total cost to the Company of drilling and if applicable, completing the partnership wells.

The 2011-B Bayou City Two Well Drilling Program, L.P. (the “2011-B Drilling Program”) was formed in Kentucky on March 4, 2011 to acquire a 5% working interest in two oil wells, in what is known as the Friesian Well, located in Colorado County, Texas and the Little Chenier Well, located in Cameron Parish, Louisiana. The Company paid for and holds a 10% interest in this partnership and receives management fees equal to the excess, if any, of the Turnkey Fees over the total cost to the Company of drilling and if applicable, completing the partnership wells.

The 2011 Bayou City Drilling & Production Program, L.P. (the “Drilling and Production Program”) was formed on March 18, 2011 to acquire a 2.875% working interest in the same two wells as the 2011 and 2011-B Drilling Programs. The Company paid for and holds a 10% interest in this partnership and receives management fees equal to the excess, if any, of the Turnkey Fees over the total cost to the Company of drilling and if applicable, completing the partnership wells.

The 2011-C Bayou City Offset Drilling Program, L.P. (the “2011-C Drilling Program”) was formed in Kentucky on April 12, 2011 to acquire up to a 5% working interest in the Kleimann #1 Well, located in Colorado County, Texas. The 2011-C Drilling Program ended up only acquiring a 2.625% working interest in the Kleimann #1 well. The Company paid for and holds a 10% interest in this partnership and receives management fees equal to the excess, if any, of the Turnkey Fees over the total cost to the Company of drilling and if applicable, completing the partnership well.

The 2011-D Bayou City Two Well Drilling Program, L.P. (the “2011-D Drilling Program”) was formed in Kentucky on May 10, 2011 to acquire a 5% working interest in the Prairie Bell West Prospect Well and the Prairie Bell East Prospect Well located in Colorado County, Texas. The Company paid for and holds a 10% interest in this partnership and receives management fees equal to the excess, if any, of the Turnkey Fees over the total cost to the Company of drilling and if applicable, completing the partnership wells.

The 2011 Bayou City Year End Drilling Program, L.P. (“2011 Year End Program”) was formed in Kentucky on September 13, 2011 to acquire a 6.48% working interest in the Loma Blanca Well located in Brooks County, Texas. The Company paid for and holds a 10% interest in this partnership and receives management fees equal to the excess, if any, of the Turnkey Fees over the total cost to the Company of drilling and if applicable, completing the partnership well.

The 2012-A Bayou City Year Drilling Program, L.P. (“2012-A Program”) was formed in Kentucky on December 13, 2011 to acquire an 8.33% working interest in the Altair Well located in Colorado County, Texas. The Company paid for and holds a 10% interest in this partnership and receives management fees equal to the excess, if any, of the Turnkey Fees over the total cost to the Company of drilling and if applicable, completing the partnership well.

The 2012 Bayou City Squeezebox Offset Program, L.P. (“2012 Squeezebox Offset”) was formed in Kentucky on March 13, 2012 to acquire up to a 5% working interest in the Squeezebox Shallow well located in Cameron Parrish, Louisiana. The Company paid for and holds a 10% interest in this partnership and receives management fees equal to the excess, if any, of the Turnkey Fees over the total cost to the Company of drilling and if applicable, completing the partnership well.

The Opportunity Funds and Affiliated Partners

In April 2011, the Company acquired a 25% ownership interest in Affiliated Partners, a general partnership formed for the purpose of holding an 80% interest in Loanmod, LLC, a Delaware limited liability company (“Loanmod”). Affiliated Partners is also owned by our President, Chief Executive Officer, Chief Financial Officer and director, Stephen Larkin (50%) and our other director, Travis Creed (25%). The Company acquired its interest in Affiliated Partners in exchange for its agreement to serve as the managing member and investment manager of the Opportunity Fund VII, LLC, a Delaware limited liability company (the “Opportunity Fund VII”), which invests in mortgage notes and land contracts secured by real estate. The Company also serves as the managing member and investment manager of the BYCX Opportunity Fund I (“BYCX Fund I”), established in June 2011, and the Opportunity Fund VIII, LLC (the “Opportunity Fund VIII,” and collectively with the other managed funds, the “Opportunity Funds”), established in February 2013, both of which are also Delaware limited liability company that invest in Mortgage Notes and Land Contracts. The purchases of Mortgage Notes and Land Contracts by the Opportunity Funds are facilitated primarily by Loanmod, which receives income as a result in connection with its acquisition of Mortgage Notes and Land Contracts for the Opportunity Funds. In the event that the Opportunity Funds acquire Mortgage Notes and Land Contracts from an unaffiliated party, Loanmod is entitled to a transaction fee from such Opportunity Fund equal to 2.5% of the purchase price of all Mortgage Notes and Land Contracts acquired from such third party.

The BYCX Fund I was organized on June 28, 2011 with the objective of investing in a managed portfolio comprised of Mortgage Notes and Land Contracts secured by real estate to provide members with quarterly cash distributions. The subscription periods in which units were offered for sale in the Opportunity Funds have closed. Fund VI, BYCX Fund I and Opportunity Fund VII are participants in a “Holding Fund” called 2011-12 Opportunity Fund 6-1, LLC, which is managed by the Company and Blue Ridge Group, Inc. As of January 2013, Fund VI owns approximately 52% of the Holding Fund, BYCX Fund I owns approximately 28% of the Holding Fund and Opportunity Fund VII owns approximately 20% of the Holding Fund. The Holding Fund has acquired 437 Mortgage Notes and Land Contracts with unpaid balances totaling approximately $15,807,695. The Holding Fund was capitalized with approximately $10,632,660 as of December 31, 2012. The first quarterly distributions from the Holding Fund were made in January 2012 and as of January 2013 a total of approximately $838,634 has been distributed to Holding Fund members.

Competition, Markets and Regulations

Competition in the Oil and Gas industry: The oil and gas industry is highly competitive in all its phases. The sale of interests in oil and gas projects, like those sponsored 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 are substantially larger than we are and possess substantially greater financial resources, personnel, and budgets than we do, which may affect our ability to compete.

Competition in the Mortgage Notes and Land Contracts Industry: Our success depends, in large part, on our ability to acquire assets at favorable spreads over our borrowing costs. In acquiring mortgage-related investments, we compete with mortgage REITs, mortgage finance and specialty finance companies, savings and loan associations, banks, mortgage bankers, insurance companies, mutual funds, institutional investors, investment banking firms, other lenders, governmental bodies and other entities. These entities and others that may be organized in the future may have similar asset acquisition objectives and increase competition for the available supply of mortgage assets suitable for purchase. Additionally, our investment strategy is dependent on the amount of financing available to us in the repurchase agreement market, which may also be impacted by competing borrowers. Our investment strategy will be adversely impacted if we are not able to secure financing on favorable terms, if at all.

Oil and Gas Markets: The price obtainable for oil and gas production from our properties and the oil and gas partnerships we manage is affected by market factors beyond our control. 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 our properties. Changes in oil and gas prices can impact our determination of proved reserves as well as our 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 levels of production obtained by our properties. 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 we 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.

Mortgage Notes and Land Contracts Market: There are a number of firms, institutions and individuals who buy Mortgage Notes and Land Contracts similar to those purchased by the Opportunity Funds. Some of the buyers have substantially greater financial, technical and other resources than the Opportunity Funds.

Environmental Regulation

As the managing general partner of the Company’s drilling partnerships, our 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 our financial position and business operations. 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 our operations or financial condition cannot be predicted, but are likely to increase. Furthermore, if any penalties or prohibitions were imposed upon us for violating such regulations, our operations would be adversely affected.

The oil and gas partnerships we sponsor and manage hold interests in properties upon which each partnership has or intends 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 the partnerships we manage 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 oil and gas 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.

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 our 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 our oil and gas holdings.

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 our oil and gas interests will be significantly affected by FERC Order No. 500. Gas produced from our 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.

Regulation of Mortgage Notes and Land Contracts

The U.S. Government, through the U.S. Federal Reserve, the Federal Housing Administration (“FHA”), and the Federal Deposit Insurance Corporation, has implemented a number of federal programs designed to assist homeowners, including the Home Affordable Modification Program, or HAMP, which provides homeowners with assistance in avoiding residential mortgage loan foreclosures, the Hope for Homeowners Program, or H4H Program, which allows certain distressed borrowers to refinance their mortgages into FHA-insured loans in order to avoid residential mortgage loan foreclosures, and the Home Affordable Refinance Program, or HARP, which applies to loans sold or guaranteed by government-sponsored enterprises on or prior to May 31, 2009, allows borrowers who are current on their mortgage payments to refinance and reduce their monthly mortgage payments, with no current loan-to-value ratio upper limit and without requiring new mortgage insurance. HAMP, the H4H Program and other loss mitigation programs may involve, among other things, the modification of mortgage loans to reduce the principal amount of the Mortgage Notes and Land Contracts held by the Opportunity Funds (through forbearance and/or forgiveness) and/or the rate of interest payable on the loans, or the extension of payment terms of the loans. A significant number of loan modifications with respect to loans in the Opportunity Funds’ portfolios that have not already been modified could result in increased prepayment rates and negatively impact the realized yields and cash flows on such loans. These loan modification programs, future legislative or regulatory actions, including possible amendments to the bankruptcy laws, which result in the modification of outstanding residential mortgage loans, as well as changes in the requirements necessary to qualify for refinancing mortgage loans with Fannie Mae, Freddie Mac or Ginnie Mae, may adversely affect the value of, and the returns on, residential Mortgage Notes and Land Contracts held by the Opportunity Funds.

In response to the financial issues affecting the banking system and financial markets and going concern threats to commercial banks, investment banks and other financial institutions, the Emergency Economic Stabilization Act, or EESA, was enacted by the U.S. Congress in 2008. There can be no assurance that the EESA or any other U.S. Government actions will have a beneficial impact on the financial markets. To the extent the markets do not respond favorably to any such actions by the U.S. Government or such actions do not function as intended, our business may not receive the anticipated positive impact from the legislation and such result may have broad adverse market implications.

