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EX-32.2 - CERTIFICATION - BAYOU CITY EXPLORATION, INC.bayou_ex3202.htm
EX-32.1 - CERTIFICATION - BAYOU CITY EXPLORATION, INC.bayou_ex3201.htm
EX-23.1 - CONSENT - BAYOU CITY EXPLORATION, INC.bayou_ex2301.htm
EX-99.1 - REPORT OF CONSULTANTS - BAYOU CITY EXPLORATION, INC.bayou_ex9901.htm
EX-31.2 - CERTIFICATION - BAYOU CITY EXPLORATION, INC.bayou_ex3102.htm
EX-31.1 - CERTIFICATION - BAYOU CITY EXPLORATION, INC.bayou_ex3101.htm


SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549   
FORM 10-K/A
(Amendment No. 3)
(MARK ONE)
þ
 
ANNUAL REPORT UNDER SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009
 
or
   
o
 
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
FOR THE TRANSITION PERIOD FROM                      TO                     

COMMISSION FILE NUMBER 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 NUMBER)
 
 
 
 
   
632 Adams Street — Suite 700, Bowling Green, KY
 
42101
(ADDRESS OF PRINCIPLE EXECUTIVE OFFICES)
  (ZIP CODE)
  
(REGISTRANT’S TELEPHONE NUMBER, INCLUDING AREA CODE): (270) 842-2421

SECURITIES REGISTERED UNDER SECTION 12(b) OF THE EXCHANGE ACT: NONE
SECURITIES REGISTERED UNDER SECTION 12(g) OF THE EXCHANGE ACT: COMMON STOCK PAR VALUE $.005 PER SHARE

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

Check whether the issuer is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes o    No þ
    
Check whether the issuer: (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act 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
   
Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B contained in this form, and no disclosure will 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

Indicated by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated Filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
  
Large accelerated filer o Accelerated filer o Non-accelerated filer o Smaller reporting company þ
   
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No þ
 
State issuer’s revenues for its most recent fiscal year: $ 1,025,000
 
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately $2,132,291 as of March 29, 2010 based upon the closing price of the common stock on the OTC “Bulletin Board” on March 29, 2010 of $0.08 per share. As of March 30, 2010 the registrant had 26,653,633 shares of Common Stock, par value $0.005 per share, and 0 shares of Preferred Stock, par value $0.001 per share, subscribed or outstanding.

APPLICABLE ONLY TO CORPORATE REGISTRANTS
 
State the number of shares outstanding of each of the issuer’s classes of common equity, as of the latest practicable date.
 
26,653,633 Shares of Common Stock Outstanding at March 29, 2010; 0 Shares of Preferred Stock Outstanding at March 29, 2010.

DOCUMENTS INCORPORATED BY REFERENCE: None.
 
 


 
 

Explanatory Note

Bayou City Exploration, Inc. (the “Company”) is filing this Amendment No. 3 to its Annual Report on Form 10-K (the “Form 10-K/A”) to amend its Annual Report on Form 10-K for the year ended December 31, 2009, which was filed with the Securities and Exchange Commission (“SEC”) on March 31, 2010 and subsequently amended on the same date to correct an administrative error and again on January 14, 2011 in response to comments made by the SEC (collectively, the “2009 10-K”). This Amendment No. 3 is in response to comments made by the SEC on the Company’s 2009 10-K, received by the Company on February 4, 2011 (the “SEC Comment Letter”).  It amends the 2009 10-K by: (i) filing a copy of an engineering report obtained by the Company relating to its oil and gas reserves as Exhibit 99.1 (the “PPC Report”); (ii) removing prior disclosure stating that the Company had chosen not to disclose proven oil and gas reserves in the 2009 10-K; (iii) expanding disclosures to include the information regarding oil and natural gas reserves required by Item 1202(a)(6) and (7) of  Regulation S-K, promulgated under the Securities Exchange Act of 1934, as amended; (iv) correcting disclosure in the “SUBSEQUENT EVENTS” footnotes to the Financial Statements regarding the Company’s interest in the Sein #1 well; and (v) disclosing information in the notes to the financial statements regarding certain royalty interests held by the Company in the Sein #1 well. It also amends Item 15 – Exhibits to include a consent from Pressler Petroleum Consultants, Inc., updated officer certifications and updated signature pages.

Except as described above, no other changes have been made to the 2009 10-K, and this Amendment No. 3 does not otherwise amend, update or change the financial statements or disclosures in the 2009 10-K.
  
 
 

 
 
FORM 10-K
 
Amendment No. 3

TABLE OF CONTENTS
    
    Page
 PART I
 
     
 1.
Description of Business
1
 2.
Description of Properties
4
 3.
Legal Proceedings
7
 4.
Submission of Matters to a Vote of Security Holders
7
     
 PART II
 
     
 5.
Market Price for Common Equity and Related Stockholder Matters
8
 6.
Management’s Discussion and Financial Analysis of Financial Condition
8
 7.
Financial Statements
11
 8.
Change in and Disagreements with Accountants on Accounting and Financial Disclosure
11
 8A.
Controls and Procedures
11
 8B.
Other Information
12
     
 PART III
 
      
 9.
Directors, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of the Exchange Act
13
 10.
Executive Compensation
15
 11.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
17
 12.
Certain Relationships and Related Transactions
18
 13.
Exhibits
19
 14.
Principal Accountant Fees and Services
19
     
 PART IV
 
     
 Signatures
20
     
 FINANCIAL STATEMENTS
 
     
 Independent Auditor’s Report
 
 
Killman, Murrell, & Company, P.C.
F-1
     
 Balance Sheets
F-2
 Statements of Operations
F-3
 Statements of Changes in Stockholders’ Equity
F-4
 Statements of Cash Flows
F-5
 Notes to Financial Statements
F-6
 Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)
F-15
 
 EX-23.1
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 EX-99.1
   
 
 

 
 
PART I
 
1.
 
DESCRIPTION OF BUSINESS
   
General Description
  
Bayou City Exploration, Inc., (the “Company”), a Nevada corporation, was organized in November 1994, as Gem Source, Incorporated (“Gem Source”), and subsequently changed the Company's name to Blue Ridge Energy, Inc. in May 1996. In September 2005, the Company changed its name to Bayou City Exploration, Inc.

On April 4, 2007, the Company announced the relocation of their corporate headquarters to 632 Adams Street, Suite 700, Bowling Green, Kentucky 42101 in order to decrease overhead, consolidate operations and reduce the number of personnel on staff. This move was completed in May, 2007. The Company’s executive office in the year 2006 was located at 10777 Westheimer, Suite 170, Houston, Texas, 77042. Since relocating the Company’s headquarters to Bowling Green, Kentucky the Company maintained only the geological contract staff in the Houston office for the development and sale of the Company’s prospects until June 2008 when the Company eliminated all paid staff and closed the office.

In 2007, the Company announced that Robert D. Burr had been appointed President and Chief Executive Officer of the Company by the Board on an interim basis as of April 3, 2007 while the Company continues to search for new executive management.   In January 2010, the Company announced the Board’s appointment of Stephen C. Larkin as the new Chief Financial Officer.  The appointment runs through December 31, 2010 and extends automatically each year for twelve months unless terminated by either party within ninety days of the anniversary date.

All of our periodic report filings with the Securities and Exchange Commission (“SEC”) pursuant to Section 13 or 15(d) of the Securities and Exchange Act of 1934, as amended, are available through the SEC web site located at www.sec.gov, including our annual report on Form 10-K, quarterly reports on Form 10-QSB, current reports on Form 8-K and any amendments to those reports. The Company will also make available to any stockholder, without charge, copies of its Annual Report on Form 10-K as filed with the SEC and a copy of its Code of Ethics. For copies of this, or any other filings, please contact: Robert D. Burr at Bayou City Exploration, Inc., 632 Adams Street — Suite 700, Bowling Green, KY 42101 or call (270) 842-2421.

The Company is engaged in the oil and gas business primarily in the gulf coast of Texas, east Texas, south Texas, and Louisiana. The Company develops oil and gas prospects for the drilling of oil and gas wells and attempts to sell the prospects to oil and gas exploration companies under terms that provide the participating company will provide the funds necessary to drill and complete a well on the prospect, reimburse the Company for any leasehold or exploration costs associated with the prospect, pay the Company a prospect fee for developing the oil and gas prospect, and allow the Company to retain a carried interest in the well to be drilled. The wells drilled by the Company included both exploratory and developmental wells.

Prior to May 1, 2007, the Company operated many of the wells in which it owned an interest. The Company no longer intends to operate properties. The Company will seek to sell a portion of the interest in each prospect it generates to an operator that will be responsible for the drilling and operating of the oil and gas properties. In prior years, the Company has been licensed as an oil and gas operator with the Texas Railroad Commission in the state of Texas. During the second quarter 2007, the Company’s license with the Texas Railroad Commission to be an operator in the state of Texas was not renewed. The Company operated two wells in Texas and one in Louisiana. All three wells are now plugged and abandoned. The Company’s ownership in all remaining wells is through non-operated working and royalty interests.

The Company plans to pursue other sources of capital through either the issuance or restructuring of debt or equity securities. The Company also owns certain oil and gas interests as of December 31, 2009 that have developed into revenue producing properties it intends to use cash generated by these properties to cover its ongoing operational needs and restructuring of the Balance Sheet.

On July 17, 2009 the Company renewed a line of credit from Blue Ridge Group, Inc. (“BR Group”) in the amount of $500,000 to finance the Company’s operations.  As of December 31, 2009 the Company has a liability balance under this line of credit arrangement due BR Group in the amount of $375,000. The line of credit provides for interest at the rate of 8% per annum on the unpaid outstanding balance and is due upon demand. If no demand for payment is made by BR Group, the line of credit balance plus all accrued unpaid interest is due July 17, 2010.

During the 4th quarter, 2007, Peter Chen, a minority shareholder loaned the Company $100,000 to finance the Company’s operations. The Company executed a promissory note on October 4, 2007; the note is due on demand and bears an interest rate of 0%.
    
 
1

 
   
Competition, Markets and Regulations

Competition: The oil and gas industry is highly competitive in all its phases. The Company encounters strong competition from other independent oil and gas companies. Major and independent oil and gas companies actively bid for desirable oil and gas properties, as well as for the equipment and labor required to operate and develop such properties. Many of its competitors possess substantially greater financial resources, personnel, and budgets than the Company, which may affect its ability to compete with companies in Texas & Louisiana.

Markets: The price obtainable for oil and gas production from the Company’s properties is affected by market factors beyond the control of the Company. Such factors include the extent of domestic production, the level of imports of foreign oil and gas, the general level of market demand on a regional, national and worldwide basis, domestic and foreign economic conditions that determine levels of industrial production, political events in foreign oil-producing regions, variations in governmental regulations and tax laws and the imposition of new governmental requirements upon the oil and gas industry. There can be no assurance that oil and gas prices will not decrease in the future, thereby decreasing net revenues from the Company properties. Changes in oil and gas prices can impact the Company’s determination of proved reserves and the Company’s calculation of the standardized measure of discounted future net cash flows relating to oil and gas reserves. In addition, demand for oil and gas in the United States and worldwide may affect the Company’s level of production. From time to time, a surplus of gas or oil supplies may exist, the effect of which may be to reduce the amount of hydrocarbons that the Company may produce and sell, while such an oversupply exists. In recent years, initial steps have been taken to provide additional gas pipelines from Canada to the United States. If additional Canadian gas is brought to the United States market, it could create downward pressure on United States gas prices.

Regulations:

Environmental Regulation

The federal government and various state and local governments have adopted laws and regulations regarding the control of contamination of the environment by the oil and gas industry. These laws and regulations may require the acquisition of permits by oil and gas operators before drilling commences, prohibit drilling activities on certain lands lying within wilderness areas or where pollution arises and impose substantial liabilities for pollution resulting from operations, particularly operations near or in onshore and offshore waters or on submerged lands. These laws and regulations may also increase the costs of routine drilling and operating of wells. Because these laws and regulations change frequently and are becoming increasingly more stringent, the costs to the Company of compliance with existing and future environmental regulations and the overall impact on the Company’s operations or financial condition cannot be predicted, but are likely to increase.

