10KSB 1 form10-ksb.txt PETROSEARCH ENERGY CORPORATION 10-KSB 12-31-2005 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 FORM 10-KSB [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended DECEMBER 31, 2005 [ ] TRANSITION REPORT PURSUANT TO 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ________ to ________ Commission file number: 000-51488 PETROSEARCH ENERGY CORPORATION (Exact name of small business issuer as specified in its charter) NEVADA 20-2033200 (State or other jurisdiction of (IRS Employer Identification No.) incorporation or organization) 675 BERING DRIVE, SUITE 200 HOUSTON, TX 77057 (Address of principal executive offices) (713) 961-9337 Securities Registered Under Section 12(b) Of The Exchange Act: Title Of Each Class n/a Name Of Each Exchange On Which Registered n/a Securities Registered Pursuant to 12(g) of the Exchange Act: Title Of Each Class Common Stock, $0.001Par Value Check whether the issuer is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act ____ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X] Check whether the issuer: (i) 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 (ii) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B contained herein, and no disclosure will be contained, to the best of registrant's knowledge, in definitive proxy or information statement incorporated by reference in Part III of this Form 10-KSB or any amendment to this Form 10-KSB. [X] The Issuer's revenues for the year ended December 31, 2005 were $1,701,043. The aggregate market value of Common Stock held by non-affiliates of the registrant at March 15, 2006, based upon the last reported sales prices on the OTCBB, was $45,847,691. As of March 15, 2006, there were approximately 31,057,101 shares of Common Stock outstanding. 1
TABLE OF CONTENTS PART I Page Item 1. Business 1 Item 2. Properties 2 Item 3. Legal Proceedings 8 Item 4. Submission of Matters to a Vote of Security Holders 8 PART II Item 5. Market for Common Equity, Related Stockholder Matters and Small Business Issuer Purchases Of Equity Securities 8 Item 6. Management's Discussion and Analysis or Plan of Operation 11 Item 7. Financial Statements 28 Item 8. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 28 Item 8A. Controls and Procedures 28 Item 8B. Other Information 28 PART III Item 9. Directors, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of The Exchange Act 29 Item 10. Executive Compensation 32 Item 11. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 35 Item 12. Certain Relationships and Related Transactions 37 Item 13. Exhibits 38 Item 14. Principal Accountant Fees and Services 38
2 PART I ITEM 1. BUSINESS Petrosearch Energy Corporation, a Nevada corporation formed in November 2004, is an independent crude oil and natural gas exploration and production company. We are the successor of Petrosearch Corporation, a Texas corporation formed in August 2003. All references to capitalization and business operations herein apply to our current capitalization and operating history, including our predecessor, Petrosearch Texas. We have established production in North Dakota, Texas and Oklahoma, and are currently engaged in exploration and development activities, including direct operator activities, through our subsidiary, Petrosearch Operating Company, L.L.C., in North Dakota, Texas, Oklahoma, Mississippi and Louisiana. OUR HISTORY We are the successor to the business of Petrosearch Corporation, a Texas corporation that was formed in August 2003 pursuant to a multi-step merger and holding company restructure. Under this merger plan, Petrosearch Corporation, a privately held Delaware corporation formed in April 2002, merged into a Texas subsidiary of Texas Commercial Resources, Inc., a publicly traded company. Simultaneously, TCRI created Petrosearch Texas as a subsidiary, and then consummated a holding company reorganization which resulted in the parent company (TCRI) and the subsidiary (Petrosearch Texas) reversing positions, such that TCRI became a subsidiary of Petrosearch Texas. In November 2003, immediately following the merger, we agreed to sell the outstanding stock of the TCRI subsidiary back to its former shareholders. Under the terms of the agreement, Petrosearch Texas conveyed the capital stock of the TCRI subsidiary to a designated trustee and paid certain existing liabilities of TCRI in exchange for 1,500,000 shares of TexCom, Inc. a separate Texas corporation, plus an indemnity related to certain existing TCRI liabilities. In November 2004, shareholders of Petrosearch Texas approved a 6.5-to-1 reverse stock split which took effect immediately prior to its merger with the Company on December 30, 2004. The effect of the merger, among other things, was to redomicile to Nevada. Upon the completion of the merger, shareholders of Petrosearch Texas were issued shares of our common stock representing 100% of the then issued and outstanding common shares. BUSINESS PLAN We were founded on the belief that, despite the steady decline of U.S. hydrocarbon reserves and production during the past three decades, the consolidation and restructuring of the upstream portion of the