In July 2010, the U.S. Congress enacted the Dodd Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, in part to impose significant investment restrictions and capital requirements on banking entities and other organizations that are significant to U.S. financial markets. For instance, the Dodd-Frank Act imposes significant restrictions on the proprietary trading activities of certain banking entities and subjects other systemically significant organizations regulated by the U.S. Federal Reserve to increased capital requirements and quantitative limits for engaging in such activities. The Dodd-Frank Act also seeks to reform the asset-backed securitization market (including the mortgage-backed securities market) by requiring the retention of a portion of the credit risk inherent in a pool of securitized assets and by imposing additional registration and disclosure requirements. Certain of the new requirements and restrictions exempt agency securities, other government issued or guaranteed securities, or other securities. Nonetheless, the Dodd-Frank Act also imposes significant regulatory restrictions on the origination of residential mortgage loans and will impact the formation of new issuances of non-agency securities. The Dodd-Frank Act has also created a new regulatory bureau, the Consumer Financial Protection Bureau, or the CFPB, which now oversees many of the core laws which regulate the mortgage industry, including among others, the Real Estate Settlement Procedures Act and the Truth in Lending Act. While the full impact of the Dodd-Frank Act and the role of the CFPB cannot be assessed until all implementing regulations are released, the Dodd-Frank Act's extensive requirements may have a significant effect on the financial markets, and may affect the availability of mortgage pools being traded and the prices at which loans are purchased and sold. Restrictions on loan trading could have an adverse effect on the Opportunity Funds and the the Mortgage Notes and Land Contracts held by them.

State Regulations

Production of oil and gas from our oil and gas holdings is affected by state regulations. States in which we operate 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 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 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.

Employees

We currently have one employee, Stephen C. Larkin, our President, Chief Executive Officer and Chief Financial Officer, who is employed by the Company full time. From time to time we may engage outside consultants to perform service on the Company’s behalf. In addition, we often utilize the resources of Blue Ridge Group, Inc., with whom we share common management. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

Additional Information

We are required to file annual reports on Form 10-K and quarterly reports on Form 10-Q with the Securities and Exchange Commission (the “SEC”) on a regular basis, and are required to disclose certain material events in a current report on Form 8-K. The public may read and copy any materials that we file with the SEC at the Public Reference Room at the SEC located at 100 F Street NE, Washington, DC 20549, on official business days during the hours of 10 a.m. to 3 p.m. The public may also obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. In addition, our periodic reports may be found on our website, www.bcexploration.com. We will make available to any stockholder, without charge, copies of any filings not otherwise available on our website. For copies of 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.

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

Our principal office is located at 632 Adams Street — Suite 700, Bowling Green, Kentucky 42101, in office space leased from GC Royalty, LLC and shared with Blue Ridge Group, Inc. (“Blue Ridge Group”), which has common employees with the Company. GC Royalty, LLC is owned by Robert and Doris Burr, who collectively beneficially own 29.79% of the Company’s Common Stock. For the year ended December 31, 2012, the space we occupy, which encompasses 24,205 square feet of office and general storage space, was leased by Blue Ridge Group, and used by the Company pursuant to a management arrangement pursuant to which the Company paid Blue Ridge approximately $44,000 per year for use of office space and certain general and administrative duties. In November 2012, the Company executed a new lease for this same space, which became effective January 1, 2013 for a base monthly rent of $15,000. The new lease will expire at the end of 2016. While we believe comparable office space would be available to us on commercially reasonable terms, in the event we were not able to continue to use our current office space, it is likely new space would be acquired on substantially different terms.

During 2011, the Company leased two office suited located at 303 S. Jupiter Road, Allen, Texas 75002. On October 10, 2011, the Company signed an agreement with RMB Jupiter Office Park, Ltd. (the “Landlord”), wherein the Company agreed to move from the two office suites previously leased into one larger suite of approximately 2,041 square feet for $2,891.50 per month. The lease, which was amended on October 10, 2011, extends a lease previously held by the Company and is for a five (5) year term that began November 1, 2011. In the event this office space becomes unavailable, we believe comparable office space would be available on substantially similar terms.

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 2012 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, 2012, based upon a report prepared by Pressler Petroleum Consultants, Inc. (“PPC”). All of the Company’s proved reserves are located in the United States.

Summary of Oil and Gas Reserves as of December 31, 2012

					Future Net Revenue, $
Reserve Category	Oil (Bbls*)		Gas (Mcf**)		Undiscounted		Present Worth at 10%
Proved Developed Producing		5,400		68,180	$	612,240	$	544,710
Proved Developed Non-Producing		0		0		0		0

Total Net Proved Reserves		5,400		68,180	$	612,240	$	544,710

*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 $94.71 per barrel of oil for West Texas Intermediate oil at Cushing, Oklahoma, and $2.849 per thousand standard cubic feet of 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.

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 date 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 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 their 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 Director, President Chief Executive Officer and Chief Financial Officer, Stephen C. Larkin. Mr. Larkin has been working with oil and gas companies since he began his position with Blue Ridge Group, Inc. in 2008. 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. Stan S. Valdez, P.E. and Mr. Andrew Tharp, E.I.T. of PPC. Mr. Valdez has over 16 years of practical experience in the estimation and evaluation of petroleum reserves, as well as continuing education concerning the estimating and auditing of oil and gas reserves. He holds a B.S. in Petroleum Engineering from Texas A&M University. Mr. Reis is a qualified reserves estimator as set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. Mr. Tharp has over one year of practical experience in the estimation and evaluation of oil and gas reserves and holds a B.S. in Petroleum Engineering from the University of Texas at Austin.

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 2012, 2011, and 2010 the average selling price for natural gas was $3.66, $5.06, and $4.44 per Mcf, respectively, and the average selling price for oil was $92.45, $75.69, and $58.47 per barrel, respectively.

	Net		Net		Net
	Production		Production		Production
	For the Year		For the Year		For the Year
	12/31/2012		12/31/2011		12/31/2010
Net Volumes (Equivalent Barrels)		5,277		2,412		7,489
Average Sales Price per Equivalent Barrel	$	26.47	$	54.17	$	33.79
Average Production Cost per Equivalent Barrel (includes production taxes)	$	15.72	$	20.01	$	6.79

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.

In 2012, three partnerships were formed that are managed by the Company and they drilled a total of one exploratory well and one developmental well, one of which is currently in production, and one of which was determined to be a dry hole. There was also one exploratory well drilled in 2012 outside of the managed partnerships that started into production in October 2012. In 2011, the six partnerships managed by the Company drilled a total of seven exploratory wells and one developmental well, four of which are currently in production, one was determined to be in dry hole, and two produced for a short period of time and then became unviable. In 2010, the one partnership managed by the Company at the time drilled one exploratory well that was determined to be a dry hole and the Company drilled one developmental well outside of the managed partnerships that is currently in production.

Present Activities.

The Company formed three new oil and gas drilling partnerships in 2012. The partnerships drilled four wells, one began producing in 2012, one was deemed a dry hole, and the remaining two wells began production in January 2013.

Delivery Commitments.

The Company is not currently committed to providing a fixed and determinable quantity of oil or gas under any existing contract or agreement.

Oil and Gas Properties, Wells, Operations and Acreage.

During 2012, the Company participated in the drilling of three new wells, one of which was determined to be a dry hole and has been plugged and abandoned. See “Drilling and Other Exploratory and Development Activities” above.

As of December 31, 2012, the Company owned a direct working interest in six producing wells, including the Rooke #2, the Squeeze Box #1, the Kleimann #1, the Prairie Bell East, the Loma Blanca, and the Koehn #2. Two other wells in which the Company owns working interest have been drilled, one was a dry hole and the other produced for nine months and dried up in October 2012. The Company drilled one dry hole that was plugged and abandoned. The Rooke #1, which stopped producing in October 2010, was converted into a salt water disposal well in 2011 and has yet to be plugged and abandoned.

The following tables summarize by geographic area the Company’s developed acreage and gross and net interests in producing oil and gas wells as of December 31, 2012. The Company did not hold any undeveloped acreage at December 31, 2012. Productive wells are producing wells and wells mechanically 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

Louisiana		319.52		2.49		-0-		-0-

Texas		2,117.44		76.52		-0-		-0-

Totals		2,436.96		79.01		-0-		-0-

PRODUCTIVE WELLS

	Gross Wells				Net Wells
Geographic Area:	Oil		Gas		Oil		Gas

Louisiana		0		1		0		.01

Texas		2		3		.02		.21

Totals		2		4		.02		.22

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, 2012.

Developed Properties

Rooke #2: The Company owns a 9.5% working interest in one well located in Refugio County, Texas, which began production in May 2010. The well produces about six Bbls per day.

Kleimann #1: The Company owns a 0.26% working interest in the Kleimann #1, a well located in Colorado County, Texas. Production started on March 6, 2012 and the well is currently producing approximately 250 Mcf and six Bbls per day.

Squeeze Box: The Company owns a 0.78% working interest in the Squeezebox well. This gas well is located in Cameron Parish, Louisiana, and began production in November 2011. The well produces about 1,286 Mcf and 12 Bbls per day.

Prairie Bell East: The Company owns a 0.49% working interest in the Prairie Bell East well, a gas well is located in Colorado County, Texas. The well has been in production since February 27, 2012 and has been producing approximately 1,522 Mcf and 53 Bbls per day.

Loma Blanca: The Company owns a 0.59% working interest in the Loma Blanca well, which well is located in Brookes County, Texas. The well has been in production since August 2012. The well produces about 112 Mcf per day.

Koehn #2: The Company owns an 11.00% working interest in the Koehn #2 well, which is located in Colorado County, Texas. This well has been in production since October 2012. The well produces about 93 Bbls and 533 Mcf per day.

Key Undeveloped Properties

On August 29, 2011, the Company invested $190,000 and entered into the Next Energy Illinois Basin Oil & Gas Lease Development JV (“Next Energy JV”), a joint venture with Next Energy, LLC and other industry participants to evaluate, test and purchase mineral leases in the Illinois Basin. The venture is targeting up to 300,000 net acres of oil and gas leases. The investment entitles the Company to 0.005% of the joint venture. The Company does not own a direct interest in any of the acreage, but rather an interest in a joint venture that holds undeveloped acreage.