The Company currently owns or leases one property that for many years has been used for the exploration and production of oil and natural gas and several that have just started to produce.  Although the Company believes it has utilized good operating and waste disposal practices, prior owners and operators of these properties may not have utilized similar practices, and hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), RCRA and analogous state laws, as well as state laws governing the management of oil and natural gas wastes. Under such laws, the Company 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.

Federal Regulation of Natural Gas

The transportation and sale of natural gas in interstate commerce is heavily regulated by agencies of the federal government. The following discussion is intended only as a summary of the principal statutes, regulations and orders that may affect the production and sale of natural gas from the Company properties.
   
 
2

 
   
FERC Orders

Several major regulatory changes have been implemented by the Federal Energy Regulatory Commission (“FERC”) from 1985 to the present that affect the economics of natural gas production, transportation and sales. In addition, the FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry that remain subject to the FERC’s jurisdiction. In April 1992, the FERC issued Order No. 636 pertaining to pipeline restructuring. This rule requires interstate pipelines to unbundle transportation and sales services by separately stating the price of each service and by providing customers only the particular service desired, without regard to the source for purchase of the gas. The rule also requires pipelines to (i) provide nondiscriminatory “no-notice” service allowing firm commitment shippers to receive delivery of gas on demand up to certain limits without penalties, (ii) establish a basis for release and reallocation of firm upstream pipeline capacity and (iii) provide non-discriminatory access to capacity by firm transportation shippers on a downstream pipeline. The rule requires interstate pipelines to use a straight fixed variable rate design. The rule imposes these same requirements upon storage facilities. FERC Order No. 500 affects the transportation and marketability of natural gas. Traditionally, natural gas has been sold by producers to pipeline companies, which then resell the gas to end-users. FERC Order No. 500 alters this market structure by requiring interstate pipelines that transport gas for others to provide transportation service to producers, distributors and all other shippers of natural gas on a nondiscriminatory, “first-come, first-served” basis (“open access transportation”), so that producers and other shippers can sell natural gas directly to end-users. FERC Order No. 500 contains additional provisions intended to promote greater competition in natural gas markets.

It is not anticipated that the marketability of and price obtainable for natural gas production from the Company’s properties will be significantly affected by FERC Order No. 500. Gas produced from the Company’s properties normally will be sold to intermediaries who have entered into transportation arrangements with pipeline companies. These intermediaries will accumulate gas purchased from a number of producers and sell the gas to end-users through open access pipeline transportation.

State Regulations

Production of any oil and gas from the Company’s property is affected by state regulations. States in which the Company operates have statutory provisions regulating the production and sale of oil and gas, including provisions regarding deliverability. Such statutes, and the regulations promulgated in connection therewith, are generally intended to prevent waste of oil and gas and to protect correlative rights to produce oil and gas between owners of a common reservoir. State regulatory authorities also regulate the amount of oil and gas produced by assigning allowable rates of production to each well or proration unit.

Operating Hazards and Insurance

General: The oil and gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures and discharges of toxic gases. The occurrence of any of these events could result in substantial losses to the Company due to injury or loss of life, 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. In accordance with customary industry practice, we maintain insurance against some, but not all, of the risks described above. However, there can be no assurance that any insurance obtained by us will be adequate to cover any losses or liabilities. We cannot predict the continued availability of insurance or the availability of insurance at premium levels that justify its purchase. The occurrence of a significant event, not fully insured or indemnified against, could materially and adversely affect our financial condition and operations.

Recent Terrorist Activities and the Potential for Military and Other Actions: The continued threat of terrorism and the impact of retaliatory military and other action by the United States and its allies might lead to increased political, economic and financial market instability and volatility in prices for oil and natural gas, which could affect the market for our exploration and production operations. In addition, future acts of terrorism could be directed against companies operating in the United States, and it has been reported that terrorists might be targeting domestic energy facilities. While we believe that the risk to our energy assets is minimal, there is no assurance that we can completely secure our assets or completely protect them against a terrorist attack. These developments have subjected our operations to increased risks and, depending on their ultimate magnitude, could have a material adverse effect on our business. In particular, we might experience increased capital or operating costs to implement increased security for our energy assets.
   
 
3

 
    
Employees

During 2008 the Company has had only one employee, Mr. Robert D. Burr, serving as President and Acting Chief Financial Officer without pay.   In April 2009 the Company started paying Mr. Burr an annual salary of $90,000 and hired a Controller, Stephen C. Larkin at an annual salary of $30,000 per year.  These are the only two paid employees for the Company.

From May 2007 until February 2008, only the exploration contract personnel have remained in the Houston, Texas office. At the time of notice of termination, the Company had employment and consulting agreements with three persons. One of the agreements was with an exploration and prospect development contractor. This contractor worked for the Company until February 2008 when his services were terminated.

The Company’s headquarters is now the same as the corporate office of one of its major stockholders, Blue Ridge Group, Inc. (“BR Group”). Since moving the Company’s headquarters to Bowling Green Kentucky the Company has made direct investments in five new projects described below. Mr. Burr (CEO and Acting CFO) and Mr. Larkin (Controller) have been in charge of all administrative matters of the Company and all other business matters of the Company have been fulfilled through independent contractors. Mr. Burr has served the Company without salary during 2008 and until April 1, 2009 when the Board of Directors approved an annual salary of $90,000. Annually, the Board of Directors determines if any of the executive officers of the Company are eligible for a performance bonus. No performance bonuses were paid during 2009 and 2008.

2.
 
DESCRIPTION OF PROPERTIES

During 2009, the Company participated in the drilling of four new wells and one of its existing wells has been plugged and abandoned.

As of December 31, 2009, the Company owns a direct working interest in two producing well, being the Rooke #1 and the Chapman #75-1 in Texas; two wells being completed, being the Garcitas #1 and the Rooke B-1 also in Texas. All other wells in which the Company previously owned direct participation working interest have been abandoned and plugged. The Company owns a small indirect interest in 1 well in Texas through two different partnerships managed by BR Group. The Company also owns a small royalty interest in 1 well in Texas.

The following tables summarize by geographic area the Company’s developed and undeveloped acreage and gross and net interests in producing oil and gas wells as of December 31, 2009. Productive wells are producing wells and wells capable of production. Wells that are dually completed in more than one producing horizon are counted as one well.

DEVELOPED AND UNDEVELOPED ACREAGE
  
   
Developed Acreage
   
Undeveloped Acreage
 
Geographic Area:
 
Gross Acres
   
Net Acres
   
Gross Acres
   
Net Acres
 
Texas
   
                -0-
     
               -0-
     
-0-
     
-0-
 
                         
Totals
   
                -0-
     
               -0-
     
-0-
     
-0-
 

PRODUCTIVE WELLS
   
   
Gross Wells
   
Net Wells
 
Geographic Area:
 
Oil
   
Gas
   
Oil
   
Gas
 
Texas
   
2
     
                4
     
.18
     
.26
 
                         
Totals
   
                  2
     
4
     
.18
     
.26
 
     
 
4

 
    
Key Properties

The working interest owned by the Company, either directly or indirectly through oil and gas partnerships, 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, 2009:

Developed Properties:

Bridges #1 well in Shelby County, Texas: The Company owns a 0.7% indirect working interest in this well through two partnerships managed by BR Group.

Sein #1 well:  The Company owns an 8.1% royalty interest in 1 well located in Aransas County Texas which began production in November 2008.  The well produces about 6,600 Mcf per day and 90 Bbls of oil per day.

Rooke #1 well:  The Company owns a 9.5% working interest in 1 well located in Refugio County Texas which began production in September 2009.  The well produces about 425 Mcf per day and about 10 Bbls of oil per day.

Chapman No. 75-1:  The Company owns an 8% working interest in 1 well located in Nueces County, Texas which began production in October 2009.  The well produces about 390 Mcf per day.

Garcitas #1:  The Company owns a 9.5% working interest in 1 well located in Jackson & Victoria County, Texas.  The well has been drilled and gone to completion.  It is believed that the well will begin producing in the first quarter of 2010.

Rooke B-1:  The Company owns a 9.5% working interest in 1 well located in Refugio County, Texas.  The well has been drilled and gone to completion.  It is believed that the well will begin production late in the first quarter of 2010 or early in the second quarter of 2010.

In February 2008, the Company sold the mineral rights on approximately 460 acres in Aransas, Texas to an operating company for $350,000 and retained a royalty interest of 12% in the property.  The operating company subsequently developed a producing well that went to production in November 2008.  In 2009 the Company received approximately $1,006,000 from the royalty interest.

During 2009 & 2008 the Company received total cash flow of approximately $3,000 and $8,000 from its interest in the partnerships operated by BR Group and Eagle Energy respectively.

Undeveloped Properties:

At this time the Company has no undeveloped properties under lease.

Dry Holes and Abandonment of Properties during 2008

The Company had a 2.5% working interest in the Powers well located in Colorado County, Texas which was drilled and completed in the fourth quarter of 2009.  The well was determined to be a dry hole and has been abandoned, for a total write off of $100,000.

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 indirectly through the oil and gas partnerships, is owned jointly with other working interest partners and 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.
  
 
5

 
   
Production and Sales Price

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 2009 and 2008, the average selling price for natural gas was $4.44 and $9.11 per Mcf, respectively, and the average selling price for oil was $58.47 and $99.65 per barrel, respectively.
    
   
Net
Production
For the Year
12/31/09
   
Net
Production
For the Year
12/31/08
 
    Net Volumes (Equivalent Barrels)
   
35,431.00
     
6,833.00
 
    Average Sales Price per Equivalent Barrel
 
$
28.78
   
$
42.12
 
    Average Production Cost per Equivalent Barrel (includes production taxes)
 
$
1.88
   
$
3.12
 
    
The Average Production Cost per Equivalent Barrel represents the Lease Operating Expenses divided by the Net Volumes in equivalent barrels. Lease Operating Expenses include normal operating costs such as pumper fees, operator overhead, salt water disposal, repairs and maintenance, chemicals, equipment rentals, production taxes and ad valorem taxes.

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 2009 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, 2009 based upon a report prepared by Pressler Petroleum Consultants, Inc. (“PPC”).  All of the Company’s proved reserves are located in the United States.

 
Future Net Revenue, $
Reserve
Category
Oil
(Bbls*)
Gas
(Mcf**)
 
Undiscounted
Present Worth
at 10%
Proved Developed Producing
15
12,423
29,024
27,680
Proved Developed Non-Producing
1,366
23,036
94,170
87,390
         
Total Net Proved Reserves
1,381
35,459
123,194
115,070

*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 $61.18 per barrel of oil for West Texas Intermediate oil at Cushing, Oklahoma, and $3.87 per Million British thermal units (MMBtu) for natural gas at Henry Hub, Louisiana. The oil and gas prices were adjusted on each well based on deductions such as quality, energy content, and basis differential, as appropriate.  Prices for oil and natural gas were held constant throughout the remaining life of the properties.
 
 
 
6

 

 
Qualifications of Technical Persons and Internal Controls Over the Reserves Estimation Process

Reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly.  The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment.  Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered.  Future prices received for production may vary, perhaps significantly, from the prices assumed for the purposes of estimating the standardized measure of discounted future net cash flows.  The standardized measure of discounted future net cash flows should not be construed as the market value of the reserves at the dates shown.  The 10% discount factor required to be used under the provisions of applicable accounting standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry.  The standardized measure of discounted future net cash flows is materially affected by assumptions about the timing of future production, which may prove to be inaccurate.

The reserve estimates reported herein were prepared by independent engineers of PPC.  The process performed by PPC engineers to prepare reserve amounts included their estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue, based in part on data provided by the Company.  The estimates of reserves were determined by accepted industry methods. Methods utilized by PPC in preparing the estimates include extrapolation of historical production trends and analogy to similar producing properties.  PPC believes the assumptions, data, methods and procedures utilized in preparing the estimates were appropriate for the purpose served by their report, and that it utilized all methods and procedures it considered necessary to prepare this report.