oil and gas industry (including exploration, drilling and production) had left a significant number of valuable oil and gas prospects and projects available for acquisition and development throughout North America. We continue to implement our business plan which is to find high quality prospects and projects and provide the capital, along with the technical, operational and administrative support and management oversight, needed to develop the projects. We have increased our SEC PV-10 proved reserves from $13.7 million as of December 31, 2004 to $46.5 million as of December 31, 2005. We have also successfully improved the quality of our portfolio and have acquired assets that have multiple year growth potential that allow us to efficiently control the amount and timing of our capital expenditures. In 2006 we plan to focus on the development of our high quality properties which will have a significant impact on our production, revenues and cash flows. In late 2005 and early 2006 we entered into two agreements, for significant resource projects that we believe will have a major impact on our future growth. The first project includes the purchase on November 15, 2005, of a 100% working interest in a waterflood project consisting of 1,755 acres in the Quinduno Field located in Roberts County, Texas. 1 The second project is covered by agreements with the Harding Company (Dallas, TX) which entered into a strategic Lease Acquisition and Development Agreement with ExxonMobil Corporation dated June 29, 2005 (the "ExxonMobil/Harding Agreement"). The ExxonMobil/Harding Agreement provides for the acquisition by Harding of leases and development in an area of mutual interest comprised of approximately 1.6 million acres in the Barnett Shale trend of five North Texas counties. Harding is responsible to serve as operator for a significant portion of the area of mutual interest. ExxonMobil is responsible for the construction of the gathering and evacuation system which will serve the area of mutual interest. The First Amended and Restated Program Agreement between Harding Company and Petrosearch (the "First Amended and Restated Program Agreement") provides for our acquisition from Harding of a 24.938% before payout and 14% after payout working interest in the project. Harding has also extended participation rights to two other companies under separate agreements. At the time of execution of the First Amended and Restated Program Agreement, Harding had not obtained from Exxon Mobil a consent to transfer and waiver of ExxonMobil's a preferential purchase right set forth in the ExxonMobil/Harding Agreement. At the time of our execution of and initial funding under the First Amended and Restated Program Agreement, Petrosearch did not have a direct contractual relationship with ExxonMobil. We believed that all conditions necessary to assign and convey the working interest from Harding had been met. We subsequently learned that ExxonMobil had not waived its right to consent and its preferential purchase rights. We further learned that ExxonMobil desired to explore possible alternative ownership structures beneficial to all concerned before providing a waiver of the preferential rights. On March 30, 2006 we entered into an Extension Agreement with ExxonMobil, Harding, and two other parties that extends the preferential purchase right of ExxonMobil until May 2, 2006 (the "Extension Agreement"). The purpose of the Extension Agreement is to give all the parties involved the ability to explore possible alternative structures with the goal to form an integrated venture which would include both upstream and pipeline assets and activities, which would better align each party's interest, and which would enhance the ability of the venture to assure that adequate pipeline capacity would be available to move natural gas to market. The opportunity to participate in an integrated venture which includes the gathering and evacuation system was not present in the First Amended and Restated Program Agreement and thus, the potential alternative structure has potential positive features. The Extension Agreement preserves to the parties all of their respective rights and claims as they existed prior to the execution of the Extension Agreement. However, in the event that the parties cannot achieve a mutually agreed alternative structure on or before May 2, 2006, ExxonMobil could exercise its preferential purchase right which, if exercised, would prevent our participation in the project. In the event of such a loss of this opportunity to participate in the project, our legal rights are not prejudiced by the Extension Agreement and we expect to pursue all potential remedies available to us relating to the factual circumstances surrounding these agreements. EMPLOYEES AND INDEPENDENT CONTRACTORS As of December 31, 2005, we had 12 employees, of which 7 are in management positions. None of our employees are represented by a union and we consider our employee relations to be good. Additionally, as of December 31, 2005 we had independent contractor relationships with one person. ITEM 2. PROPERTIES BARNETT SHALE PROJECT In February, 