Dry Holes and Abandonment of Properties during 2012

In 2012, the Company incurred $128,344 in dry hole or abandonment expenses. The expenses incurred were from a dry hole drilled by one of the partnerships managed by the Company in 2011, the Company also had a large direct interest in the well.

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 stockholders are a party adverse to us or have a material interest adverse to us.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

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, 2011	$	0.00	$0.00
June 30, 2011		0.00	0.00
September 30, 2011		0.00	0.00
December 31, 2011		0.00	0.00

March 31, 2012	$	0.035	$0.025
June 30, 2012		0.045	0.012
September 30, 2012		1.15	0.10
December 31, 2012		0.60	0.36

According to OTC Market Groups, Inc., there were no bid or ask prices for our Common Stock during the 2011 fiscal years. The closing bid prices for the quarters ended September 30 and December 31, 2012, reflect prices following the Company’s 1 for 100 reverse stock split, which occurred on July 26, 2012.

Stockholder Information

As of March 21, 2013, there were 549 stockholders of record of the Company’s Common Stock. The number of registered stockholders excludes any estimate by us of the number of beneficial owners of shares of Common Stock held in “street name.”

Dividend Information

No cash dividends have been declared or paid on our Common Stock since 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. Our 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

All of the Company’s recent sales of unregistered securities within the past three years have been previously reported in Quarterly Reports on Form 10-Q and current reports on Form 8-K.

Securities authorized for issuance under equity compensation plans

The following table sets forth certain information, as of December 31, 2012, 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		20,000	$	1.00		21,500
Equity compensation plans not approved by security holders		–		–		–
Total		20,000	$	1.00		21,500

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 of the yearly periods ended December 31, 2012 and 2011. The financial statements and the notes thereto contain detailed information that should be referred to in conjunction with the following discussion.

Recently Issued Accounting Pronouncements

During the year ended December 31, 2012 and through April 11, 2013, there were several new accounting pronouncements issued by the Financial Accounting Standards Board (FASB). Each of these pronouncements, as applicable, has been or will be adopted by the Company. Management does not believe the adoption of any of these accounting pronouncements has had or will have a material impact on the Company’s consolidated financial statements.

Consolidation Policy

The Company consolidates its interest in joint ventures and partnerships in the oil and gas industry using the ‘proportionate consolidation’ method provided for in Accounting Standards Codification (ASC) Topic 810-10-45-14, Consolidation – Other Presentation Matters. A proportionate consolidation is permitted when the Company does not control the joint venture or partnership but nonetheless exercises significant influence. Under this method, the Company recognizes their proportionate share of each partnership’s assets, liabilities, revenues and expenses, which are included in the appropriate classifications on the Company’s consolidated financial statements.

All significant intercompany transactions of its consolidated subsidiary and the limited partnerships are eliminated.

Critical Accounting Policies and Estimates

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, there was no stock compensation expense to be recognized in the year ended December 31, 2012 and stock compensation expense of $11,008 was required to be recognized in the year ended December 31, 2011.

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.

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 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 $816,410 in 2012, as compared to a net income of $257,114 in 2011. The $559,296 increase in net income resulted from the Company recording $1,339,503 more in total operating revenues, offset by $882,004 more in operating costs and a net increase in other income of $134,669 in 2012 as compared to 2011. On a per share basis the Company had a net income of $0.95 per share in 2012 and a net income of $0.89 per share in 2011.

Operating Revenues: Operating revenues totaled $3,312,772 in 2012 as compared to $1,973,269 in 2011, a 67.9% increase for the year. The increase in total operating revenue was primarily a result of a change in the Company’s business focus during 2011, wherein $3,132,676 of the Company’s revenues were derived from net turnkey drilling contract revenue in 2012, while in 2011, the Company had $1,839,915 of turnkey drilling contract revenue. In 2012, the Company’s revenues from oil and gas sales also increased $46,742 compared to 2011 which was a result of increased production primarily from the Koehn #2 well, which began production in the October 2012.

Direct Operating Costs: Direct operating costs for the producing oil and gas wells, which include lease operating expenses and production taxes, totaled $47,021 in 2011 compared to $75,527 in 2012. This 60.6% increase in expense is primarily due to increased lease operating expenses on the Coastal Plains wells’ which are approaching the end of their useful life.

Other Operating Expenses: Other operating expenses include abandonment and dry hole costs, marketing costs, depreciation, depletion, and amortization expense, turnkey drilling contract costs and marketing. Other operating expenses decreased to $420,607 in 2012 compared to $434,852 in 2011. This decrease of $14,245 was a result of a $33,217decrease in depletion and amortization, and a $74,337 decrease in marketing costs, offset by an increase of $93,309 in abandonment and dry hole costs.

General and Administrative Costs: General and administrative costs were $716,124 in 2012 compared to $636,995 for 2011, an increase of $79,129, or approximately 12.42%. The increase was primarily attributable to increases office rent with related costs, and legal and audit fees related to the SEC filings and review of the Company’s limited partnership offerings, and includes a quarterly management fee of approximately $11,000 payable to Blue Ridge Group, Inc., with whom we share office space and utilize various accounting-related and administrative services.

Other Income: The Company’s Other Income increased $119,931 during the year ended December 31, 2012. This increase in other income was primarily a result of $150,099 in equity earnings received by the Company for its holdings in Affiliated Partners, which was purchased during 2012, offset by $22,799 in miscellaneous expenses. In contrast, during 2011, the Company had net other expense of $7,369 including $631 worth of miscellaneous income and $8,000 of interest expense.

Income Taxes: In 2012 the Company had $32,872 in federal or state income tax liability and no income tax liability or benefit in 2011 as a result of a large net operating loss carry forward from years 2011 and prior. Based on the amount of net losses in 2011 and prior, a full valuation allowance has been recorded against the deferred tax assets associated with the net operating loss carry forwards. The Company had an estimated net operating loss carry forward of $7,264,508 and $8,004,196 as of December, 31, 2012 and 2011, respectively. However, the Company had an ownership change in March, 2012 with the issuance of additional shares in a private placement transaction. This resulted in an Internal Revenue Code (IRC) Section 382 limitation on the availability of the Company’s net operating losses immediately before the ownership change to operational periods following the date of the ownership change. The Section 382 limitation rule limits the use of the Company’s current net operating loss carry forward to $30,193 per year in future years. This annual limitation was allocated in the year 2012 to the period following the change date and resulted in net operating losses available for the time period of April through December, 2012, being limited to $22,645 and the above tax liability for 2012 of $32,872.

Balance Sheet Review

Assets: The Company’s total assets increased $977,203 from $2,218,336 as of December 31, 2011 to $3,195,539 as of December 31, 2012. The increase was primarily attributable to a $591,439 increase in current assets during 2012, from $1,778,140 as of December 31, 2011 to $2,369,579 as of December 31, 2012. The increase was attributable to an $827,546 increase in cash received from Turnkey Agreements entered into between the Company and partnerships we sponsored, as well as increases in accounts receivable of $151,179. The increase in total current assets was offset in part by a $387,286 decrease in pre-paid expenses from 2011 to 2012. The $385,764 additional increase in the Company’s assets was a result of a $184,015 increase in oil and gas properties as compared to 2011, a $57,017 increase in other investments at cost during 2012, and a $150,099 investment in an unconsolidated affiliate company in which we did not hold an interest during 2011, partially offset by decrease in the Company’s other fixed assets, which deceased a $5,367, from $25,047 during 2011 to $19,680 for the year ended December 31, 2012.

Liabilities: The Company’s liabilities decreased $197,207 in 2012 to $1,384,913 as of December 31, 2012 compared to $1,582,120 as of December 31, 2011. The majority of this decrease is the result of a $659,763 decrease in turnkey partnership obligations, due to a decrease in the number of limited partnerships formed, from six in 2011 to only three in 2012. There was also a $100,752 decrease in accounts payable and accrued expenses, offset by a $530,611 accounts payable to related parties and $32,697 in federal income taxes payable during 2012. The Company did not owe income taxes for 2011. The accounts payable to related parties is attributable to the amounts received by the Company as the result of Turnkey Agreements it has with the partnerships it sponsors and manages. The amounts received under such Turnkey Agreements are booked as revenue, but considered a deferred liability until such time as the Company has completed all its responsibilities under the Turnkey Agreements.

There was $84,906 in deferred liability and a $100,000 note payable obligation to a minority stockholder remained unchanged from period to period.

Stockholders’ Equity: Total stockholder’s equity of the Company increased $1,174,410, from $636,216 at December 31, 2011 to $1,810,626 at December 31, 2012. This increase is mainly the result of a net operating profit of $932,744 and an issuance of stock in the amount of $327,500 during 2012.

Liquidity and Capital Resources

The Company’s current ratio (current assets / current liabilities) was 1.12 to 1 as of December 31, 2011 compared to 1.71 to 1 as of December 31, 2012. The change in the current ratio from 2011 to 2012 is the result a significant increase in current assets due to the cash on hand the Company holds as a result of certain Turnkey Agreements.

The Company saw a significant change in its liquidity during the year ended December 31, 2012, which was primarily the result of implementing a new business plan that started in 2010, in which we serve as the sponsor and managing general partner of partnerships formed for the purpose of undertaking oil and gas exploration activities. During 2011, in contrast, the Company sponsored an additional five limited partnerships, for which it serves as the managing general partner and has received revenues from Turnkey Agreements with such partnerships, wherein for a fixed price the Company agrees to drill, test and, if advisable, complete, oil and wells in which each partnership holds an interest. Generally, the amount charged by the Company to undertake these exploration activities under a Turnkey Agreement exceeds the total costs paid by the Company to complete such operations. When the Company receives payment from a partnership for the services it agrees to perform under a Turnkey Agreement, it records any amounts received as revenue. However, such amounts are also considered a deferred liability on the Company’s balance sheets until such time as the Company’s obligations under the Turnkey Agreement are completed. As of December 31, 2012, the Company recorded $3,132,676 in net turnkey drilling contract revenue, and had a deferred liability of $582,746. As the Company continues to sponsor and manage partnerships, it expects that the revenues received from Turnkey Agreements will enable it to continue to meet its financial obligations and be profitable. To the extent the Company is unable to successfully sponsor additional partnerships, it may have difficulty continuing operations.