The Company’s internal control over the preparation of reserve estimates is a process designed to provide reasonable assurance regarding the reliability of the Company’s reserve estimates in accordance with SEC regulations.  The preparation of reserve estimates are created by a third party consultant, PPC, and overseen by the Company’s President and Chief Executive Officer, Charles Bukowski.  PPC performs evaluations based on accepted engineering standards.  Reserves were determined by decline curve projection in the case of established production.  For behind the pipe zones, reserves were calculated based on production and review of offset wells in the area and by reviewing calculated volumetric data.  These specific reserve estimates were performed by Mr. Daniel L. Wilson, P.E., who has more than 34 years of related experience while working for various large and independent oil companies concentrating solely on estimating reserves.  Charles Bukowski, who oversees the reserve estimates presented by PPC, has been working with oil companies for over 26 years, including both major oil companies (Mobil Oil Corp) and smaller independent oil companies.  He is the sole person for the Company that reviews and approves the reserve estimates.

Drilling Activities

The Company drilled 5 wells in year 2009 and 0 wells in 2008.  As of December 31, 2009 two of these have gone into production and two other wells are in the process being completed.  The fifth well is still in the process of being drilled.

3.
 
LEGAL PROCEEDINGS

The Company has one judgment against it for $55,000 on which it is currently making monthly payments to resolve the judgment.  No other action against it is known at this time.  The Company also has significant monthly payments on its notes payable, all of which mature and be due in full during the year 2010.  The Company expects to pay these notes payable off in full prior to the maturity dates.   Other than noted above, neither the Company nor any of its properties is subject to any material pending legal proceedings.

4.
 
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None
    
 
7

 
   
PART II
      
5.
 
MARKET PRICE FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Market Information

The Common Stock of the Company is thinly traded on the OTC Bulletin Board with “BYCX” as its stock symbol. The range of high and low bid information for each quarter since January 1, 2008 is as follows:
   
   
High Bid
   
Low Bid
 
March 31, 2008
 
$
0.25
   
$
0.14
 
June 30, 2008
   
0.15
     
0.03
 
September 30, 2008
   
0.08
     
0.03
 
December 31, 2008
   
0.08
     
0.01
 
                 
March 31, 2009
 
$
0.01
   
$
0.01
 
June 30, 2009
   
0.05
     
0.01
 
September 30, 2009
   
0.07
     
0.01
 
December 31, 2009
   
0.10
     
0.03
 

These quotations reflect inter dealer prices, without retail mark-up, markdown or commission, and may not represent actual transactions.

Dividend Information

No cash dividends have been declared or paid on the Company’s Common Stock since the Company’s inception. The Company has not paid, nor does it intend to pay, cash dividends on its Common Stock in the foreseeable future. We intend to retain earnings, if any, for the future operation and development of our business. The Company’s dividend policy will be subject to any restrictions placed on it in connection with any debt offering or significant long-term borrowing.

Recent Sales of Unregistered Securities

The Company did not issue any stock during 2009 or 2008.

Shareholder Information

As of December 31, 2009, there were approximately 600 shareholders of record of the Company’s Common Stock.

6.
 
MANAGEMENT’S DISCUSSION AND FINANCIAL ANALYSIS OF FINANCIAL CONDITION

The following discussion is intended to assist in an understanding of the Company’s financial position and results of operations for each year of the two year periods ended December 31, 2009 and 2008. The financial statements and the notes thereto, which follow, contain detailed information that should be referred to in conjunction with the following discussion.

Financial Overview

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

On April 4, 2007, the Company announced the relocation of their corporate headquarters to 632 Adams Street, Suite 700, Bowling Green, Kentucky 42101 in order to decrease overhead, consolidate operations and reduce the number of personnel on staff. This move was completed in May, 2007. Prior to that the Company’s executive office was located at 10777 Westheimer, Suite 170, Houston, Texas, 77042. After relocating the Company’s headquarters to Bowling Green, Kentucky the Company had maintained only the geological contract staff in the Houston office for the continued development and sale of the Company’s prospects until June 2008 when the office was closed and all remaining staff was terminated.
  
 
8

 
   
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, stock compensation expense of $71,000 was required to be recognized in the year ended December 31, 2009, no stock compensation expense was required to be recognized for the year ended December 31, 2008.

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.
   
 
9

 
    
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 $783,000 in 2009, as compared to a net loss of $175,000 in 2008. The increase in the net income (loss) is primarily due to the fact that the Company’s owns an 8.1% royalty interest in the Sein well which went into production in November of 2008 and provided the Company with $909,000 of net revenue (gross revenues less taxes) in 2009.  On a per share basis the Company had a net income of $0.03 per share in 2009 and a net loss of $0.01 per share in 2008.

Operating Revenues:  Operating revenues totaled $1,025,000 in 2009 as compared to $346,000 in 2008 which is a 196% increase from 2008. The increase is mainly the result of the production of the well in the county of Nueces, Texas called the Sien #1, which went into production in November 2008.  The Company sold these leases in February 2008 and retained an 8.1% royalty interest in the land.  The Sien well was subsequently drilled on the property and produced approximately $1,006,000 of revenue for the Company for the year of 2009 and 206,000 for 2008.

Direct Operating Costs:  Direct operating costs for the producing oil and gas wells totaled $100,000 in 2009 compared to $36,000 in 2008. This increase in expenses is a result of the Sien well being in production for all of 2009 as opposed to just 2 months in 2008.

Other Operating Expenses:  Other operating expenses includes impairment, abandonment, and dry hole costs, exploration costs, depreciation, depletion and amortization expense, and accretion expense. Other operating expenses increase by 79% to $111,000 in 2009 compared to $62,000 in 2008. This increase of $49,000 was made up of an increase of $72,000 in impairment, abandonment, and dry hole costs, all other costs combined to decrease $23,000 in 2009 from 2008, mainly in depreciation, depletion and amortization costs.

General And Administrative Costs:  General and administrative costs were $374,000 in 2009 compared to $330,000 for 2008, an increase of $44,000, or an increase of 13%.  The increase is due mainly to an increase in stock based compensation expense of $71,000 and a decrease in accounting and professional fees of $36,000.  All other expenses in total were essentially the same.

Other Expenses, Net:  Other income in excess of other expenses increased by a net of $434,000 in 2009 from 2008 due largely to increase in forgiveness of debt, which was $167,000 for 2009 and $33,000 for 2008, an increase of $134,000, collection of $171,000 in bad debts previously allowed for, and $40,000 reversal in long-term P&A liability after plugging all active wells.  In early 2009 the Company aggressively settled most of its accounts payable with companies it had not been able to pay for several years and was able to get a large amount of the payable forgiven for immediate payment.  The Company also aggressively pursued its outstanding accounts receivables and was able to collect a large amount of these as well.

Income Taxes: The Company had no federal or state income tax liability or benefit in 2009 or in 2008 as a result of a large NOL carry forward from years 2008 and prior. Based on the amount of net losses in 2008 and prior, a full valuation allowance has been recorded against the deferred tax assets associated with the net operating loss carry forwards. The Company has an estimated net operating loss carry forward of 8,834,000 and $9,606,000 as of December 31, 2009 and 2008 respectively. Under Internal Revenue Code (IRC) Section 382, a change in ownership occurred on December 31, 2004 with the issue of the additional shares from the private stock placement. This rule will limit the NOL carry forward amount to $267,000 per year. These NOLs begin expiring in 2017 if not utilized.

Balance Sheet Review

Assets: The Company’s total assets increased $292,000 from $235,000 as of December 31, 2008 to $527,000 as of December 31, 2009.  Property costs increased $117,000 primarily due to the investment in the two new productive wells the Company made this year, the Rooke #1 and the Chapman No. 75-1, and other noncurrent assets increased $186,000 due to the investment in two other wells, the Garcitas #1 and the Rooke B-1. The Company’s current assets decreased $11,000 from $229,000 as of December 31, 2008 to $218,000 as of December 31, 2009 due to the income receivable from the Sien #1 GU well at year-end dropping $45,000 and cash increasing $34,000.
   
 
10

 
   
Liabilities:  The Company’s liabilities decreased to $743,000 as of December 31, 2009 compared to $1,313,000 as of December 31, 2008. The Company reduced is accounts payable and accrued expenses by $222,000, reduced its accounts payable to related parties by $111,000, reduced its advances from JIB owners by $51,000, reduced its notes payable to related parties by $142,000, and a reduction of $44,000 in long-term P&A cost liability.  During 2009, the entire reduction in notes payable to related parties were related to the amounts owed to Blue Ridge Group which went from $517,000 in 2008 to $375,000 in 2009.

The Company’s liabilities to third parties as of December 31, 2009 included $133,000 in trade payables and accrued expenses. The Company’s liabilities to related parties include $135,000 in trade payables and accrued expenses and $475,000 in notes payable due to related parties as of December 31, 2009.

Stockholders’ Equity: Total stockholder’s equity of the Company increased $862,000 to a deficit of $216,000 at December 31, 2009. This decrease is mainly the result of the 2009 net operating loss of $783,000.

Capital Resources and Liquidity: The Company’s current ratio (current assets / current liabilities) was .29 to 1 as of December 31, 2009 compared to .18 to 1 as of December 31, 2008. The change in the current ratio from 2008 to 2009 is the result a significant decrease in current liabilities due to both the Company negotiating a large reduction in accounts payable with creditors and the Company paying off a significant amount of current liabilities with the cash flow from the Sien #1 well.

The Company’s sources of cash during 2009 were basically all from the $1,025,000 in oil and gas sales receipts. The Company’s sources of cash during 2008 were $409,000 in proceeds from the sale of assets, plus $77,000 in loans from BR Group and other related parties, and $69,000 is oil and gas sales.

During 2009 the Company relied primarily upon oil and gas sales receipts and in 2008 the Company relied primarily upon sales of assets to fund its operations. Management intends to fund further growth with the current oil and gas revenues by continuing to invest in oil and gas prospects for a profit.

As of December 31, 2009 the Company has no contractual obligations that will encumber their cash flow into the future.

7.
 
FINANCIAL STATEMENTS

The response to this item is set forth herein in a separate section of this Report, beginning on Page F-1.

8.
 
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

The Company elected to change auditors for its 2007 financial statements. The accounting firm of Killman, Murrell & Company, PC was retained to audit its December 31, 2008 and 2007 financial statements. The Company had no disagreements with its previous auditors, Mountjoy & Bressler, LLP who audited the Company’s December 31, 2006 financial statements.

8A.
 
CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 15d-15(e) under the Securities and Exchange Act of 1934 (the “Exchange Act”) promulgated there under, our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report (the “Evaluation Date”).  Based on such evaluation, our management, including our CEO and CFO, concluded that our disclosure controls and procedures were effective, at a reasonable assurance level, as of the Evaluation Date, to ensure that information required to be disclosed in reports that we file or submit under that Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our CEO and CFO, in a manner that allows timely decisions regarding required disclosure.
    
 
11

 
    
Changes in Internal Controls over Financial Reporting

The Company maintains a system of internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. There was no change in our internal control over financial reporting, that occurred during the year ended December 31, 2009, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control Over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined rule 13a-15(f) of the Exchange Act.  The Company’s internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the preparation and fair presentation of published financial statements.

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.  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 control over financial reporting was effective in providing reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principals as of December 31, 2009.

This Form 10-K does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in their annual report.

Inherent Limitations of Internal Controls

There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention and overriding of controls and procedures.  A control system, no matter how well conceived and operated, can only provide reasonable, not absolute, assurance that the objectives of the control system are met.  Further, the design of the control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs.  Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.
   
8B.
 
OTHER INFORMATION

On January 1, 2006, the Company entered into an employment agreement with D. Edwin Suhr, Jr. to serve as Senior Vice President Land as well as the Corporate Secretary (“2006 Contract”). Mr. Suhr’s contract was for a one year period and was automatically extended for one additional year at the end of the initial term and each extension period, unless either party gives at least 90 days prior notice, prior to the end of the applicable term. Mr. Suhr’s annual base salary was $120,000. On January 1, 2007, the Company entered into a revised three year employment agreement with Mr. Suhr (“2007 Contract”). The 2007 Contract provides for automatic extensions for one additional year at the end of the initial term and each extension period, unless either party gives at least 30 days prior notice, prior to the end of the applicable term. Mr. Suhr’s annual base salary was increased to $180,000. Mr. Suhr’s 2007 Contract also provided that the Company would grant him the number of shares of restricted Company common stock equal to $30,000 divided by the previous 30 day trading price of the Company stock on each of the anniversary dates of the agreement in 2008, 2009, 2010.