2006, we entered into a First Amended and Restated Program Agreement (the "First Amended and Restated Program Agreement") with Harding Company (Dallas, Texas) which provides for our participation with Harding Company and other oil and gas companies in the development of an Area of Mutual Interest representing a total of 1.6 million acres of Barnett Shale lands located in five North Texas Counties. The terms of the Program Agreement are subject to the terms of the existing Lease Acquisition and Development Agreement dated June 29, 2005, between Harding Company and ExxonMobil Corporation. We completed funding for $2.8 million of our $28 million obligation for the first phase of the project on February 6, 2006. Under the First Amended and Restated Program Agreement, until our first phase obligation of $28 million is expended, we will pay 34.432% of the costs of leasing activities, seismic and geologic costs and drilling and completion costs. Our revenue sharing percentage and operating cost-bearing percentage is 24.938% until we reach payout from production from all wells in the area of mutual interest; thereafter, our share of additional capital requirements and our working interest will be 14%. As of March 11, 2006, significant leasing activity has occurred. The first well was spudded on February 8, 2006 in Tarrant County, Texas, casing was cemented at 9,264 feet total depth on March 3rd, and this initial well is waiting completion. The second well in the project was spudded on March 15, 2006 in Ellis County, Texas. This project is subject to the pending resolution of all matters relating to the First Amended and Restated Program Agreement between the Company and Harding, and the contingencies set forth in the Extension Agreement between ExxonMobil, Harding, the Company and two other parties, as described in the Business section above. 2 NORTH TEXAS/PANHANDLE WATER FLOOD PROJECT In November, 2005 we acquired a 100% working interest in 1,755 acres in the Quinduno Field in Roberts County, Texas, in the Anadarko Basin. The Company's working interest reduces to 90% at payout, including the cost of acquisition. Proved reserves are estimated by Ryder Scott to be 2.0 MMbo and 1.1 Bcf of gas with an SEC PV-10 value of $33.7 million (at December 31, 2005). The purchase price (in November 2005) equated to $3.37 per proved barrel of oil equivalent (boe) based on a conversion factor of 6 Mcf/bo. As operator, we intend to extract the reserves through conventional water flood technology. The first phase of the project began in March 2006 with the drilling of a new well for production to a depth of 4,495 feet. An unexpected oil saturated dolomite was found, and tested, approximately 180 feet below the top of the target water flood horizon (Lower Albany Dolomite). The reservoir appears to be normally pressured and does not appear to have been produced in the past. The initial rate on pump is expected to be approximately 30 bopd with associated gas and water. The well will begin pumping in early April 2006 when surface facilities and power are available. As a result of this new zone discovery, the company is considering plans for its development that will not interfere with the planned water flood development. During 2006, a minimum of 4 old wells will be converted to injection wells and water injection will begin. RODNEY ISLAND, TENSAS PARISH, LOUISIANA In October 2005, we took over operations of the Harper Z-1 well on the Rodney Island prospect from the previous operator after casing was set and cemented. We are in the process of completing the well that was directionally drilled to a measured depth of 11,701 feet (vertical depth = 9,373 feet) and logged approximately 19 feet of oil sand in the Tuscaloosa Massive Sand. Re-mapping based on the additional data from the Harper Z-1 well indicates as many as 2 additional proved locations and 3 other identified locations. Ryder Scott estimates proved reserves net to our share as of December 31, 2005 to be - 49.4 Mbo and 26 MMcf. We have a 25% working interest before payout in the Harper Z-1 well and 18.75% working interest after payout. We have an 18.75% working interest in all additional wells. GRUMAN PROSPECT, STARK COUNTY, NORTH DAKOTA In September 2005 we purchased an additional 21.25% working interest, giving us an 85% working interest in this Lodgepole Reef oil well. We plan to drill a 9,900 foot increased density well up dip of the Gruman 18-1 well into the productive reef. Depending on the success of this new well, one of the two wells is expected to eventually be converted to water injection. Proved developed reserves in the prospect to our share of the well as of December 31, 2005, are 309 Mbo and 82 MMcf of natural gas, as estimated by a third party engineering firm, McCartney Engineering, LLC. The increased density well was spudded on March 28, 2006. SW GARWOOD, COLORADO COUNTY, TEXAS The initial well on this prospect, the Pintail #1, completed in the Upper Wilcox in December 2004, is expected to pay out by the end of the second quarter of 2006 from the first of 5 potentially productive zones. The well is currently producing approximately 500 