The Company also anticipates it will earn revenue over time from its direct oil and gas holdings, including holdings in oil and gas wells held by the limited partnerships it manages. In 2012, the Company purchased an 11% working interest in the Koehn #2 which started into production in October 2012 and is currently producing average net revenue in excess of $28,000 per month. In addition, the Company seeks to generate revenue from joint ventures with other oil and gas companies, such as the Next Energy JV, in which it participated in 2011. To date, however, the Company’s revenues from its oil and gas holdings and other investments have been very limited, and it is dependent upon the revenues it receives from Turnkey Agreements in order to continue its operations, which during 2012 were sufficient to pay the Company’s operating expenses. The Company believes that revenue from Turnkey Agreements will be sufficient to fund their ongoing business; and based on previous years’ expenses, the Company’s current cash resources will be enough to fund their operations for the next twelve months.

As of December 31, 2012, the Company’s cash balance was $2,087,480 and its liabilities totaled $1,384,913, which include $582,746 of deferred liability associated with obligations it has under current Turnkey Agreements, $530,611 in accounts payable to related party to pay for an interest in partnership wells, and approximately $184,906 in related party accounts payable and notes outstanding to a minority stockholder. At December 31, 2012 the Company had total working capital of $1,045,113 and no contractual obligations that will encumber its cash flow into the future.

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, 2012 and 2011, the Company was not involved in any unconsolidated SPE transactions nor 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

All financial statements required by this Item are listed in Part IV, Item 15 of this Form 10-K, are presented beginning on Page F-1, and are incorporated herein by this reference.

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 not effective due to the inherent limitations describe below, 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 disclosures.

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 in rule 13a-15(f) o 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 limitation, 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, 2002. 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 not effective in that there was a material weakness as of December 31, 2012.

A material weakness is a deficiency or combination of deficiencies in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis by the Company’s internal controls.

The Company’s management has identified a material weakness in the effectiveness of internal control over financial reporting related to a shortage of resources in the accounting department required to assure appropriate segregation of duties with employees having appropriate accounting qualifications related to the Company’s unique industry accounting and disclosure rules.

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, 2012, 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 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 and accounting personnel with appropriate qualifications 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.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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 stockholders 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

Stephen C. Larkin	53	Director, President, Chief Executive Officer and Chief Financial Officer	2010

Travis Creed	46	Chairman	2010

STEPHEN C. LARKIN, age 53, was elected to serve as our President and Chief Executive Officer effective as of November 30, 2012 and has served 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 beginning in July 2008 until his appointment as its President in November 2010. From September 1998 until September 2007, Mr. Larkin served as President and Chief Executive Officer of Sensus Precision Die Casting, Inc. and President, Chief Executive Officer 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 Chief Financial Officer of one of its divisions (for seven years), to Vice President of Operations (for four years) then finally with Sensus Precision Die Casting Company as their President and Chief Executive Officer. Prior to that Mr. Larkin spent almost six years with Ernst and Young, LLP both in the Lansing, Michigan office and the Tampa Bay, 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, a Master of Business Administration degree from Michigan State University in Operations Management in 1989 and an Executive Master of Business Administration from the University of New Hampshire in International Business in 1997. Mr. Larkin became a Certified Public Accountant in May 1982 in the State of Florida.

TRAVIS N. CREED, age 46, was appointed to serve as a director of the Company in July 2010. Since 2007, Mr. Creed has also served 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. Mr. Creed is a licensed to practice law in the State of Arkansas, however, he has been voluntarily inactive since 2007 and does not presently engage in the practice 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.

Family Relationships

There are no family relationships between any of our directors and executive officers.

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 2012, 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. Kevin Cline, who was appointed to serve as a director of the Company on June 26, 2012, filed one late Form 3 on November 27, 2012. Robert D. Burr, a stockholder owning greater than 10% of the Company’s common stock as of March 8, 2012, filed one late Form 3 on March 28, 2012.

Code of Ethics for Financial Executives

On April 14, 2011, the Company's Board of Directors approved a Code of Ethics that applies to the Company’s principal officers. 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 42101.

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.

ITEM 11. Executive Compensation

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, 2012.

SUMMARY COMPENSATION TABLE

		Salary		Bonus		Total
Name and Principal Position	Year	($)		($)		($)
Charles T. Bukowski	2012		110,000		–	$	110,000
Former President and Chief Executive Officer	2011		120,000		–	$	127,405
Stephen C. Larkin,	2012		92,500		27,750	$	120,250
President, Chief Executive Officer and Chief Financial Officer	2011		90,000		–	$	94,653

Narrative Disclosure to Summary Compensation Table

Charles Bukowski, the Company’s former President and Chief Executive Officer, received a base salary of $120,000, which he began receiving in July 2010. However, Mr. Bukowski resigned on November 30, 2012. Our President, Chief Executive Officer, and Chief Financial Officer, Stephen Larkin, currently receives a base salary of $120,000 per year. This was increased on December 1, 2012 from a previous salary of $90,000 per year. As part of the Company’s compensation package, its officers are from time to time awarded stock options. In 2009, 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 2009, Mr. Larkin was awarded an option to purchase 10,000 shares of common stock at an exercise price of $0.01 per share. Mr. Larkin’s options vested over a two year period. The stock option awards were issued pursuant to the Company’s 2005 Stock Option and Incentive Plan. In 2010, Mr. Bukowski was awarded 5,000 stock options in connection with his appointment as the Company’s President and Chief Executive Officer. Mr. Bukowski’s options vested over a two-year period and have a $0.05 exercise price. Each of the named executive officers’ stock option awards have a ten year term, beginning on the award date. However, after Mr. Bukowski’s resignation on November 30, 2012, his stock options expired thirty days later on December 30, 2012.

In July 2010, the Board of Directors, in connection with the appointment of Charles Bukowski as the Company’s now former President and Chief Executive Officer, passed a corporate resolution establishing a bonus program for the Company’s Chief Executive Officer and Chief Financial Officer. The resolution established that for the first $500,000 in pre-tax income the Company makes after July 1, 2010, the Company will pay each of the officers 20% of their base salary and for each $250,000 the Company makes in pre-tax income thereafter, the Company will pay an additional bonus equal to 10% of the officer’s base salary. The bonus is to reset on January 1^st of each year. During 2011, the Company failed to reach the $500,000 threshold, however in 2012 the company reached over the $750,000 threshold and accordingly Stephen Larkin was paid a bonus of $27,750, which is based on 30% of his gross earnings for 2012, on March 14, 2013.

Employment Agreements

There were no employment agreements in place as of December 31, 2012.

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 Stock Option 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 seventy thousand (70,000) common shares of which approximately 21,500 shares remain available for grant as of December 31, 2012. 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, 2012.

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

OPTION AWARDS

Number of
Securities
Underlying
Unexercised
Options
(#)

Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options

Option Exercise Price

Option Expiration

Name

Exercisable

Unexercisable

(#)

($)

Date

Stephen C. Larkin

President, CEO and CFO

10,000

–

1.00

05/18/19

Travis N. Creed

Chairman

5,000

–

1.00

05/18/19

Director Compensation

During 2012, the directors of the Company were not compensated for their services as directors of the Company.

Compensation Committee Interlocks and Insider Participation

The Company does not currently maintain separate compensation committee. When necessary, the entire Board of Directors performs the tasks that would be required of a compensation committee. Stephen C. Larkin, our President, Chief Executive Officer and Chief Financial Officer and sole employee, also serves on the Board of Directors and participated in deliberations of the Board of Directors concerning executive officer compensation. Moreover, Mr. Larkin also currently serves as a director and the President of Blue Ridge Group, Inc., a company for which Travis N. Creed, the Chairman of our Board of Directors, serves as Senior Vice President - Real Property Division and General Counsel.

Compensation Committee Report

Stephen C. Larkin and Travis N. Creed, who collectively constitute the entire Board of Directors of the Company, perform the tasks that would be required of a compensation committee when necessary. The Board of Directors has reviewed with management the disclosures relating to executive compensation herein and determined that such disclosures should be included in this Annual Report.

ITEM 12.

SECURITIES OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth the ownership, as of March 21, 2013, 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 stockholders 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 990,230 shares of Common Stock outstanding as of March 21, 2013.

Name of Beneficial Owner	Amount and Nature of Beneficial Ownership		Percent of Class
Stephen C. Larkin⁽¹⁾		270,629		27.33%
Travis N. Creed⁽²⁾		35,000		3.53%
All directors, nominees and officers as a group (2 persons)		305,629		30.86%
Robert Burr⁽³⁾		294,981		29.79%
Doris Burr⁽³⁾		294,981		29.79%

(1)

Mr. Larkin’s beneficial ownership interest includes vested options for the purchase of 10,000 shares exercisable within 60 days March 30, 2013, plus 260,629 shares in his personal portfolio.

(2)

Mr. Creed’s beneficial ownership interest includes vested options for the purchase of 5,000 shares exercisable within 60 days March 30, 2013, plus 30,000 shares in his personal portfolio.

(3)

Represents 9,981 shares held by Robert Burr individually and 285,000 shares held jointly with Doris Burr, his spouse. Mr. and Ms. Burr’s address is 1314 Fairview Avenue, Bowling Green, KY 42103.

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 President, Chief Executive Officer, and 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 addition, the Company utilizes the administrative and accounting services of Blue Ridge Group, including the services of its Controller, Paul Larkin, for purposes of compiling the Company’s financial statement information for SEC reporting purposes and for reports made to partners of the partnerships sponsored by the Company. Paul Larkin is the son of Stephen Larkin, the Company’s Chief Financial Officer and a member of the Board of Directors of the Company.