On December 1, 2006, the Company entered into an employment agreement with James G. Brown to serve as the Drilling and Production Manager. Mr. Brown’s contract is for a three year period and provides for automatic extensions for one additional year at the end of the initial term and each extension period, unless either party gives at least 30 days prior notice, prior to the end of the applicable term. Mr. Brown’s annual base salary was $168,000. Mr. Brown’s employment contract also provided that the Company would grant him the number of shares of restricted Company common stock equal to $20,000 divided by the previous 30 day trading price of the Company stock on each of the anniversary dates of the agreement in 2007, 2008, 2009.

Both employment agreements may be terminated by the Company on the death or disability of the officer or in the event the officer engages in any act constituting “cause,” as defined in the agreements. Mr. Suhr’s 2006 Contract also contained a provision allowing the Company to terminate his employment at any time with or without cause on 30 days’ written notice. Both agreements also provide that the officers will be entitled to participate in any other individual or group health insurance, which the Company may from time to time make available to similarly situated employees. The employment agreements contain provisions providing for non-disclosure of proprietary information and surrender or records and contains a covenant not to solicit, divert or appropriate any Restricted Clients (as defined in the agreements) of Company during their employment and for two years following the termination of their employment.
   
 
12

 
   
On September 18, 2006, the Company entered into a Consulting Agreement with Bart Birdsall to provide consulting services to evaluate geology and geophysical data in areas of interest to the Company and to identify certain drilling prospects. The Consulting Agreement provides that Mr. Birdsall would be paid $700 per day as well as 1% overriding royalty interest reduced to the net mineral interest acquired in each oil and gas prospect identified by Mr. Birdsall and accepted by the Company. The term of the agreement is until December 31, 2009 and the contract will be automatically extended for additional one year terms unless either party gives at least 30 days prior notice, prior to the end of the applicable term. The full text of the three employment agreements and the consulting agreement were filed as Exhibits 10.1, 10.2, 10.3 and 10.4, respectively, with its Form 10-KSB filed for the year ended December 31, 2007.

The Company gave Messrs. Suhr, Brown and Birdsall 30 days’ notice of termination of their employment or agreement with the Company as of May 1, 2007. Messrs. Suhr and Brown are no longer associated with the Company. Messr. Birdsall has continued to provide exploration efforts to the Company on a contract basis since May 1, 2007. The Company has not obtained a release from these contracts. The ultimate outcome of these contracts is unknown at this time.

PART III

9.
 
Directors, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of the Exchange Act

The directors of the Company as of December 31, 2009 are as follows:
   
Director
 
Age
 
Company Position or Office
 
Director Since
                     
Robert D. Burr
   
64
   
Chairman, President and CEO
   
1996
 
                     
Harry J. Peters
   
66
   
Director
   
2000
 
                     
Gregory B. Shea
   
47
   
Director
   
1999
 
                     
Stephen C. Larkin
   
50
   
Director and CFO
   
2009
 
   
ROBERT D. BURR, age 64, Bowling Green, Kentucky, was named interim president and Chief Executive Officer in April, 2007, and has been Chairman of the Board of the Company since May 1996. He served as President and Chief Executive Officer from May 1996 until March 1, 2000. Mr. Burr has also been the Chairman of the Board, President and Chief Executive Officer of Blue Ridge Group, Inc. (“BR Group”) since August 1993. Mr. Burr is a native of Port Arthur, Texas and attended McNeese State College, Lake Charles, Louisiana. He has been active for over 25 years in the oil and gas business with a myriad of companies.

HARRY J. PETERS, age 65, Bowling Green, Kentucky, served as Senior Vice President and Chief Operating Officer (COO) from May 2003 through September 2005. He was Senior Vice President-Acquisitions from August 2000 to April 2003. Mr. Peters served the Company as Senior Vice President-Sales and Marketing from April 2000 to July 2000 and has served as a Director since April 2000. A native of New York, he has over 30 years of experience in sales and marketing, both domestic and international. Over the years, he has developed close working relationships with investment bankers, institutional investors and securities dealers while directing market financing of reserve purchases, and raising drilling risk capital and venture capital for wells in Texas, Kentucky, Oklahoma, Louisiana, Colorado, West Virginia and Utah. Mr. Peters has been a director and Senior Vice President-Sales and Marketing of BR Group since April of 1999. He is a graduate of St. Michaels College in Santé Fe, New Mexico.

GREGORY B. SHEA, age 47, Bowling Green, Kentucky, has been a Director since 1999. From 1999 through June 2005, Mr. Shea served as Senior Vice President-Operations of the Company and from May 2002 through June 2005 he also served as Secretary-Treasurer. Mr. Shea has previously managed BR Group’s and Bayou City Exploration, Inc.’s Kentucky drilling and field operations, drilling over 350 wells from 1997 to 2002. During that time, Mr. Shea was also President of Blue Ridge Builders, Inc., a residential and commercial construction company in Bowling Green, Kentucky and a majority-owned subsidiary of BR Group since November 1994. Blue Ridge Builders, Inc. is responsible for the construction of over 70 properties in Kentucky and Tennessee. He was elected a Director of BR Group in February 1995. Between 1981 and 1986, he attended North Texas State University. Mr. Shea is also the son-in-law of Mr. Burr.
  
 
13

 
   
STEPHEN C. LARKIN, age 50, Bowling Green, Kentucky, was appointed as a Director in June 2009, and appointed as Chief Financial Officer on January 4, 2010.  Prior to becoming Chief Financial Officer, he served as Controller since April 1, 2009.  Mr. Larkin has also served as Chief Financial Officer of BR Group since June 2008.  Mr. Larkin earned a B.A. Degree from Michigan State University in 1981, an MBA Degree from Michigan State University in 1989 and an Executive MBA from the University of New Hampshire in 1997.

COMPLIANCE WITH SECTION 16(A) OF THE SECURITIES EXCHANGE ACT OF 1934

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.

The Company believes that during the 2009 fiscal year, its officers, directors and 10% shareholders complied with the Section 16(a) filing requirements in a timely fashion.

REPORT OF THE AUDIT COMMITTEE

As of the date of this filing, the Company has not appointed members to an audit committee and an audit committee does not exist. Therefore, the role of an audit committee has been conducted by the Board of Directors of the Company.

The Company intends to establish an audit committee. When established, the audit committee will be comprised of at least two disinterested members. The audit committee’s primary function will be to provide advice with respect to the Company’s financial matters and to assist the Board of Directors in fulfilling its oversight responsibilities regarding finance, accounting, tax and legal compliance. The audit committee’s primary duties and responsibilities will be: (i) to serve as an independent and objective party to monitor the Company’s financial reporting process and internal control system; (ii) to review and appraise the audit efforts of the Company’s independent accountants; (iii) to evaluate the Company’s quarterly financial performance as well as its compliance with laws and regulations; (iv) to oversee management’s establishment and enforcement of financial policies and business practices; and (v) to provide an open avenue of communication among the independent accountants, management and the Board of Directors.

Currently, the entire Board of Directors performs the duties of an Audit Committee and oversees the Company’s financial reporting process. Management has the primary responsibility for the financial statements and the reporting process including the systems of internal controls. In fulfilling its oversight responsibilities, the Board of Directors reviewed the interim financial statements filed quarterly and the audited financial statements in the Annual Report with management including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments, and the clarity of disclosures in the financial statements. At this time, the Board of Directors does not have a financial expert because of its small company size; however, the Board of Directors intends to appoint a financial expert in the future.
   
 
14

 
   
10.
 
Executive Compensation

The following table shows information for the year ended December 31, 2009 regarding the compensation of our Chief Executive Officers.

SUMMARY COMPENSATION TABLE
   
Name and
Principal
Position
 
Year
 
Salary
($)
 
Bonus
($)
 
Stock
Awards
($)
 
Option
Awards
($)
 
Non-equity
incentive plan
compensation
Non-Equity
 
Change in
pension value
and non-
qualified
deferred
compensation
earnings ($)
 
All other
compensation
($)
 
Total
($)
                                                     
Robert D. Burr President and CEO
 
2009
   
68,000
   
   
   
33,000
   
   
   
 
101,000
    
Employment Agreements

There are no employment agreements in place as of December 31, 2009.

STOCK OPTION PLAN

On February 22, 2005, the Board of Directors approved the Bayou City Exploration, Inc. (formerly Blue Ridge Energy, Inc.) 2005 Stock Option and Incentive Plan (the “Stock Option Plan”). The Stock Option Plan allows for the granting of stock options to eligible directors, officers, employees, consultants and advisors.

Effective January 1, 2006, the Company accounts for the Plan in accordance with revised Statement of Financial Accounting Standards (SFAS) No. 123, Share-Based Payment (SFAS 123(R)). Accordingly, stock compensation expense has been recognized in the statement of operations based on the grant date fair value of the options for the period ended December 31, 2009. Prior to January 1, 2006, the Company accounted for stock compensation cost under the Plan in accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, (APB 25) as permitted by SFAS 123 as originally issued. Under APB 25, stock compensation expense was recognized only if the options had intrinsic value (difference between option exercise price and the fair market value of the underlying stock) at the date of grant. As the Company issued all options with an exercise price equal to the grant date market value of the underlying stock, no compensation expense had previously been recorded by the Company.

The maximum number of shares with respect to which options may be awarded under the Stock Option Plan is seven million (7,000,000) common shares of which approximately 900,000 shares remain available for grant as of December 31, 2009. The following table shows more information about our Stock Option Plan.
    
 
15

 
  
EQUITY COMPENSATION PLAN INFORMATION
   
Plan category
 
Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights
 
Weighted-average
exercise price of
outstanding options,
warrants and rights
 
Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities to be issued
upon exercise of
outstanding options,
warrants, and rights)
                   
Equity compensation plans approved by security holders
   
6,100,000
 
$
0.028
   
900,000
                   
Equity compensation plans not approved by security holders
 
None
   
n/a
 
None
                   
Total
   
6,100,000
 
$
0.028
   
900,000

The following table shows information regarding awards granted to each of our Named Executive Officers under our Stock Option Plan outstanding as of December 31, 2009.

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
OPTION AWARDS
    
Name
 
Number of
Securities
Underlying
Unexercised
Options
(#)
Exercisable
 
Number of
Securities
Underlying
Unexercised
Options
(#)
Unexercisable
 
Equity Incentive Plan Awards: Number of
Securities Underlying
Unexercised
Unearned Options
(#)
 
Option Exercise
Price
($)
 
Option
Expiration
Date
Robert D. Burr
President and CEO
   
2,350,000
   
   
 
$
0.01
   
05/18/19
                               
Harry J. Peters
Director
   
950,000
   
   
 
$
0.01
   
05/18/19
                               
Gregory B. Shea
Director
   
700,000
   
   
 
$
0.01
   
05/18/19
                               
Stephen C. Larkin
   
333,333
   
666,667
   
 
$
0.01
   
05/18/19

BOARD MEETINGS AND COMPENSATION
  
During the year ended December 31, 2009, the Board of Directors of the Company met on four occasions. Each of the Company’s directors attended the meeting of the Board of Directors. While the Company has no formal policy, directors are encouraged to attend the Company’s annual meeting of stockholders. The Company does not have an Audit, Nomination or Compensation Committee.
   