Mcfd with 8 barrels of condensate. After pay out we will back-in for 33-1/3% working interest until payout of all project money spent to-date, including acquisition costs, at which time our working interest will reduce to 13.33%. The second well, Pintail Flats #1, was completed and fracture stimulated in May, 2005 in the deepest sand penetrated by the well in the Lower Wilcox. Completion problems resulting from the fracture treatment have resulted in the well performing below expectations (producing approximately 200 Mcfd) from this zone. An engineering review of available data is underway to determine the best way to maximize the production rate from the current zone. The well has an additional 5 potentially productive zones in the Lower Wilcox and 3 in the Upper Wilcox. 3 Net proved reserves for this project, as estimated by Ryder Scott Company are 1.2 Mbo and 642 MMcf of natural gas. Of the 2,402 acres in the prospect, we have: 20% working interest in approximately 240 acres; 33.33% working interest after payout on a well by well basis in 1,018 acres that reduces to 13.33% after project payout; 33.33% working interest after payout on a well-by-well basis in 640 acres that reduces to 18.33% at project payout; and 21.5% working interest after payout on a well by well basis in 444 acres that reduces to 19.25% at project payout. The cost of the two existing wells has been funded by our drilling partner. BUENA VISTA, JEFFERSON COUNTY, MISSISSIPPI We fracture stimulated and tested approximately 80 feet of potentially productive sands at the base of the Hosston zone without establishing commercial production in the Phillips-Burkley #1 well during 2005. The presence of gas was established but production rates were non-commercial. These sands have been abandoned and we plan to test and complete the well in a portion of approximately 280 feet of potentially productive Hosston sands up-hole, which appear to have superior reservoir properties compared to the sands already tested. The Phillips-Burkley # 1, an exploratory gas well on a leasehold position of 7,481 acres, has been funded by our drilling partner. We are the operator and have a 50% working interest in the well and acreage. If commercial reserves can be established, the structure could support in excess of 22 additional wells. MISSISSIPPI TUSCALOOSA PROJECTS We have identified five Tuscaloosa oil prospects in the Mississippi Inland Salt Basin, in Yazoo County, comprising a maximum of 2,295 acres and up to 18 potential drilling locations. Eight locations are planned to be drilled in 2007, ranging from 6,150 feet to 7,500 feet in depth. Approximately 40% of the required acreage has been leased and seismic data on the prospects is being reprocessed. We own 100% of the prospects and will operate the project. CENTRAL TEXAS/GULF COAST PROJECTS TAIT PROJECTS - COLORADO COUNTY, TEXAS. This is a natural gas prospect with the potential of up to 7 locations on 1,250 net acres. The prospects consist of two primary targets in the Upper Wilcox at approximately 10,000 feet. All acreage has been leased and we have acquired and analyzed 3-D seismic data on the prospect. The initial well has a planned spud date in the second quarter of 2006. Four wells in the project are planned for 2006. We have a 10% non-operated working interest. BURLESON COUNTY, TEXAS, PROJECTS -- A multi-well natural gas project that includes a total of 15 development and step-out locations in the Austin Chalk and Georgetown formations at approximately 10,000 feet vertical depth on a maximum leasehold position of up to 8,400 acres. Horizontal wells are planned with total measured length of approximately 13,000 feet. The initial well is planned to be spudded in the third quarter of 2006 with a second well planned in the fourth quarter of 2006. We will have a 37.5% non-operated working interest in the project. OIL AND NATURAL GAS RESERVES Our estimate of proved reserves is based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operations, development activities and costs, and work-over costs, all of which may in fact vary considerably from actual results. In addition, as prices and costs change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. 4 Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the unit-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our depreciation, depletion and amortization expense and accretion expense. Our oil and gas properties are also subject to a "ceiling" limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures. For the vast majority of our reserves, we engage independent petroleum engineering firms to prepare our estimates of proved hydrocarbon liquid and gas reserves. These reserve estimates have not previously been filed with any other Federal authority or agency. The following tables set forth summary information with respect to our proved reserves as of December 31, 2005, as estimated by compiling reserve information, which was prepared by the engineering firms of Ryder Scott Company, McCartney Engineering, LLC and internally generated engineering estimates (internal estimates make up less than 1% of our proved reserve estimates).