On March 8, 2012, the Company entered into a Stock Purchase Agreement with eight investors (the “Investors”), pursuant to which the Company sold 700,000 shares of the Company’s common stock, $0.005 par value (the “Common Stock”) in a private offering at a price of $0.005 per share, for total consideration to the Company valued at $350,000. The Investors included Charles T. Bukowski, Jr., the Company’s President and Chief Executive Officer, as well as a member of the Company’s Board of Directors (the “Board”), Travis N. Creed, a member of the Board, Stephen C. Larkin, the Company’s Chief Financial Officer and a member of the Board, Robert D. and Doris R. Burr, the Company’s former Chief Executive Officer and his spouse, Danny Looney, the Company’s tax accountant, Harry J. Peters, a consultant to the Company, Robert Shallow, a current stockholder and G2 International, Inc., a consultant to the Company. The consideration for the Common Stock was paid primarily in cash, however, the shares issued to G2 International, Inc. were issued in exchange for settlement of outstanding invoices for consulting services rendered.

In April 2012, the Company acquired a 25% ownership interest in Affiliated Partners, a general partnership formed for the purpose of holding an 80% interest in Loanmod, LLC, a Delaware limited liability company (“Loanmod”). Affiliated Partners is also owned by the Company’s President, Chief Executive Officer, Chief Financial Officer and director, Stephen Larkin (50%) and its other director, Travis Creed (25%). The Company acquired its interest in Affiliated Partners in exchange for its agreement to serve as the managing member and investment manager of the Opportunity Fund VII, LLC, a Delaware limited liability company (the “Opportunity Fund VII”), which invests in Mortgage Notes and Land Contracts secured by real estate. The Company also serves as the managing member and investment manager of the BYCX Opportunity Fund I (“BYCX Fund I”), established in June 2011, and the Opportunity Fund VIII, LLC (the “Opportunity Fund VIII,” and collectively with the other managed funds, the “Opportunity Funds”), established in early 2013, subsequent to the date of this Report, both of which are also Delaware limited liability company that invest in Mortgage Notes and Land Contracts. The purchases of Mortgage Notes and Land Contracts by the Opportunity Funds are facilitated primarily by Loanmod, which receives income as a result in connection with its acquisition of Mortgage Notes and Land Contracts for the Opportunity Funds. In the event that the Opportunity Funds acquire Mortgage Notes and Land Contracts from an unaffiliated party, the Company is entitled to a transaction fee from such Opportunity Fund equal to 2.5% of the purchase price of all Mortgage Notes and Land Contracts acquired from such third party.

On June 26, 2012 the Company named Kevin Cline, Source Capital Group’s Managing Principal to its board of directors. Mr. Cline’s appointment was made in connection with the formation of Rivergreen Financial, LLC (“Rivergreen”) a subsidiary formed for the purpose of selling the Company’s managed partnerships and Opportunity Funds, for which Mr. Cline was to serve as President. In November 2012, following the Company’s decision not to utilize Rivergreen as a broker-dealer, Mr. Cline resigned as a board member of the Company. While serving on the board, Kevin was paid $27,375 in non-employee compensation related to fees earned by Source Capital in connection with the Company’s offerings.

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

On June 7, 2012, the Company executed a letter agreement engaging Turner, Stone & Company, L.L.P. (“Turner Stone”) as its independent registered public accounting firm, and terminated the engagement of its former independent registered public accounting firm, KWCO, P.C. (“KWCO”), for geographic convenience. It is not anticipated that the auditors will be present at the Annual Meeting.

Audit Fees

The Company incurred $17,390, in fees from Turner Stone for the review of the second and third 2012 quarterly 10-Q reports, $22,870 from KWCO for review of the first quarter 2012 quarterly 10-Q report, and will pay approximately $30,000 for its annual December 31, 2012 audit. The Company incurred $21,355 in fees from KWCO for the review of the three 2011 quarterly 10-Q reports and $49,453 from KWCO for auditing the Company’s financial statements for December 31, 2011 and review of the annual 10-K.

Audit Related Fees

The Company incurred no fees or expenses for the 2012 and 2011 fiscal years for professional services rendered by Turner Stone or KWCO 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 2012 and 2011 fiscal years for professional services rendered by Turner Stone or KWCO for tax compliance, tax advice, or tax planning.

All Other Fees

We incurred no other fees or expenses for the 2012 and 2011 fiscal years for any other products or professional services rendered by Turner Stone or KWCO other than as described above.

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
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets as of December 31, 2012 and 2011	F-3
Statements of Operations for the years ended December 31, 2012 and 2011	F-4
Statements of Changes in Stockholders’ Equity for the years ended December 31, 2012 and 2011	F-5
Statements of Cash Flows for the years ended December 31, 2012 and 2011	F-6
Notes to Financial Statements	F-7– F20

(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 (incorporated by reference to Ex. 3.3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2010, filed with the Commission on April 15, 2011 (the “2010 10-K”))
3.4	Certificate of Amendment to the Articles of Incorporation of Blue Ridge Energy, Inc. filed October 11, 2004 (incorporated by reference to Ex. 3.4 of the Company’s 2010 10-K)
3.5	Certificate of Amendment to the Articles of Incorporation of Blue Ridge Energy, Inc. filed June 9, 2005 (incorporated by reference to Ex. 3.5 of the Company’s 2010 10-K)
3.6	Certificate of Amendment to the Articles of Incorporation of Bayou City Exploration Inc. filed July 9, 2012 (incorporated by reference to Appendix A to the Company’s Schedule 14C Information Statement filed with the Commission on July 6, 2012)
3.7	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 (incorporated by reference to Ex. 10.1 of the Company’s 2010 10-K)
10.2	Limited Partnership Agreement of Bayou City Louisiana Drilling Program, L.P. dated July 8, 2010 (incorporated by reference to Ex. 10.2 of the Company’s 2010 10-K)
10.3	Turnkey Drilling Contract between Bayou City Exploration, Inc. and Bayou City Louisiana Drilling Program, L.P. dated July 8, 2010 (incorporated by reference to Ex. 10.3 of the Company’s 2010 10-K)
10.4	Limited Partnership Agreement of 2011 Bayou City Two Well Drilling Program, L.P. dated January 10, 2011(incorporated by reference to Ex. 10.4 of the Company’s 2010 10-K)
10.5	Turnkey Drilling Contract between Bayou City Exploration, Inc. and 2011 Bayou City Two Well Drilling Program, L.P. dated January 10, 2011(incorporated by reference to Ex. 10.5 of the Company’s 2010 10-K)
10.6	Limited Partnership Agreement of 2011-B Bayou City Two Well Drilling Program, L.P. dated March 4, 2011(incorporated by reference to Ex. 10.6 of the Company’s 2010 10-K)
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 (incorporated by reference to Ex. 10.7 of the Company’s 2010 10-K)
10.8	Limited Partnership Agreement of 2011 Bayou City Two Well Drilling and Production Program, L.P. dated March 18, 2011(incorporated by reference to Ex. 10.8 of the Company’s 2010 10-K)
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(incorporated by reference to Ex. 10.9 of the Company’s 2010 10-K)
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) (incorporated by reference to Ex. 10.11 of the Company’s 2010 10-K)
10.12	Non-Qualified Stock Option Agreement between the Company and Stephen Larkin, dated May 18, 2009 (1) (incorporated by reference to Ex. 10.12 of the Company’s 2010 10-K)
10.13	Non-Qualified Stock Option Agreement between the Company and Travis Creed, dated May 18, 2009 (1) (incorporated by reference to Ex. 10.13 of the Company’s 2010 10-K)
10.14	Non-Qualified Stock Option Agreement between the Company and Kevin Cline, dated May 18, 2009 (incorporated by reference to Ex. 10.14 of the Company’s 2010 10-K)
10.15	Non-Qualified Stock Option Agreement between the Company and Charles Bukowski, dated August 3, 2010 (1) (incorporated by reference to Ex. 10.15 of the Company’s 2010 10-K)
10.16	Purchase of Interest Agreement by and between 2009 Production and Drilling Program, L.P. and the Company, dated January 4, 2010 (incorporated by reference to Ex. 10.16 of the Company’s 2010 10-K)

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 (incorporated by reference to Ex. 10.17 of the Company’s 2010 10-K)
10.18	Purchase of Interest Agreement by and between 2009/10 Production & Drilling Program, L.P. and the Company, dated March 1, 2010. (incorporated by reference to Ex. 10.18 of the Company’s 2010 10-K)
10.19	Purchase of Interest Agreement by and between Burrite, Inc. and the Company, dated March 1, 2010 (incorporated by reference to Ex. 10.19 of the Company’s 2010 10-K)
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 (incorporated by reference to Ex. 10.20 of the Company’s 2010 10-K)
10.21	Lease between RMB Jupiter Office Park, Ltd. and Bayou City Exploration, Inc. dated July 15, 2010 (incorporated by reference to Ex. 10.21 of the Company’s 2010 10-K)
10.22	Lease between RMB Jupiter Office Park, Ltd. and Bayou City Exploration, Inc. dated January 15, 2011 (incorporated by reference to Ex. 10.22 of the Company’s 2010 10-K)
10.23	Joint Venture Agreement of Next Energy Illinois Basin Oil & Gas Lease Development JV, dated August 26, 2011(incorporated by reference to Ex. 10.1 of the Company’s quarterly report on Form 10-Q for the period ended September 30, 2011, filed with the Commission on November 14, 2011 (the “September 2011 10-Q)
10.24	Limited Partnership Agreement of 2011 Bayou City Exploration, Inc. and 2011 Bayou City Year End Drilling Program, L.P., dated October 5, 2011 (incorporated by reference to Ex. 10.2 of the September 2011 10-Q)
10.25	Turnkey Drilling Contract between Bayou City Exploration, Inc. and 2011 Bayou City Year End Drilling Program, L.P., dated October 5, 2011 (incorporated by reference to Exhibit 10.3 of the September 2011 10-Q)
10.26	Stock Purchase Agreement, dated March 8, 2012 by and among the Company and the investors named therein (incorporated by reference to Ex. 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on March 9, 2012)
10.27	First Amendment to Lease by and between the RMB Jupiter Office Park and the Company, executed October 10, 2011(incorporated by reference to Ex. 10.27 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2011)
10.28	Limited Partnership Agreement of 2012-A Bayou City Drilling Program, L.P. dated January 2, 2012 (incorporated by reference to Ex. 10.1 of the Company’s quarterly report for the period ended March 31, 2012 (the “March 2012 10-Q”)
10.29	Turnkey Drilling Contract between Bayou City Exploration, Inc. and 2012-A Bayou City Drilling Program, L.P., dated January 2, 2012 (incorporated by reference to Ex. 10.2 of the Company’s March 2012 10-Q)
10.30	Limited Partnership Agreement of 2012 Bayou City Squeeze Box Offset Program, L.P. dated April 9, 2012 (incorporated by reference to Ex. 10.4 of the Company’s March 2012 10-Q)
10.31	Turnkey Drilling Contract between Bayou City Exploration, Inc. and 2012 Bayou City Squeeze Box Offset Program, L.P., dated April 9, 2012 (incorporated by reference to Ex. 10.5 of the Company’s March 2012 10-Q)
10.32	Operating Agreement of BYCX Opportunity Fund I , LLC dated June 28, 2011*
10.33	Operating Agreement of Opportunity Fund VII , LLC dated June 30, 2011*
10.34	Operating Agreement of Opportunity Fund VIII , LLC dated February 1, 2013*
10.35	Lease Agreement between Bayou City Exploration and GC Royalty, LLC, effective January 1, 2013*
10.36	Operating Agreement of 2011-12 Opportunity Fund 6-1, LLC, dated October 10, 2012*
14.1	Code of Ethics (incorporated by reference to Ex. 14.1 of the Company’s 2010 10-K)
23.1	Consent of Pressler Petroleum Consultants, Inc.*
31.1	Certification of Principal Executive Officer and Principal Financial Officer of Periodic Report pursuant to Rule 13a-14a/Rule 14d-14(a).*
32.1	Certification of Principal Executive Officer 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.