 
16

 
    
Based on the Company’s history and experience without a nominating committee, the Board of Directors believes it is appropriate for the Company to continue operations without a standing nominating committee. Historically, there have not been many vacancies on the Board and the entire Board has identified available, qualified candidates. All directors participate in the consideration of the director nominees. Qualifications for consideration as a director nominee may vary according to the skills and experience being sought to complement the existing Board’s composition. However, in making nominations the Board will consider the individual’s integrity, business experience, industry experience, financial background, time availability and other skills and experience possessed by the individual. The Board of Directors will consider persons for director nomination who are proposed by stockholders. The Board of Directors will evaluate nominees for director on the same basis regardless of whether the nominee is recommended by an officer, director or stockholder. Stockholders who wish to propose a person for consideration by the Board of Directors as a director nominee should send the name of such person, together with information concerning such person’s qualifications and experience, in writing to the Chairman of the Board at the Company’s address.

During 2009, the directors of the Company received the following compensation for their services as directors of the Company.

DIRECTOR COMPENSATION
   
Name
 
Fees
Earned
or
Paid in
Cash
($)
 
Stock
Awards
($)
 
Option
Awards
($)
 
Non-Equity
Incentive Plan
Compensation
($)
 
Non-
Qualified
Deferred
Compensation
Earnings
($)
 
All Other
Compensation
($)
 
Total
($)
Robert D. Burr
   
   
   
   
   
   
   
Harry J. Peters
   
   
   
   
   
   
   
Gregory B. Shea
   
   
   
   
   
   
   
Stephen C. Larkin
   
   
   
   
   
   
   
  
11.
 
SECURITIES OWNERSHIP OF BENEFICIAL OWNERS AND MANAGEMENT

The table below sets forth each stockholder who is known to the Company to be the beneficial owner of more than 5% of the Common Stock of the Company at December 31, 2009. The Securities Exchange Act of 1934 requires certain persons, including the Company’s directors and executive officers, to file reports with the SEC regarding beneficial ownership of certain equity securities of the Company. The Company has relied upon information known to the Company and these SEC beneficial ownership filings in disclosing the following information regarding security ownership of 5% beneficial owners and management.

Name and Address of Beneficial Owner
 
Amount and Nature of
Beneficial Ownership
 
Percent
of Class
                 
Robert D. Burr
632 Adams Street, Suite 710
Bowling Green, KY 42101
   
4,933,971
(1)
   
18.5
%
 
               
Blue Ridge Group, Inc.
632 Adams Street, Suite 710
Bowling Green, KY 42101
   
3,638,371
(2)
   
13.7
%

(1)
 
Mr. Burr’s beneficial ownership includes vested options of 2,350,000 shares and 2,583,971 shares (71.02% of 3,638,371) of BR Group’s direct ownership of common shares. By virtue of his position as Chairman of the Board of BR Group, Mr. Burr may be deemed to beneficially own the 3,638,371 shares of the Company’s Common Stock beneficially owned by BR Group Mr. Burr disclaims beneficial ownership of these shares except to the extent described in the following sentence. Mr. Burr beneficially owns approximately 71.02% of the outstanding shares of BR Group, which beneficially owns approximately 13.7% of the Company.
(2)
 
BR Group’s beneficial ownership is attributable to its direct ownership of 3,638,371 shares of the Company’s Common Stock.
  
 
17

 
  
The table below sets forth the beneficial ownership of the Company’s Common Stock by each executive officer, director and director nominee of the Company as of December 31, 2009.

Name of Beneficial Owner
 
Amount and Nature of
Beneficial Ownership (4)
 
Percent
of Class
                 
Robert D. Burr (1)
   
4,933,971
     
18.5
%
Harry J. Peters (2)
   
1,014,763
     
3.8
%
Gregory B. Shea (3)
   
764,763
     
2.9
%
Stephen C. Larkin (4)
   
   333,333
     
  1.2
All directors, nominees and officers as a group (4 persons)
   
7,046,830
     
26.4
%

(1)  
Mr. Burr’s beneficial ownership includes vested options of 2,350,000 shares and 2,583,971 shares (71.02% of 3,638,371) of BR Group’s direct ownership of common shares. By virtue of his position as Chairman of the Board of BR Group, Mr. Burr may be deemed to beneficially own the 3,638,371 shares of the Company’s Common Stock beneficially owned by BR Group however, Mr. Burr disclaims beneficial ownership of these shares except to the extent described in the following sentence. Mr. Burr beneficially owns approximately 71.02% of the outstanding shares of BR Group, which beneficially owns approximately 13.7% of the Company.
(2)
 
Mr. Peters’ beneficial ownership includes vested options of 950,000 shares and 64,763 shares (1.78% of 3,638,371) of BR Group’s direct ownership of common shares.
(3)
 
Mr. Shea’s beneficial ownership includes vested options of 700,000 shares and 64,763 shares (1.78% of 3,638,371) of BR Group’s direct ownership of common shares.
(4)
 
Mr. Larkin’s beneficial ownership interest includes vested options of 333,333 shares.
(5)
 
These beneficial ownerships represent vested stock options and options exercisable within 60 days of December 31, 2009.

12.
 
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

A. Common Stock Transactions

As of December 31, 2009, there are 26,653,633 shares of common stock issued and outstanding. A total of 3,638,371 shares are held by Blue Ridge Group, Inc. and the remaining 23,015,262 shares are held by approximately 600 shareholders of record.

B. Payables and Notes Payable to Related Parties.

As of December 31, 2009 and December 31, 2008 the Company had the following debts and obligations to related parties:
    
   
December 30, 2009
   
December 31, 2008
 
Trade payable to BR Group
 
$
-0-
   
$
3,000
 
Payable to BR Group for proceeds from sale of asset
   
-0-
     
-0-
 
Drilling Advances payable to Gulf Coast Drilling Co.
   
50,000
     
104,000
 
Payable to minority shareholders for operating capital
   
85,000
     
85,000
 
Note payable to BR Group
   
-0-
     
123,000
 
Line of Credit payable to BR Group for operating capital
   
375,000
     
393,000
 
Note payable to Peter Chen — a minority shareholder
   
100,000
     
100,000
 
Accrued Interest
   
-0-
     
55,000
 
                 
Total Payable or Notes Payable to Related Parties
 
$
610,000
   
$
863,000
 
   
The promissory note payable to BR Group was originally entered into October 1, 2004, for $123,000 to settle outstanding cash advances received from BR Group during prior periods. The note was interest bearing at the rate of 7.95% and was payable in full on or before July 17, 2009. The note was secured by all oil and gas production income that the Company holds until the note was paid in full. The Company paid the note in full, with all accrued interest, on March 24, 2009

The line of credit payable to BR Group was executed by the Company on July 17, 2009, in the amount of $500,000 to finance the Company’s operations.  As of December 31, 2009 the Company has a liability balance under this line of credit arrangement due BR Group in the amount of 375,000. The line of credit provides for interest at the rate of 8% per annum on the unpaid outstanding balance and is due upon demand. If no demand for payment is made by BR Group, the line of credit balance plus all accrued unpaid interest is due July 17, 2010.  Accrued interest on the note as of December 31, 2009 was -0-.
   
 
18

 
   
The fee mineral acres of the McAllen West Prospect previously secured the line of credit from BR Group. In February, 2008, the Company was successful in selling its McAllen West Prospect and received $358,000. The Company had costs of $300,000 associated with this prospect previously included in property and equipment on the Company’s balance sheet resulting in a $58,000 gain on sale of assets recognized in the Company’s statement of operations. The sales proceeds from the secured property have not been paid to BR Group. BR Group has not yet demanded the proceeds from the sale to be paid on the secured indebtedness but instead has allowed the sales proceeds to remain in the Company to be used for operating capital.

During the 2nd and 3rd quarters, 2007, a minority shareholder loaned the Company $85,000 to finance the Company’s operations. No loan documents were executed.

During the 4th quarter, 2007, Peter Chen, a minority shareholder loaned the Company $100,000 to finance the Company’s operations. The Company executed a promissory note on October 4, 2007; the note is due on demand and bears an interest rate of 0%.

As of December 31, 2009 and 2008, the Company owed Gulf Coast Drilling Company (an affiliate of BR Group) $50,000 and 104,000, respectively, in drilling advances received for the King Unit #1 well that were in excess of BR Group’s participation interest in the well.

As of December 31, 2009 and 2008, the Company had a trade payable due to BR Group in the amount of -0- and $3,000, respectively

13.
 
EXHIBITS

A) EXHIBITS

23.1   Consent of Pressler Petroleum Consultants, Inc.
     
31.1
 
Section 302 Certification of Chief Executive Officer
     
31.2
 
Section 302 Certification of Chief Financial Officer
     
32.1
 
Section 906 Certification of Chief Executive Officer
     
32.2
 
Section 906 Certification of Chief Financial Officer
     
99.1   Report of Pressler Petroleum Consultants, Inc.

14.
 
PRINCIPAL ACCOUNTANT FEES AND SERVICES

INDEPENDENT AUDITORS

The Company hired Killman, Murrell & Company, PC (“Killman”) as its independent auditors for auditing the Company’s financial statements for the year ended December 31, 2009 and December 31, 2008.  It is not anticipated that the auditors will be present at the Annual Meeting.

AUDIT FEES

The Company incurred $22,000 in fees from Killman for the review of three 2009 quarterly 10-Q reports and approximately $30,000 for its annual December 31, 2009 audit. The Company incurred $16,000 in fees from Killman for the review of the three 2008 quarterly 10-Q reports and $25,000 from Killman for auditing the Company’s financial statements for December 31, 2008 and review of the annual 10-K.

TAX FEES

During 2009 the Company engaged an independent CPA firm other than its independent auditors to prepare its 2008 federal and state tax returns. Danny W. Looney, PC billed the Company $4,000 during 2009 for the preparation of the Company’s 2008 federal and state income tax filings. During 2008 Danny W. Looney, PC billed the Company $4,000 for the preparation of the Company’s 2007 federal and state income tax filings. No other fees were charged by Killman during 2009 and 2008. The Board of Directors has considered the scope of the above services and concludes these services do not impair the auditor’s independence.
   
 
19

 
 
PART IV

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, in the City of Bowling Green, State of Kentucky on February 25 , 2011.
   
 
Bayou City Exploration, Inc.
 
     
 
By:  
/s/ Charles T. Bukowski
 
   
Chief Executive Officer and President 
 
       

     
 
By:  
/s/ Stephen C. Larkin
 
   
Chief Financial Officer 
 
       
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in capacities and the dates indicated.
           
Bayou City Exploration, Inc., Registrant
 
           
           
Date: February 25 , 2011
 
           
           
By:
/s/ Charles T. Bukowski
 
By:
/s/ Stephen C. Larkin
 
           
 
Charles T. Bukowski, Director
   
 Stephen C. Larkin, Director
 
           
By:
/s/ Travis N. Creed
       
           
 
Travis N. Creed, Director
       
   
 
20

 
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
  
Board of Directors and Shareholders
Bayou City Exploration, Inc.
Bowling Green, Kentucky

We have audited the accompanying balance sheets of Bayou City Exploration, Inc. as of December 31, 2009 and 2008, and the related statements of operations, stockholders’ deficit, and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Bayou City Exploration, Inc. as of December 31, 2009 and 2008, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
    
 
  
/s/ Killman, Murrell & Company, P.C.
 
Killman, Murrell & Company, P.C. 
 
Odessa, Texas 
 
 

March 31, 2010
    
 
F-1

 
 
BAYOU CITY EXPLORATION, INC.
   
BALANCE SHEETS
   
   
December 31,
2009
   
December 31,
2008
 
ASSETS
           
             
CURRENT ASSETS:
           
Cash
  $ 51,704     $ 18,042  
Accounts receivable:
               
Trade and other (net of allowance for doubtful accounts - $37,468 as of December 31, 2009 and $222,011 as of December 31, 2008).
    165,946       210,674  
TOTAL CURRENT ASSETS
    217,650       228,716  
                 
OIL & GAS PROPERTIES, NET
    308,967       5,834  
                 
TOTAL ASSETS
  $ 526,617     $ 234,550  
                 
LIABILITIES AND STOCKHOLDERS' DEFICIT:
               
                 
CURRENT LIABILITIES:
               
Accounts payable and accrued expenses
  $ 133,071     $ 354,789  
Accounts payable - related party
    134,906       246,298  
AFE advances from JIB owners
    -       51,186  
Notes payable - related parties
    475,000       616,569  
                 
TOTAL CURRENT LIABILITIES
    742,977       1,268,842  
                 
ASSET RETIREMENT LIABILITY
    -       43,806  
                 
TOTAL LIABILITIES
    742,977       1,312,648  
                 
STOCKHOLDERS' DEFICIT:
               
Preferred stock, $0.001 par value; 5,000,000 shares authorized; 0 shares issued and outstanding as of December 31, 2009 and December 31, 2008
    -       -  
Common stock, $0.005 par value; 150,000,000 shares authorized; 26,653,633 shares issued and outstanding at December 31, 2009 and December 31, 2008
    133,268       133,268  
Additional paid in capital
    13,363,430       13,284,765  
Accumulated deficit
    (13,713,058 )     (14,496,131 )
                 
TOTAL STOCKHOLDERS' DEFICIT
    (216,360 )     (1,078,098 )
                 
TOTAL LIABILITIES AND SHAREHOLDERS' DEFICIT
  $ 526,617     $ 234,550  
 
 
The accompanying notes are an integral part of these financial statements
   
 
F-2

 
 
BAYOU CITY EXPLORATION, INC.
   
STATEMENTS OF OPERATIONS
   
   
Years Ended December 31
 
   
2009
   
2008
 
OPERATING REVENUES:
           
Oil and gas sales
  $ 1,025,300     $ 287,808  
Gain on sale of oil and gas properties
            57,750  
TOTAL OPERATING REVENUES
    1,025,300       345,558  
                 
OPERATING COSTS AND EXPENSES:
               
Lease operating expenses and production taxes
    99,596       36,228  
Abandonment and dry hole costs
    99,583       28,311  
Depletion and amortization
    11,110       33,484  
General and administrative costs
    374,284       329,927  
                 
TOTAL OPERATING COSTS
    584,573       427,950  
                 
OPERATING INCOME (LOSS)
    440,727       (82,392 )
                 
OTHER INCOME (EXPENSE):
               
Interest expense
    (45,304 )     (45,108 )
Gain (loss) on sale of non oil and gas assets
    -       (79,879 )
Forgiveness of debt
    167,344       32,514  
Bad debt recovery
    170,537       -  
Miscellaneous income
    49,769       -  
                 
NET INCOME (LOSS) BEFORE INCOME TAX
    783,073       (174,865 )
                 
Income tax provision
    -       -  
                 
NET INCOME (LOSS)
  $ 783,073     $ (174,865 )
                 
                 
NET INCOME (LOSS) PER COMMON SHARE
  $ 0.03     $ (0.01 )
                 
Weighted Average Common Shares Outstanding - Basic and Diluted
    26,653,633       26,653,633  
 
 
See accompanying independent auditor’s report and notes to financial statements
   
 
F-3

 
 
BAYOU CITY EXPLORATION, INC.
   
STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
 
   
Common Stock
   
 
   
 
 
   
Shares
   
Amount
   
Additional
Paid in Capital
   
Accumulated
Deficit
   
Total
 
                               
 Balance at 12-31-07
  $ 26,653,633     $ 133,268     $ 13,276,765     $ (14,321,266 )   $ (911,233 )
                                         
 Interest on non-interest bearing note payable to shareholder
    -       -       8,000       -       8,000  
 Net loss
    -       -       -       (174,865 )     (174,865 )
 Balance at 12/31/2008
    26,653,633       133,268       13,284,765       (14,496,131 )     (1,078,098 )
                                         
 
                                       
 Interest on non-interest bearing note payable to shareholder
    -       -       8,000       -       8,000  
 Stock options issued
    -       -       70,665       -       70,665  
 Net income
    -       -       -       783,073       783,073  
 Balance at 12/31/2009
  $ 26,653,633     $ 133,268     $ 13,363,430     $ (13,713,058 )   $ (216,360 )
 
 
See accompanying independent auditor’s report and notes to financial statements
   
 
F-4

 
      
BAYOU CITY EXPLORATION, INC.
  
STATEMENTS OF CASH FLOWS
   
   
Years Ended December 31
 
   
2009
   
2008
 
CASH FLOW FROM OPERATING ACTIVITIES:
           
             
Net Income (Loss)
  $ 783,073     $ (174,865 )
Adjustments to reconcile net income (loss) to net cash flows used in operating activities:
               
Depreciation, depletion, and amortization
    11,110       33,484  
Abandonment and dry hole costs
    99,583       28,311  
Gain on sale of oil and gas properties
    -       (57,750 )
Loss on sale of non oil and gas assets
    -       79,879  
Interest contributed by shareholder
    8,000       8,000  
Stock option expense
    70,665       -  
Forgiveness of debt
    (167,344 )     (32,514 )
Change in operating assets and liabilities:
               
Accounts receivable - trade
    44,728       (197,217 )
Prepaid expense and other assets
    -       7,024  
AFE advances - JIB owners
    (51,186 )     -  
Accounts payable - related party
    (111,392 )     (35,667 )
Accounts payable and accrued liabilities
    (54,375 )     (139,364 )
Long term liability - P&A costs
    (43,806 )        
                 
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
    589,056       (480,679 )
                 
                 
CASH FLOW FROM INVESTING ACTIVITIES:
               
Purchase of oil and gas properties
    (413,825 )     (3,977 )
Proceeds from sale of assets
    -       408,937  
                 
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES
    (413,825 )     404,960  
                 
CASH FLOWS FROM FINANCIANG ACTIVITIES:
               
                 
Payments on long term debt
    -       (4,627 )
Proceeds from related party line of credit
    65,450       77,374  
Payments on related party line of credit
    (207,019 )     (700 )
                 
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
    (141,569 )     72,047  
                 
NET INCREASE IN CASH
    33,662       (3,672 )
                 
CASH AT BEGINNING OF YEAR
    18,042       21,714  
                 
CASH AT END OF YEAR
  $ 51,704     $ 18,042  
                 
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
               
                 
Cash paid for interest
  $ 37,304     $ 242  
                 
Cash paid for federal income taxes
  $ -     $ -  
 
 
See accompanying independent auditor’s report and notes to financial statements
   
 
F-5

 
   
BAYOU CITY EXPLORATION, INC.
NOTES TO FINANCIAL STATEMENTS
December 31, 2009 and 2008
  
1.  OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General
 
Bayou City Exploration, Inc., (the “Company”), a Nevada corporation, was organized in November 1994, as Gem Source, Incorporated (“Gem Source”), and subsequently changed the name to Blue Ridge Energy, Inc. in May 1996. In September 2005, the Company changed its name to Bayou City Exploration, Inc.
 
On April 4, 2007, the Company announced the relocation of their corporate headquarters to 632 Adams Street, Suite 700, Bowling Green, Kentucky 42101 in order to decrease overhead, consolidate operations and reduce the number of personnel on staff. This move was completed in May, 2007. The Company’s executive office in the year 2006 was located at 10777 Westheimer, Suite 170, Houston, Texas, 77042. Since relocating the Company’s headquarters to Bowling Green, Kentucky the Company has maintain only the geological contract staff in the Houston office for the continued development and sale of the Company’s prospects until June of 2008 when they eliminated the staff and closed the office.
 
The Company is engaged in the oil and gas business primarily in the gulf coast of Texas, east Texas, south Texas, and Louisiana. The Company develops oil and gas prospects for the drilling of oil and gas wells and attempts to sell the prospects to oil and gas exploration companies under terms that provide the participating company will provide the funds necessary to drill and complete a well on the prospect, reimburse the Company for any leasehold or exploration costs associated with the prospect, pay the Company a prospect fee for developing the oil and gas prospect, and allow the Company to retain a carried interest in the well to be drilled. The wells drilled by the Company included both exploratory and development wells.
 
Prior to May 1, 2007, the Company operated many of the wells for which it owned an interest. The Company no longer intends to operate properties. The Company will seek to sell a portion of the interest in each prospect it generates to an operator that will be responsible for the drilling and operating of the oil and gas properties. In prior years the Company has been licensed as an oil and gas operator with the Texas Railroad Commission in the state of Texas. During the second quarter 2007 the Company’s license with the Texas Railroad Commission to be an operator in the state of Texas was not renewed. The Company operated two wells in Texas and one in Louisiana. All three wells are now plugged and abandoned. The Company’s ownership in all remaining wells is through non-operated working and royalty interests.

Basis of Presentation

These financial statements have been prepared by management, who is responsible for their content, in accordance with accounting principles generally accepted in the United States of America.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Recently Issued Accounting Standards

The FASB established the FASB Accounting Standards Codification (“Codification”) as the source of authoritative U.S. generally accepted accounting principles (“GAAP”) recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements issued for interim and annual periods ending after September 15, 2009. The codification has changed the manner in which U.S. GAAP guidance is referenced, but did not have an impact on our financial position, results of operations or cash flows.
  
 
F-6

 
    
In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2010-06, “Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements.” This ASU requires some new disclosures and clarifies some existing disclosure requirements about fair value measurement as set forth in Accounting Standards Codification (“ASC”) 820. ASU 2010-06 amends ASC 820 to now require: (1) a reporting entity should disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; and (2) in the reconciliation for fair value measurements using significant unobservable inputs, a reporting entity should present separately information about purchases, sales, issuances, and settlements. In addition, ASU 2010-06 clarifies the requirements of existing disclosures. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Early application is permitted. The Company will comply with the additional disclosures required by this guidance upon its adoption in January 2010.

Also in January 2010, the FASB issued Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas—Oil and Gas Reserve Estimation and Disclosures.”  This ASU amends the “Extractive Industries—Oil and Gas” Topic of the Codification to align the oil and gas reserve estimation and disclosure requirements in this Topic with the SEC’s Release No. 33-8995, “Modernization of Oil and Gas Reporting Requirements (Final Rule),” discussed below.  The amendments are effective for annual reporting periods ending on or after December 31, 2009, and the adoption of these provisions on December 31, 2009 did not have a material impact on our financial statements.

SEC’s Final Rule on Oil and Gas Disclosure Requirements

On December 31, 2008, the Securities and Exchange Commission, referred to in this report as the SEC, issued Release No. 33-8995, “Modernization of Oil and Gas Reporting Requirements (Final Rule),” which revises the disclosures required by oil and gas companies.  The SEC disclosure requirements for oil and gas companies have been updated to include expanded disclosure for oil and gas activities, and certain definitions have also been changed that will impact the determination of oil and gas reserve quantities.  The provisions of this final rule are effective for registration statements filed on or after January 1, 2010, and for annual reports for fiscal years ending on or after December 31, 2009

In August 2009, the FASB issued ASU No. 2009-05, “Fair Value Measurements and Disclosures (Topic 820) — Measuring Liabilities at Fair Value,” related to fair value measurement of liabilities. This update provides clarification that in circumstances in which a quoted price in an active market for an identical liability is not available, a reporting entity is required to measure fair value using one or more valuation techniques. This guidance is effective for the first reporting period beginning after issuance.

In June 2009, the FASB issued guidance under ASC 105, “Generally Accepted Accounting Principles.” This guidance established a new hierarchy of GAAP sources for non-governmental entities under the FASB Accounting Standards Codification. The Codification is the sole source for authoritative U.S. GAAP and supersedes all accounting standards in U.S. GAAP, except for those issued by the SEC. The guidance was effective for financial statements issued for reporting periods ending after September 15, 2009. The adoption had no impact on the Company’s financial position, cash flows or results of operations.

In May 2009, the FASB issued guidance under ASC 855 “Subsequent Events,” which sets forth: (1) the period after the balance sheet date during which management of reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. The guidance was effective on a prospective basis for interim or annual financial periods ending after June 15, 2009.

In April 2009, the FASB updated its guidance under ASC 820, “Fair Value Measurements and Disclosures,” related to estimating fair value when the volume and level of activity for an asset or liability have significantly decreased and identifying circumstances that indicate a transaction is not orderly. The guidance was effective for interim and annual reporting periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009. The adoption of this guidance did not have any impact on the Company’s results of operations.
 
Also in April 2009, the FASB updated its guidance under ASC 825, “Financial Instruments,” which requires disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This guidance also requires those disclosures in summarized financial information at interim reporting periods. The guidance was effective for interim reporting periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009.
 