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/ Stephen C. Larkin
		Stephen C. Larkin
		President, Chief Executive Officer and Chief Financial Officer
		April 16, 2013

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/ Stephen C. Larkin

		Stephen C. Larkin, Director
		April 16, 2013

By:		/s/ Travis N. Creed

		Travis N. Creed, Director April 16, 2013

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Bayou City Explorations, Inc.

Bowling Green, Kentucky

We have audited the accompanying consolidated balance sheet of Bayou City Explorations, Inc. (the “Company”) as of December 31, 2012 and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for the year 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 audit.

We conducted our audit 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Bayou City Explorations, Inc. as of December 31, 2012, and the results of their consolidated operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ Turner, Stone & Company, L.L.P.

Dallas, Texas

April 11, 2013

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders
Bayou City Exploration, Inc.
Bowling Green, Kentucky

We have audited the accompanying balance sheets of Bayou City Exploration, Inc. as of December 31, 2011, and the related statements of operations, stockholders’ equity, 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, 2011, 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/ KWCO, P.C.

KWCO, P.C.

Odessa, Texas

April 9, 2012

F-2

BAYOU CITY EXPLORATION, INC.

BALANCE SHEETS

	December 31,			December 31,
	2012			2011
ASSETS

CURRENT ASSETS:
Cash	$	2,087,480		$	1,259,934
Accounts receivable:
Trade and other		60,790			13,778
Receivable due from partnerships		104,167			–
Prepaid expenses and other		117,142			504,428

TOTAL CURRENT ASSETS		2,369,579			1,778,140

OIL AND GAS PROPERTIES, NET		340,053			156,038
OTHER FIXED ASSETS, NET		19,680			25,047
OTHER INVESTMENTS AT COST		126,128			69,111
INVESTMENT IN UNCONSOLIDATED AFFILIATE COMPANY		150,099			–
INVESTMENTS HELD FOR SALE		190,000			190,000

TOTAL ASSETS	$	3,195,539		$	2,218,336

LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES:
Accounts payable and accrued expenses	$	53,953		$	154,705
Accounts payable - minority shareholder		84,906			84,906
Turnkey partnership obligation		582,746			1,242,509
Accounts payable - related party		530,611			–
Notes payable - minority shareholder		100,000			100,000
Federal income taxes payable		32,697			–

TOTAL CURRENT LIABILITIES		1,384,913			1,582,120

TOTAL LIABILITIES		1,384,913			1,582,120

STOCKHOLDERS' EQUITY:
Preferred stock, $0.001 par value; 5,000,000 shares authorized; No shares issued and outstanding as of December 31, 2012 and December 30, 2011		–			–
Common stock, $0.005 par value; 150,000,000 shares authorized; 990,176 and 290,176 shares issued and outstanding at December 31, 2012 and 2011, respectively		4,951			1,451
Additional paid in capital		13,912,814			13,558,314
Accumulated deficit		(12,107,139	)		(12,923,549	)

TOTAL STOCKHOLDERS' EQUITY		1,810,626			636,216

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,195,539			2,218,336

See accompanying notes to financial statements

F-3

BAYOU CITY EXPLORATION, INC.

STATEMENTS OF OPERATIONS

	For the years ended December 31,
	2012			2011
OPERATING REVENUES:
Oil and gas sales	$	180,096		$	133,354
Turnkey drilling contract revenue		3,132,676			1,839,915

TOTAL OPERATING REVENUES		3,312,772			1,973,269

OPERATING COSTS AND EXPENSES:
Lease operating expenses and production taxes		75,527			47,021
Abandonment and dry hole costs		128,344			35,035
Depletion, depreciation, and amortization		68,689			101,906
Turnkey drilling contract costs		1,378,532			589,918
Marketing costs		223,574			297,911
General and administrative costs		716,124			636,995

TOTAL OPERATING COSTS		2,590,790			1,708,786
OPERATING INCOME		721,982			264,483

OTHER INCOME (EXPENSE):
Miscellaneous income (expense)		(22,799	)		(7,369	)
Equity in earnings from affiliated company		150,099			–

NET INCOME BEFORE INCOME TAX PROVISION		849,282			257,114

Income tax provision		(32,872	)		–

NET INCOME	$	816,410		$	257,114

NET INCOME PER COMMON SHARE - BASIC	$	0.95		$	0.89

NET INCOME PER COMMON SHARE - DILUTED	$	0.93		$	0.89

Weighted average common shares outstanding -

Basic		862,034			290,176

Diluted		874,766			290,176

See accompanying notes to financial statements

F-4

BAYOU CITY EXPLORATION, INC.

STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

	Common Stock						Additional Paid in			Accumulated
	Shares			Amount			Capital			Deficit			Total


Balance at December 31, 2010, as previously reported		29,003,633		$	145,018		$	13,395,739		$	(13,180,663	)	$	360,094
Reverse stock split (100 for 1)		(28,713,597	)		(143,568	)		143,568			–			–
Partial shares issued for stock split		140			1			(1	)		–			–
Balance adjusted at December 31, 2010		290,176			1,451			13,539,306			(13,180,663	)		360,094

Interest on non-interest bearing note payable to shareholder		–			–			8,000			–			8,000
Stock options exercised		–			–			11,008			–			11,008
Net income		–			–			–			257,114			257,114
Balance at 12/31/2011		290,176			1,451			13,558,314			(12,923,549	)		636,216

Stock Issued for cash		655,000			3,275			324,225			–			327,500
Stock Issued for services		45,000			225			22,275			–			22,500
Interest on non-interest bearing note payable to stockholder		–			–			8,000			–			8,000
Net income		–			–			–			816,410			816,410
Balance at 12/31/2012		990,176		$	4,951		$	13,912,814		$	(12,107,139	)	$	1,810,626

See accompanying notes to financial statements

F-5

BAYOU CITY EXPLORATION, INC.

STATEMENTS OF CASH FLOWS

	For the years ended December 31,
	2012			2011

CASH FLOW FROM OPERATING ACTIVITIES:

Net Income (Loss)	$	816,410		$	257,114
Adjustments to reconcile net income to net cash flows used in operating activities:
Depreciation, depletion, and amortization		68,689			101,906
Interest contributed as capital by shareholder		8,000			8,000
Abandoments and dry holes		128,344			–
Equity in earnings of affiliated company		(150,099	)		–
Stock issued for services		22,500			–
Stock option expense		–			11,008
Change in operating assets and liabilities:
Accounts receivable - trade		(47,012	)		6,340
Receivable from partnerships		(104,167	)		–
Prepaid expenses and other		387,286			–
Accounts payable and accrued liabilities		(100,752	)		67,514
Net turnkey partnership obligation		(659,763	)		743,601
Accounts payable--related party		530,611			–
Federal income tax payable		32,697			–

NET CASH PROVIDED BY OPERATING ACTIVITIES		932,744			1,195,483


CASH FLOW FROM INVESTING ACTIVITIES:
Purchase of oil and gas properties		(375,681	)		(402,210	)
Purchase of other fixed assets		–			(25,047	)
Purchase of investment in BYCX opportunity fund		(57,017	)		–

NET CASH USED IN INVESTING ACTIVITIES		(432,698	)		(427,257	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuing stock		327,500			–

NET CASH PROVIDED BY FINANCING ACTIVITIES		327,500			–

NET INCREASE IN CASH		827,546			768,226

CASH AT BEGINNING OF YEAR		1,259,934			491,708

CASH AT END OF YEAR	$	2,087,480		$	1,259,934

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

Cash paid for interest	$	–		$	–

Cash paid for federal income taxes	$	–		$	–

See accompanying notes to financial statements

F-6

BAYOU CITY EXPLORATION, INC.

NOTES TO FINANCIAL STATEMENTS

December 31, 2012 and 2011

1. OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Bayou City Exploration, Inc., a Nevada corporation (the “Company”), was organized in November 1994, as Gem Source, Incorporated and in June 1996 changed the Company’s name to Blue Ridge Energy, Inc. On June 8, 2005, the Company again changed its name to Bayou City Exploration, Inc.

The Company is primarily engaged in the oil and gas exploration business, and focuses its operations in the gulf coast of Texas, east Texas, south Texas, and Louisiana.