The FASB updated its guidance under ASC 805, “Business Combinations,” in April 2009, which addresses application issues on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This guidance was effective for business combinations occurring on or after the beginning of the first annual period on or after December 15, 2008.
   
 
F-7

 
  
In June 2008, the FASB updated its guidance under ASC 260, “Earnings Per Share.” This guidance clarified that all unvested share-based payment awards with a right to receive non-forfeitable dividends are participating securities and provides guidance on how to allocate earnings to participating securities and compute basic earnings per share using the two-class method. This guidance was effective for fiscal years beginning after December 15, 2008. The Company adopted this guidance on January 1, 2009. The adoption did not have a material impact on the Company’s earnings per share calculations.

In March 2008, the FASB issued guidance under ASC 815, “Derivatives and Hedging,” which changes the disclosure requirements for derivative instruments and hedging activities. Entities will be required to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related items affect an entity’s financial position, operations and cash flows. This guidance was effective as of the beginning of an entity’s fiscal year that begins after November 15, 2008. The Company adopted this guidance on January 1, 2009.

Revenue Recognition

Under the sales method, oil and gas revenue is recognized when produced and sold. Management fees are recognized under the accrual method and recorded when earned. Prospect fees charged under joint participation agreements are recorded after execution.

Accounts Receivable

Accounts receivable are from oil and gas sales produced and sold during the reporting period but awaiting cash payment, from expenditures paid on behalf of the limited partnerships, from expenditures on behalf of non-operators, including related parties and on oil and gas properties operated by the Company. Based upon a review of trade receivables as of December 31, 2009, a total of $37,000 was considered potentially uncollectible, this compares to $222,000 at December 31, 2008. A reserve for uncollectible receivables was recognized for this amount and is included in operating costs of the Company’s 2009 and 2008 statement of operations. Receivables are reviewed quarterly, and if any are deemed uncollectible, they are written off as bad debts.

Managed Limited Partnerships

Prior to 2004, the Company sponsored limited partnerships for which it serves as the Managing General Partner. The Company normally participates for 1% of the Limited Partnerships as the Managing General Partner and accounts for the investment under the equity method.  Revenues received and changes in the partnership investments are recorded as oil and gas revenues and net assets, respectively.

Oil and Gas Properties
  
The Company follows the successful efforts method of accounting for oil and gas producing activities. Under the successful efforts method of accounting, costs which relate directly to the discovery of oil and gas reserves are capitalized. These capitalized costs include:
 
 
(1)
 
the costs of acquiring mineral interest in properties,
 
(2)
 
costs to drill and equip exploratory wells that find proved reserves,
 
(3)
 
costs to drill and equip development wells, and
 
(4)
 
costs for support equipment and facilities used in oil and gas producing activities.
 
These costs are depreciated, depleted or amortized on the unit of productions method, based on estimates of recoverable proved developed oil and gas reserves. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed.
 
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, 2009 the Company had $186,000 in capitalized costs pending determination, but at December 31, 2008, the Company had no costs capitalized pending determination.

 
F-8

 

Accounting for Asset Retirement Obligations

The Company follows the provisions of Statement of Financial Accounting Standards (SFAS) No. 143(ASC 410), Accounting for Asset Retirement Obligations. SFAS No. 143(ASC 410) requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Prior to 2005, management determined that any future costs related to plugging and abandonment of producing wells would be substantially offset by the value of equipment removed from the well site and such estimates were immaterial to the financial statements. Therefore, no liability was recorded prior to 2005. Due to continued rising rig and fuel costs, a detailed estimate was made in the second quarter of 2005 to determine how these rising service costs would affect future plugging and abandonment costs. As a result of this analysis, management concluded that a liability should be recorded within the financial statements under the provisions of SFAS 143(ASC 410).  These costs are evaluated annually and adjusted accordingly under the guidelines of SFAS 143(ASC 410).  As of December 31, 2008 the assets have been fully impaired.  The balance of the long term liability is $44,000 for 2008.  There was no accretion expense in 2008.  The well was plugged and abandoned in 2009 and the Company paid its share of the costs and returned the balance of the liability in the amount of $45,000 to miscellaneous income in 2009.  As of December 31, 2009 the Company had no liability established for the two new wells that went into production in late 2009 due to the fact that production just started in the fourth quarter and any liability for plugging cannot be calculated.

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 $100,000 and $28,000 for the years ended December 31, 2009 and 2008, 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 SFAS No. 69 (ASC 932-235), “Disclosures about Oil and Gas Producing Activities,”
  
 
F-9

 

Income (Loss) Per Common Share
 
The Company calculates basic earnings per common share (“Basic EPS”) using the weighted average number of common shares outstanding for the period.
 
The following table provides the numerators and denominators used in the calculation of Basic EPS for the years ended December 31, 2009 and 2008:

   
2009
   
2008
 
Income (loss) from operations
 
$
783,000
   
$
(175,000
)
Less preferred stock dividends
   
-0-
     
-0-
 
             
                 
Income (loss) available to common stockholders
 
$
783,000
   
$
(175,000
)
             
                 
Common stock outstanding for the full year
   
26,653,633
     
26,653,633
 
                 
Assumed exercise of stock options
   
-0-
     
-0-
 
             
                 
Weighted average common shares outstanding
   
26,653,633
     
26,653,633
 
 
Stock Options
 
Effective January 1, 2006, the Company accounts for stock options in accordance with revised Statement of Financial Accounting Standards (SFAS) No. 123, Share-Based Payment (SFAS 123(R) (ASC 718 and 505). Accordingly, stock compensation expense has been recognized in the statement of operations based on the grant date fair value of the options for the period ended December 31, 2006 and thereafter.

Under SFAS 123(R) (ASC 718 and 505), the fair value of options is estimated at the date of grant using a Black-Scholes-Merton (“Black-Scholes”) option-pricing model, which requires the input of highly subjective assumptions including the expected stock price volatility. Volatility is determined using historical stock prices over a period consistent with the expected term of the option. The Company utilizes the guidelines of Staff Accounting Bulletin No. 107 (SAB 107) of the Securities and Exchange Commission relative to “plain vanilla” options in determining the expected term of option grants. SAB 107 permits the expected term of “plain vanilla” options to be calculated as the average of the option’s vesting term and contractual period.

The Company has used this method in determining the expected term of all options. The Company has several awards that provide for graded vesting. The Company recognizes compensation cost for awards with graded vesting on a straight-line basis over the requisite service period for the entire award. The amount of compensation expense recognized at any date is at least equal to the portion of the grant date value of the award that is vested at that date.

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

The Company maintains its cash balances in one financial institution located in Bowling Green, Kentucky. The balances are insured by the Federal Deposit Insurance Corporation for up to $250,000. At December 31, 2009 all cash balances were under $250,000.

Advertising

The Company expenses advertising costs as these are incurred.  There were no advertising costs incurred in 2009 or 2008.

Income Taxes
 
There is no provision for income taxes for the years ended December 31, 2009 and 2008. Income taxes are provided for under the liability method in accordance with SFAS No. 109, (ASC 740) “Accounting for Income Taxes,” which takes into account the differences between financial statement treatment and tax treatment of certain transactions. It is uncertain as to whether the Company will generate sufficient future taxable income to utilize the net deferred tax assets, therefore for financial reporting purposes, a valuation allowance of $3,638,000 and $3,960,000 has been recognized to offset the net deferred tax assets at December 31, 2009 and December 31, 2008, respectively.
   
 
F-10

 

Fair Value of Financial Instruments

The carrying cash value and cash equivalents, receivables, prepaids, accounts payable, notes payable and advances payable approximate their fair value.  Management is of the opinion that the Company is not exposed to significant interest or credit risk arising from these financial instruments.

Reclassifications

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

2.  SALE OF MCALLEN WEST PROSPECT
 
In February, 2008 the Company successfully sold its McAllen West Prospect and received proceeds of $358,000, plus retained a 12% royalty interest pursuant to a term royalty deed.  This is the property that the Sien well is on and is currently producing.  The Company recognized a gain of $58,000 on the sale of its McAllen West Prospect.

3.  RELATED PARTY TRANSACTIONS

A. Common Stock Transactions
 
As of December 31, 2009, there are 26,653,633 shares of common stock issued and outstanding. A total of 3,638,371 shares are held by Blue Ridge Group, Inc., a related company, and the remaining 23,015,262 shares are held by approximately 600 shareholders of record.

B. Payables and Notes Payable to Related Parties.

As of December 31, 2009 and December 31, 2008 the Company had the following debts and obligations to related parties:

   
December 31, 2009
   
December 31, 2008
 
Trade payable to BR Group
 
$
-0-
   
$
3,000
 
Drilling Advances payable to Gulf Coast Drilling Co.
   
50,000
     
104,000
 
Payable to minority shareholders for operating capital
   
85,000
     
85,000
 
Note payable to BR Group
   
-0-
     
123,000
 
Line of Credit payable to BR Group for operating capital
   
375,000
     
393,000
 
Note payable to Peter Chen — a minority shareholder
   
100,000
     
100,000
 
Accrued Interest
   
-0-
     
55,000
 
             
Total Payable or Notes Payable to Related Parties
 
$
610,000
   
$
863,000
 

The promissory note payable to BR Group was originally entered into October 1, 2004, for $500,000 to settle outstanding cash advances received from BR Group during prior periods. The note was interest bearing at the rate of 7.95% and is payable in full on or before July 17, 2009. The note was secured by all oil and gas production income that the Company holds until the note has been paid in full.  The Company paid the note in full, with all accrued interest, on March 24, 2009.

The line of credit payable to BR Group was executed by the Company on July 17, 2009, in the amount of $500,000 to finance the Company’s operations.  The line of credit provides for interest at the rate of 8% per annum on the unpaid outstanding balance and is due upon demand. If no demand for payment is made by BR Group, the line of credit balance plus all accrued unpaid interest is due July 17, 2010.  The balance of the line of credit was $375,000 and $393,000 for the years ended December 31, 2009 and 2008 respectively.  The accrued interest amount includes the unpaid interest on this line of credit in the amount of $-0- and $34,000 as of December 31, 2009 and 2008, respectively.

During the 4th quarter, 2007, Peter Chen, a minority shareholder loaned the Company $100,000 to finance the Company’s operations. The Company executed a promissory note on October 4, 2007; the note is due on demand and bears an interest rate of 0%.  The Company charges interest at 8.0% or $8,000 and regards it as interest expense and additional paid in capital.

As of December 31, 2009 and 2008, the Company owed Gulf Coast Drilling Company (an affiliate of BR Group) $50,000 and $104,000, respectively, in monies that were in excess of BR Group’s participation interest in the well.
  
As of December 31, 2009 and 2008, the Company had a trade payable due to BR Group in the amount of $-0- and $3,000 respectively.

 
F-11

 

4.  OIL AND GAS PROPERTIES
 
Oil and Gas properties, stated at cost, consisted of the following:

   
December 31
 
   
2009
   
2008
 
Proved oil and gas properties
  $ 129,000     $ 98,000  
Investment in partnerships
    21,000       21,000  
Unproved oil and gas properties
    186,000        
                 
Total oil and gas properties
    336,000       119,000  
                 
Less accumulated depletion and amortization
    (27,000 )     (113,000 )
Less impairment
           
Net oil and gas properties
  $ 309,000     $ 6,000  

Depletion and amortization expense was $11,000 and $33,000 during the years ended 2009 and 2008, respectively.   The decrease of $22,000 was due mainly to the fact that the two new producing wells went into production late in 2009 and produced very little in 2009.

During 2009 and 2008, the Company provided for abandonment and dry hole costs of $100,000 and $28,000, respectively.  The amount for 2009 was related to the Powers well drilled in the third quarter of 2009 which was a dry hole.   The 2008 amount was for abandonment of undeveloped properties.

5.  SEISMIC LICENSE

The Company entered into a “lifetime participation” membership in the Echo 3-D Gulf Coast, Permian Basin, Rocky Mountain and Mid-Continent Programs on July 1, 2004. There are 56 3-D data sets and 13,000 miles of 2-D data available for use in generating drilling prospects. The Board is considering various options to fully exploit this dataset for the greatest benefit to the Company.

This seismic license and any related “prospecting costs” such as geological and geophysical (G&G) consulting and G&G studies are defined as Exploration Costs under ASU 932 and such expenditures are to be expensed as incurred. During 2009 and 2008, $-0- and $15,000, respectively, was incurred for exploration costs and charged to expense.

6.  OPERATING LEASE

The Company entered into an operating lease for its administrative office in Houston, Texas on April 1, 2003. The lease expired on June 30, 2008 and was not renewed.  Total rental expense was approximately $58,000 for 2008

7.  INCOME TAXES
 
The tax effect of significant temporary differences representing the net deferred tax liability at December 31, 2009 and 2008 were as follows:

   
2009
   
2008
 
Net operating loss carry forward
  $ 3,357,000     $ 3,650,000  
Depletion, depreciation and amortization
    1,000       (3,000 )
Stock based compensation
    344,000       316,000  
Valuation allowance
    (3,702,000 )     (3,963,000 )
                 
Net deferred tax liability
  $     $  
 
The Company recorded $-0- as income tax expense for the years ended December 31, 2009 and 2008, as a result of the net loss recognized in 2008 and the use of net operating losses to offset its 2009 taxable income. Further, an income tax benefit was not recognized in either of the years due to the uncertainty of the Company’s ability to recognize the benefit from the net operating losses and, therefore, has recorded a full valuation allowance against the deferred tax assets.
    
 
F-12

 

The benefit for income taxes is different from the amount computed by applying the U.S. statutory corporate federal income tax rate to pre-tax loss as follows:
 
   
2009
   
2008
 
   
Amount
   
Percent
   
Amount
   
Percent
 
Income tax benefit (tax expense) computed at the statutory rate
  $ (266,000 )     34.0 %   $ 59,000       34.0 %
Increase (reduction) in tax benefit resulting from:
                               
State and local income taxes, net of federal tax effect
    (31,000 )     4.0 %     7,000       4.0 %
Adjustment for book to tax changes
    4,000       (38.0 )%     (32,000 )     (38.0 )%
Permanent items
          (0.0 )%           (0.0 )%
Valuation allowance (increase) decrease
    293,000       (38.0 )%     (34,000 )     (38.0 )%
Income tax benefit
  $           $        

The Company has an estimated net operating loss carry forward of $8,834,000 and $9,606,000 as of December 31, 2009 and 2008 respectively.  These net operating loss carry forwards will begin expiring in 2017 unless utilized sooner. Under Internal Revenue Code (IRC) Section 382, a change in ownership occurred on December 31, 2004 with the issuance of the additional shares from the private stock placement.  As of December 31, 2004, the net operating loss (NOL) carry forward amount was $3,341,000.  The Section 382 rule will limit the use of this December 31, 2004 NOL carry forward to $267,000 per year.

8.  COMMITMENTS AND CONTINGENCIES

Commitments

The Company has liabilities to various vendors with past due amounts including a judgment against it for $55,000.  These liabilities are recorded in the financial statements in accounts payable.  The Company also has significant payments for notes payable which will all mature in 2010.  The Company expects to pay these in full prior to the maturity dates in 2010. Other than noted above, neither the Company nor any of its properties is subject to any material pending legal proceedings.

Contingencies
   
The Company’s oil and gas exploration and production operations are subject to inherent risks, including blowouts, fire and explosions which could result in personal injury or death, suspended drilling operations, damage to or destruction of equipment, damage to producing formations and pollution or other environmental hazards. Previously the Company was an operator of oil and gas wells and carried general and umbrella liability insurance coverage of approximately $10 million per occurrence and in the aggregate to protect against these hazards. This coverage was in place through June, 2007, but the policies have now been cancelled due to expense of the policies, the Company’s decision to no longer be an operator of oil and gas wells, and the plugging and abandoning of all wells operated by the Company. At the time of this filing the Company is not insured for public liability and property damage to others with respect to its operations, except to the extent the Company may be covered as a non-operator in specific wells through the liability insurance policies of other operators.

9.  STOCKHOLDERS’ EQUITY

Authorization to Issue Shares — Preferred and Common

The Company is authorized to issue two classes of stock that are designated as common and preferred stock. On October 8, 2004, a Special Meeting of Stockholders was held requesting the approval of an Amendment to the Company’s Articles of Incorporation to increase the authorized shares of Common Stock from 20,000,000 shares to 150,000,000 shares. The amendment was approved at the Special Meeting of Stockholders. As of December 31, 2009, the Company was authorized to issue 155,000,000 shares of stock, 150,000,000 being designated as common stock and 5,000,000 shares designated as preferred stock.

Stock Options

On February 22, 2005, the Board of Directors adopted the 2005 Plan, the purposes of which are to (i) attract and retain the best available personnel for positions of responsibility within the Company, (ii) provide additional incentives to employees of the Company, (iii) provide directors, consultants and advisors of the Company with an opportunity to acquire a proprietary interest in the Company to encourage their continuance of service to the Company and to provide such persons with incentives and rewards for superior performance more directly linked to the profitability of the Company’s business and increases in shareholder value, and (iv) generally to promote the success of the Company’s business and the interests of the Company and all of its stockholders, through the grant of options to purchase shares of the Company’s Common Stock and other incentives.  Subject to adjustments upon changes in capitalization or merger, the maximum aggregate number of shares which may be optioned and sold or otherwise awarded under the 2005 Plan is seven million (7,000,000) common shares.  The Board of Directors administers the 2005 Plan. Generally, awards of options under the 2005 plan vest immediately or on a graded basis over a 5 year term. The maximum contractual period of options granted is 10 years. The 2005 Plan will terminate on February 22, 2015. As of December 31, 2009, approximately 900,000 shares are available for grant. Issuance of common stock from the exercise of stock options will be made with new shares from authorized shares of the Company.

 
F-13

 
   
There were no stock options granted during the year 2008.  In 2009 the Board of Directors decided that with the current stock options strike price compared to the current market price, that the outstanding options were simply not an incentive anymore to the current employees and directors.  Therefore, in May of 2009 the Company decided to cancel the outstanding options to the current employees and directors and issue new ones.  As a result, the Company cancelled 2,968,750 options and issued 6,000,000 options to its current employees, directors and key consultants and advisors of the Company and expensed $71,000 in relation to issuance of these options.  All options were issued at the strike price of $.01, with varying vesting terms.  All options granted have a ten year term.

At December 31, 2009, there were options, fully vested and expected to vest, to purchase 6,100,000 shares with a weighted average exercise price of $0.028, an intrinsic value of $287,000 and a weighted average contractual term of 9.23 years.

At December 31, 2008, there were options, fully vested and expected to vest, to purchase 3,068,750 shares with a weighted average exercise price of $0.428, an intrinsic value of $0.00 and a weighted average contractual term of 1.786 years.

For the years ended December 31, 2009 and 2008 there was $71,000 and $0 stock based compensation expense, respectively.

When calculating stock-based compensation expense the Company must estimate the percentage of non-vested stock options that will be forfeited due to normal employee turnover. Since its adoption of SFAS 123(R) (ASC 718 and 505) on January 1, 2006, the Company initially used a forfeiture rate of 20% and increased its forfeiture rate to 50% during the third quarter 2006. This was due to the Company experiencing a number of resignations of senior management personnel, each of whom had been awarded options which, in many cases, had not vested and therefore will be forfeited.  In the future the Company will use an appropriate estimate for the forfeiture rate at the time options are being granted.

The Company did not record any tax benefit for stock based compensation expense in accordance with its current policy on providing for a full income tax valuation allowance more fully explained in the “Income Taxes” note.

The following table provides a summary of the stock option activity for all options for the year ended December 31, 2009.

   
Number of
Weighted
 Average
   
Options
Exercise
 Price
 
Options at December 31,2008
    3,068,750     $ 0.428  
Options expired or cancelled in 2009
    (2,968,750 )     (0.410 )
Options issued 2009
    6,000,000       0.010  
Options at December 31, 2009
    6,100,000     $ 0.028  
Options exercisable at December 31, 2009
    4,766,667     $ 0.026  

10.  FAIR VALUE ESTIMATES

In February 2007 the FASB issued SFAS No. 157 (ASC 820) “Fair Value Measurements”.  The objective of SFAS 157 (ASC 820) is to increase consistency and comparability in fair value measurements and to expand disclosures about fair value measurements.  SFAS 157 (ASC 820) defines fair value, establishes a framework for measuring fair value in generally accepted accounting principals, and expands disclosures about fair value measurements.  SFAS 157 (ASC 820) applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements.

The Company measures its options at fair value in accordance with SFAS 157 (ASC 820).  SFAS 157 (ASC 820) specifies a valuation hierarchy based on whether the inputs to those valuation techniques are observable or unobservable.  Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect the Company’s own assumptions.  These two types of inputs have created the following fair value hierarchy:
 
 
Level 1 -
Quoted prices for identical instruments in active markets;
 
Level 2 -
Quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets; and
   
 
F-14

 
   
 
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, 2009 was as follows:

   
Quoted Active Markets for Identical Assets
   
Significant Other Observable Inputs
   
Significant Unobservable Inputs
   
Total
 
   
(Level 1)
   
(Level 2)
   
(Level 3)
       
Options
  $ ---     $ 71,000     $ ---     $ 71,000  

The Provisions of SFAS 157 are effective for fair value measurements made in fiscal years beginning after November 15, 2007.
Options were valued using the Black-Scholes model.

11.  SUBSEQUENT EVENTS:
 
In early 2010, the Company sold its 8.073375% royalty interest in the Sein #1 well to a group of related party partnerships for $1,000,000.  All of the related party partnerships share common management with the Company.  The entire transaction was cash.

In May 2009, the FASB issued SFAS No. 165 (ASC 855), subsequent events (“ASC 855”).  ASC 855 establishes general standards of accounting for and disclosure of events after the balance sheet date but before financial statements are issued or are available to be issued.  The adoption in the fourth quarter of 2009 did not have any material impact on the Company’s financial statements.  Accordingly, the Company evaluated subsequent events through March 31, 2010, the date the financial statements were issued.

12.  SUPPLEMENTAL INFORMATION ON OIL & GAS (Unaudited)
 
Capitalized Costs Relating to Oil and Gas
 
December 31,
 
Producing Activities
 
2009
   
2008
 
Unproved oil and gas properties
  $ 186,000     $ -  
Proved oil and gas properties
    149,000       119,000  
                 
Less accumulated depreciation, depletion amortization, and impairment
    (26,000 )     (113,000 )
                 
Net capitalized costs
  $ 309,000     $ 6,000  
                 
Costs incurred in Oil and Gas Producing Activities
               
For the years ended
               
Property acquisition costs
               
Proved
  $ 47,000     $ 119,000  
Unproved
    186,000       -  
Exploration costs
    67,000       -  
Development costs
    35,000       -  
Amortization rate per equivalent barrel of production
  $ 16.50     $ 1.18  
                 
Results of Operation for Oil and Gas Producing
               
Activities for the years ended
               
Oil and gas sales
  $ 25,000     $ 287,000  
Gain on sale of oil and gas properties
    1,000,000       -  
Impairment, abandonment, and dry hole costs
    (100,000 )     (43,000 )
Production costs
    (100,000 )     (21,000 )
Depreciation, depletion and amortization
    (11,000 )     (6,000 )
                 
      814,000       217,000  
Income tax expense
    -       -  
Results of operations for oil and gas producing
               
Activities (excluding corporate overhead and Financing costs)
  $ 814,000     $ 217,000  
   
 
F-15

 
  
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 - $61.18 bbl; Gas – $3.87 mcf for year ended December 31, 2009);
 
·
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-16

 

 
The following table sets forth estimated proved oil and gas reserves together with the changes therein for the year ended December 31, 2009:

   
Oil
   
Gas
 
   
(bbls)
   
(mcf)
 
Proved developed and undeveloped reserves
           
Beginning of year
    -       -  
Revisions of previous estimates
    -       -  
Improved recovery