The Company also serves as the Managing Member and Investment Manager of funds organized as limited liability companies to acquire portfolios of mortgage notes and land contracts secured by real estate (the “Mortgage Notes and Land Contracts”). Nevertheless, most of its business resources are focused upon the management of partnerships created to explore and develop oil and gas reserves. The Company manages partnerships that purchase interests in exploratory wells and/or interests in producing oil and gas properties with undrilled reserves. The Company’s growth strategy is based on sponsoring partnerships in which third party investors purchase an interest. These partnerships then assume the costs associated with the drilling of oil and gas wells in exchange for unit interests in a partnership that holds a portion of the working interest derived from the wells they finance. The Company acts as the Managing General Partner for these partnerships and typically maintains a partnership interest in such partnerships, but may also maintain 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 allows for a reduction of financial risk associated with drilling new wells, enabling us to earn income from present production in addition to income from any successful new drilling. As of December 31, 2012, the Company held interest in eight partnerships.

Oil and Gas Drilling Partnerships and Properties

When the Company undertakes a drilling project, a calculation is made to estimate the costs associated with drilling the project well(s). 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 (each, a “Turnkey Agreement”). 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.

As of December 31, 2012, the Company served as the managing general partner of eight limited partnerships formed for the purpose of oil and gas exploration and drilling. The Company has entered into Turnkey Agreements with each of these partnerships pursuant to which it receives turnkey fees for drilling the partnerships’ wells and, if applicable, completing the wells (the “Turnkey Fees”).

In addition to our current business strategy described above, the Company also owns an interest in Affiliated Partners and manages certain Opportunity Funds (described below) in addition to certain oil and gas interests outside of the interests in the partnerships it sponsors that have developed into revenue producing properties as well as an interest in a lease development joint venture to develop properties located in the Illinois Basin. The Company uses the cash generated by these oil and gas interests in addition to the revenues from our direct investment partnerships to cover its ongoing operational needs and restructuring of the balance sheet.

F-7

The Opportunity Funds and Affiliated Partners

In April 2011, the Company acquired a 25% ownership interest in Affiliated Partners, a general partnership formed for the purpose of holding an 80% interest in Loanmod, LLC, a Delaware limited liability company (“Loanmod”). Affiliated Partners is also owned by our President, Chief Executive Officer, Chief Financial Officer and director, Stephen Larkin (50%) and our other director, Travis Creed (25%). The Company acquired its interest in Affiliated Partners in exchange for its agreement to serve as the managing member and investment manager of the Opportunity Fund VII, LLC, a Delaware limited liability company (the “Opportunity Fund VII”), which invests in mortgage notes and land contracts secured by real estate. The Company also serves as the managing member and investment manager of the BYCX Opportunity Fund I (“BYCX Fund I”), established in June 2011, and the Opportunity Fund VIII, LLC (the “Opportunity Fund VIII,” and collectively with the other managed funds, the “Opportunity Funds”), established February 2013, both of which are also Delaware limited liability company that invest in Mortgage Notes and Land Contracts. The purchases of Mortgage Notes and Land Contracts by the Opportunity Funds are facilitated primarily by Loanmod, which receives income as a result in connection with its acquisition of Mortgage Notes and Land Contracts for the Opportunity Funds. In the event that the Opportunity Funds acquire Mortgage Notes and Land Contracts from an unaffiliated party, Loanmod is entitled to a transaction fee from such Opportunity Fund equal to 2.5% of the purchase price of all Mortgage Notes and Land Contracts acquired from such third party.

Recent accounting pronouncements

Consolidation Policy

All significant intercompany transactions of its consolidated subsidiary and the limited partnerships are eliminated.

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 produced and sold during the reporting period but awaiting cash payment. Based upon a review of trade receivables as of December 31, 2012 and 2011, there were no receivables considered potentially uncollectible. Receivables are reviewed quarterly, and if any are deemed uncollectible, they are written off as bad debts.

F-8

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 proportionate consolidation. Certain partnerships that have an interest in the Opportunity Fund, like the 2012 Bayou City Year End Drilling Program L.P., the Company has chosen to participate for the required 1%. Revenues received and changes in the partnership investments are recorded as oil and gas revenues and net assets, respectively. As of December 31, 2012, the Company held interest in eight partnerships.

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 units of production 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.

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, 2012 and 2011, the Company had no capitalized costs pending determination.

Accounting for Asset Retirement Obligations

The Company follows the provisions of FASB ASC 410, Asset Retirement and Environmental Obligations. 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 ASC 410. These costs are evaluated annually and adjusted accordingly under the guidelines of ASC 410. As of December 31, 2012 the Company had no liability established for any of its wells that are currently in production as these amounts have been determined to be immaterial.

F-9

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 $128,344 and $35,035 for the years ended December 31, 2012 and 2011, 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.

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 ASC 932-235, “Extractive Activities – Oil and Gas – Notes to Financial Statements.”

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.

F-10

The following table provides the numerators and denominators used in the calculation of Basic EPS for the years ended December 31, 2012 and 2011:

	2012		2011
Net income (loss) from operations	$	816,410	$	257,114
Less preferred stock dividends		-0-		-0-

Income (loss) available to common stockholders	$	816,410	$	257,114

Weighted average shares outstanding, basic		862,034		290,176

Assumed exercise of stock options		12,732		-0-

Weighted average shares outstanding, diluted		874,766		290,176

Stock Options

Effective January 1, 2006, the Company accounts for stock options in accordance with FASB ASC 505, “Equity,” and FASB ASC 718, “Compensation – Stock Compensation.” 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 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.

Concentrations of Credit Risk Arising From Cash Deposits in Excess of Insured Limits

For purposes of the statements of cash flows, cash includes demand deposits, time deposits and short-term liquid investments with an original maturity of three months or less when purchased. At December 31, 2012 and 2011, the Company had no such investments included in cash. The Company maintains deposits in two financial institutions. Beginning January 1, 2013, the Federal Deposit Insurance Corporation (FDIC) provides insurance coverage of $250,000 per depositor per bank, no longer insuring non-interest bearing transaction accounts separately from other accounts. Based on the FDIC coverage in effect at January 1, 2013, approximately $1,046,000 of the Company’s cash at December 31, 2012 was in excess of federally insured limits.The Company has not experienced any losses in such accounts and does not believe that the Company is exposed to significant risks from excess deposits.

Marketing

During the years ended December 31, 2012 and 2011, marketing costs, which are expensed as incurred, totaled $223,574 and $297,911, respectively.

F-11

Income Taxes

There was no provision for income taxes for the year ended December 31, 2011 but there was $32,872 in federal and state income taxes to be paid in 2012 The Company had an estimated net operating loss carry forward of approximately $7,265,000 and $8,004,000 as of December, 31, 2012 and 2011, respectively. However, the Company had an ownership change in March, 2012 with the issuance of additional shares in a private placement transaction. This resulted in an Internal Revenue Code (IRC) Section 382 limitation on the availability of the Company’s net operating losses immediately before the ownership change to operational periods following the date of the ownership change. The Section 382 limitation rule will limit the use of the Company’s current net operating loss carry forward to $30,193 per year in future years. This annual limitation was allocated in the year 2012 to the period following the change date and resulted in net operating losses available for the time period of April – December, 2012 being limited to $22,645 and the above tax liability for 2012 of $32,872. Income taxes are provided for under the liability method in accordance with 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 $2,303,527 and $2,674,500 has been recognized to offset the net deferred tax assets at December 31, 2012 and December 31, 2011, respectively.

Partnership Interest in Affiliated Entity

Investments at Cost

The Company holds an interest in the BYCX Opportunity Fund I and the Opportunity Fund VII through their position as managing general partner for some of their limited partnerships. The investment accounts for these investments on a cost basis for which the Company will receive quarterly interest income. As of December 31, 2012, the Company had $126,128 invested in the Opportunity Funds collectively.

Assets Held for Sale

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.

F-12

Reclassifications

Certain accounts in prior-year financial statements have been reclassified for comparative purposes to conform to the presentation in the current-year financial statements.

2. RELATED PARTY TRANSACTIONS

A. Common Stock Transactions

As of December 31, 2012, there are 990,176 shares of common stock issued and outstanding. Of all the stockholders of record two entities own 5% or more, Stephen C. Larkin owns 27.3% and Robert and Doris Burr own 29.8%.

B. Payables and Notes Payable to Related Parties

As of December 31, 2012 and December 31, 2011, the Company had the following debts and obligations to related parties:

	2012		2011
Accounts payable to minority stockholder for operating capital	$	84,906	$	84,906
Note payable to minority stockholder		100,000		100,000

Total Payable and Note Payable to Related Parties	$	184,906	$	184,906

During the second and third quarters of 2007, the Company received $84,906 from a minority shareholder. No documents were executed to document the terms of advances. These advances are classified as a current liability on the Company’s consolidated balance sheet at December 31, 2012 and 2011.

During the fourth quarter of 2007, Peter Chen, a minority stockholder 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, unsecured and bears an interest rate of 0%. The Company charges interest at 8.0% or $8,000 and records it as interest expense and additional paid in capital.

The Company also has accounts payable to Blue Ridge Group of $530,611 for their interest in the purchasing of three wells for the 2012-A Bayou City Drilling Program, L.P.

C. Receivables from Related Parties

As of December 31, 2012, the Company has a receivable from their managed limited partnerships in the amount of $104,167 for billed turnkey fees that have not been received. All fees were received in the first quarter of 2013.

D. Non-Employee Compensation

While serving on the Company’s Board of Directors, Kevin Cline was paid $27,375 in non-employee compensation related to fees earned by Source Capital in connection with the Company’s offerings.

F-13

3. OIL AND GAS PROPERTIES

Oil and gas properties, stated at cost, consisted of the following:

	December 31
	2012			2011

Proved oil and gas properties	$	776,540		$	572,458

Total oil and gas properties		776,540			572,458

Less accumulated depletion and amortization		(436,487	)		(416,420	)
Less impairment		–			–
Net oil and gas properties	$	340,053		$	156,038

Depletion, depreciation, and amortization expense was $68,689 and $101,906 during the years ended 2012 and 2011, respectively. The decrease of $33,217 was due mainly to the fact that the wells producing in 2011 produced very little in 2012 and the wells that began production in 2012 were had very little production according to their respective anticipated life of the well.

During 2012 and 2011, the Company provided for abandonment and dry hole costs of $128,344 and $35,035, respectively. The large increase is due to the fact that six wells that produced in 2011 dried up and were abandoned in 2012. The 2011 amount represents charges for the same well that were not invoiced until 2011, in the amount of $23,705 and a dry hole drilled by one of the partnerships in the amount of $11,330.

4. PROPERTY LEASE

The Company entered into an operating lease agreement on July 12, 2010 which expires on January 31, 2015 for the offices in Texas for $2,890 per month. Rental expense totaled $37,458 and $31,740 for the years ended December 31, 2012 and 2011, respectively. The Company’s future lease commitments are $35,778 for the years ending December 31, 2013 and 2014 and $2,890 for the year ending December 31, 2015.

Effective January 1, 2013, the Company leased its principal office space from GC Royalty, LLC. GC Royalty, LLC is owned by Robert and Doris Burr, who collectively beneficially own 29.79% of the Company’s Common Stock. The lease is for approximately 24,000 square feet of office and storage space, for $15,000 per month and has a three year term expiring on December 31, 2015. The Company’s future lease commitments are $180,000 annually for each of the years ending December 31, 2013 through December 31, 2015.

5. INCOME TAXES

The tax effect of significant temporary differences representing the net deferred tax liability at December 31, 2012 and 2011 were as follows:

	2012			2011
Net operating loss carry forward	$	2,469,932		$	2,781,864
Well Costs		(6,075	)		(6,075	)
Partnership differences		(160,330	)		(101,289	)
Valuation allowance		(2,303,527	)		(2,674,500	)

Net deferred tax liability	$	–		$	–

The Company recorded $32,872 and $-0- as income tax expense for the years ended December 31, 2012 and 2011, respectively, 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-14

The income tax expense is different from the amount computed by applying the U.S. statutory corporate federal income tax rate to pre-tax income as follows:

	2012					2011
Income tax expense computed at the statutory rate	$	288,756		34.0%		$	87,419		34.0%
Increase (reduction) in tax benefit resulting from:
State and local income taxes, net of federal tax effect							10,285		4.0%
Adjustment for book to tax changes		115,089		6.0%			–		(0.0%	)
Permanent items		–		(0.0%	)		10,317		(0.0%	)
Valuation allowance decrease		(370,973	)	(38.0%	)		(87,387	)	(38.0%	)
Income tax expense	$	32,872		–		$	–		–

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, 2012, 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.

Issuance of Equity Securities

On March 8, 2012, the Company entered into a Stock Purchase Agreement with eight investors (the “Investors”), pursuant to which the Company sold 70,000,000 shares of the Company’s common stock, $0.005 par value (the “Common Stock”) in a private offering (the “Offering”) at a price of $0.005 per share, for total consideration to the Company valued at $350,000. The investors included Charles T. Bukowski, Jr., the Company’s President and Chief Executive Officer at the time of the Offering, as well as a member of the Company’s Board of Directors (the “Board”), Travis N. Creed, a member of the Board, Stephen C. Larkin, the Company’s current President, Chief Executive Officer, and Chief Financial Officer and a member of the Board, Robert D. and Doris R. Burr, the Company’s former Chief Executive Officer and his spouse, Danny Looney, the Company’s tax accountant, Harry J. Peters, a consultant to the Company, Robert Shallow, a current stockholder and G2 International, Inc., a consultant to the Company. The consideration for the Common Stock was paid primarily in cash, however, the shares issued to G2 International, Inc. were issued in exchange for settlement of outstanding invoices for consulting services rendered.

F-15

Reverse Stock Split

On July 26, 2012, the Company effected a 1 for 100 reverse stock split of the Company’s Common Stock, resulting in a reduction of the number of shares outstanding of the Company from approximately 99,003,633 to approximately 990,000. At December 31, 2012, the Company had 990,176. Persons holding less than 100 shares of Common Stock received one share of Common Stock. The rights and privileges of the holders of shares of Common Stock were substantially unaffected by the reverse stock split. All issued and outstanding options, warrants and convertible securities were appropriately adjusted for the reverse stock split automatically on the effective date of the reverse stock split, and have been presented in the financial statements to adjust for the reverse stock split.

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 stockholder 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 (70,000) 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, 2012, approximately 21,500 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 29,688 options and issued 60,000 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 $1.00, with varying vesting terms. In 2010, there were 5,000 shares issued to Mr. Bukowski at $5.00 strike price and 17,500 options expired. All options granted have a ten year term. In 2012 the Company had 5,000 options expire as Mr. Bukowski did not exercise his options after he resigned from the Company.

At December 31, 2012 there were options, fully vested and expected to vest, to purchase 15,000 shares with a weighted average exercise price of $1.00 having an intrinsic value of $15,000 and a weighted contractual term of 6.4 years. At December 31, 2011, there were options to purchase 25,000 shares with a weighted average exercise price of $1.80, an intrinsic value of $45,000 and a weighted average contractual term of 8.2 years.

For the years ended December 31, 2012 and 2011 there was $0 and $11,008 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 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-16

The following table provides a summary of the stock option activity for all options for the year ended December 31, 2012.

	Number of Weighted Average			Options Exercise Price
Options at December 31, 2011	25,000		$	1.80
Options expired or cancelled in 2012	(10,000	)		(3.00	)
Options exercised in 2012	–			–
Options issued 2012	–			–
Options at December 31, 2012	15,000			1.00
Options exercisable at December 31, 2012	15,000		$	1.00

8. FAIR VALUE ESTIMATES

In February 2007 the FASB issued ASC 820 “Fair Value Measurements and Disclosures”. The objective of ASC 820 is to increase consistency and comparability in fair value measurements and to expand disclosures about fair value measurements. ASC 820 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. 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 ASC 820. 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, 2012 and 2011, was as follows:

	Quoted Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Total
Options	(Level 1)		(Level 2)		(Level 3)
2012	$	–	$	–	$	–	$	–
2011	$	–	$	11,008	$	–	$	11,008

The Provisions of ASC 820 are effective for fair value measurements made in fiscal years beginning after November 15, 2007. Options were valued using the Black-Scholes model.

9. SUBSEQUENT EVENTS:

In May 2009, the FASB issued ASC 855, subsequent events. 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 the date the financial statements were issued.

F-17

Formation of New Opportunity Fund.

Subsequent to the year ended December 31, 2012, the Company has formed and serves as the Manger of a new Delaware limited liability com4pany known as Opportunity Fund VIII, LLC, which was formed on January 8, 2013.

Bonus Payment to Chief Executive Officer

In February 2013, the Company paid Stephen Larkin, its President, Chief Executive Officer and Chief Financial Officer, a bonus of $27,750 (the “2012 Bonus”). The 2012 Bonus was based upon the Company’s performance during the 2012 fiscal year.

10. SUPPLEMENTAL INFORMATION ON OIL & GAS (Unaudited)

Capitalized Costs Relating to Oil and Gas	December 31,			December 31,
Producing Activities	2012			2011

Unproved oil and gas properties	$	–		$	–
Proved oil and gas properties		776,540			572,458
Less accumulated depreciation, depletion amortization, and impairment		(436,487	)		(416,420	)

Net capitalized costs	$	340,053		$	156,038

Costs incurred in Oil and Gas Producing Activities
For the years ended
Property acquisition costs
Proved	$	212,560		$	51,437
Unproved		163,121			350,773
Exploration costs		–			–
Development costs		–			–
Amortization rate per equivalent barrel of production	$	36.12		$	41.65

Results of Operation for Oil and Gas Producing
Activities for the years ended
Oil and gas sales	$	180,096		$	133,354
Gain on drilling program		1,754,144			1,249,997
Gain on sale of oil and gas properties		–			–
Impairment, abandonment, and dry hole costs		(128,344	)		(35,035	)
Production costs		(75,527	)		(47,021	)
Depreciation, depletion and amortization		(68,689	)		(101,906	)
		1,661,680			1,199,389

Income tax expense		–			–
Results of operations for oil and gas producing Activities (excluding corporate overhead and Financing costs)	$	1,661,680		$	1,199,389

F-18

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 - $94.71 Bbls; Gas – $2.849 Mcf for year ended December 31, 2012);

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

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.

F-19

The following table sets forth estimated proved oil and gas reserves together with the changes therein for the year ended December 31, 2012:

	Oil (bbls)			Gas (mcf)
Proved developed and undeveloped reserves
Beginning of year		640			12,975
Revisions of previous estimates		–			–
Improved recovery		–			–
Purchases of minerals in place		–			–
Extensions and discoveries		6,051			65,993
Production		(1,291	)		(10,788	)
Sales		–			–
End of Year		5,400			68,180

Proved developed reserves
Beginning of year		640			12,975
End of Year		5,400			68,180

Standardized measure of Discounted Future
Net Cash Flows at December 31, 2012 and 2011		2012			2011
Future cash inflows	$	811,670		$	114,540
Future production costs		(199,430	)		(39,910	)
Future development costs		–			–
Future income tax expenses		–			–
		612,240			74,630
Future net cash flows 10% annual discount for estimated timing of cash flows		(67,530	)		(13,770	)

Standardized Measures of Discounted Future
Net Cash Flows Relating to Proved Oil and Gas Reserves	$	544,710		$	60,860

The following reconciles the change in the standardized measure of discounted future net cash flow during 2012 and 2011:

	2012			2011
Beginning of year	$	69,860			41,611
Sales of oil and gas produced, net of production costs		(104,569	)		(86,334	)
Net changes in prices and production costs		(18,235	)		(45,608	)
Extensions, discoveries, and improved recovery, less related costs		651,414			152,927
Development costs incurred during the year which were previously estimated		–			–
Net change in estimated future development costs		–			(480	)
Revisions of previous quantity estimates		–			–
Net change from purchases and sales of minerals in place		–			7,744
Accretion of discount		(53,760	)		–
Net change in income taxes		–			–
Other		–			–

End of year	$	544,710			69,860

F-20