Net Reserves Pre-Tax Present Value of Future Net Revenues Category Oil (Bbls) Gas (Mcf) BOE(1) December 31, 2005 Proved Developed 330,838 229,747 369,129 $ 9,368,196 Proved Undeveloped 2,014,956 1,614,000 2,283,956 $ 37,084,128 Total Proved 2,345,794 1,843,747 2,642,011 $ 46,452,324 ------------------------------------------------------------------------------------------
(1) Estimated using a conversion ratio of 1.0 Bbl/6.0 Mcf (thousand cubic feet). Reserve engineering is a subjective process of estimating underground accumulations of crude oil, condensate and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may differ from those assumed in these estimates. Therefore, the pre-tax 10% Present Value of Future Net Revenues amounts shown above should not be construed as the current market value of the oil and natural gas reserves attributable to our properties. In accordance with the guidelines of the Securities and Exchange Commission, the engineers' estimates of future net revenues from our properties and the pre-tax 10% Present Value of Future Net Revenues thereof are made using oil and natural gas sales prices in effect as of the effective dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. PRODUCTIVE WELLS The following table sets forth the total number of our active well bores and working interest (WI) we maintain in each well as of March 15, 2006:
----------------------------------------------- NO. OF WI WI WELLS (OIL) (GAS) ----------------------------------------------- Gruman 18-1 1 85% 85% ----------------------------------------------- Gordon 1-18 1 95% N/A ----------------------------------------------- Maddox (Quinduno)(1) 2 100% 100% ----------------------------------------------- Pintail #1 (2) 1 33.33% 33.33% ----------------------------------------------- REP Pintail Flats(2) 1 33.33% 33.33% ----------------------------------------------- ----------------------------------------------- TOTAL PRODUCTIVE WELLS 6 -----------------------------------------------
5 (1) Project in which the Company's working interest reduces to 90% (as described in ITEM 2 - North Texas/Panhandle Water Flood Project). (2) Well in which we have a reversionary back-in interest after payout. (as described in ITEM 2 - SW Garwood, Colorado County, TX) Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections as of March 15, 2006. ACREAGE The following table summarizes our gross and net developed and undeveloped natural gas and oil wells and acreage under lease as of March 15, 2006:
----------------------------------------------------------- WELLS ACREAGE ----------------------------------------------------------- STATE GROSS NET GROSS NET ----------------------------------------------------------- ----------------------------------------------------------- DEVELOPED ACREAGE: ----------------------------------------------------------- Texas Garwood Gas 2 .667 1280 426 Maddox (Quinduno) 19 Oil 20 20 1755 1755 1 Gas ----------------------------------------------------------- North Dakota Oil (1) 1 .85 280 238 ----------------------------------------------------------- Oklahoma Oil 1 .95 610 579 ----------------------------------------------------------- ----------------------------------------------------------- UNDEVELOPED ACREAGE: ----------------------------------------------------------- Louisiana 2,000 500 ----------------------------------------------------------- Texas 9,347 3,173 ----------------------------------------------------------- ----------------------------------------------------------- Mississippi 7,925 4,325 ----------------------------------------------------------- Oklahoma 7,366 6,563 ----------------------------------------------------------- Montana 2,108 2,108 ----------------------------------------------------------- TOTAL 24 22.5 32,671 19,667 -----------------------------------------------------------
Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to the extent that would permit the production of commercial quantities of natural gas or oil, regardless of whether or not such acreage contains proved reserves. As is customary in the oil and gas industry, we can retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by payment of delay rentals during the remaining primary term of such a lease. The natural gas and oil leases in which we have an interest are for varying primary terms; however, most of our developed lease acreage is beyond the primary term and is held so long as natural gas or oil is produced. 6 OPERATOR ACTIVITIES We currently operate all of our producing properties, and will generally seek to become the operator of record on properties we drill or acquire in the future. We will have a non-operated interest in the Barnett Shale project (pending resolution of all matters associated with Program Agreement and Extension Agreement described herein) and in one exploratory well being drilled in Woodward County, Oklahoma. DRILLING ACTIVITIES The following table sets forth our drilling activities for the last 3 fiscal years. Our working interests in the productive wells owned as of December 31, 2005, range from a direct working interest of 95% to after payout working interest of 33-1/3%. In 2005, we drilled two additional wells not shown on the table; the Harper Z-1 in Rodney Island, Tensas Parish, Louisiana and the Phillips-Burkley #1 in Jefferson County, Mississippi. Both of these wells were in various stages of testing or completion as of March 15, 2006 and commercial viability had not been established as of that date. Subsequent to December 31, 2005, we have drilled one exploratory well and spudded a second well in Texas, one development well in Texas, and one exploratory well in Oklahoma Oklahoma and spudded an increased density well in North Dakota. All three of the new wells that have we completed drilling are in various stages of testing or completion.
-------------------------------------------- Year Ended December 31, -------------------------------------------- 2005 2004 2003 -------------------------------------------- Development Wells: -------------------------------------------- Productive 4 (1) 5 -0- -------------------------------------------- Non-Productive 0 -0- -0- -------------------------------------------- TOTAL 4 5 -0- -------------------------------------------- -------------------------------------------- Exploratory Wells: -------------------------------------------- Productive 1 (2) 4 3 -------------------------------------------- Non-Productive 3 10 -0- -------------------------------------------- TOTAL 4 14 3 -------------------------------------------- -------------------------------------------- Total Wells: -------------------------------------------- Productive 5 9 3 -------------------------------------------- Non-Productive 3 10 -0- -------------------------------------------- -------------------------------------------- TOTAL 8 19 3 --------------------------------------------
(1) These four wells were in the Blue Ridge property, which we sold effective July 1, 2005. (2) We have a 33-1/3% working interest after payout in this well, the REP Pintail Flats. Our working interest reduces to 13.33% at project payout as described in ITEM 2 - SW Garwood, Colorado County, TX). NET PRODUCTION, UNIT PRICES AND COSTS The following table presents certain information with respect to oil, gas and condensate production attributable to interests in all of our fields. Including the average sales prices received and average production costs during the fiscal periods ended December 31, 2005 and December 31, 2004 7
---------------------------------------------------------- 2005 2004 ---------------------------------------------------------- Average sales price per barrel of oil $50.34 $36.06 equivalent ---------------------------------------------------------- Lifting costs per barrel of oil equivalent $11.19 $ 5.90 ----------------------------------------------------------
DESCRIPTION OF OFFICE PROPERTIES We currently have two office locations, one in Houston and one in Dallas, Texas. The addresses are as follows: 675 Bering Drive, Suite 200 4925 Greenville Avenue, Suite 670 Houston, TX 77057 Dallas, Texas 75206 On August 1, 2005, we leased our Dallas location, comprised of approximately 2,100 square feet of office space which is held under a sixty-four month lease at a rate of approximately $2,800 per month (with payments which began December 2005). Effective July 15, 2005, our principle executive offices moved to approximately 3,700 square feet of office space at 675 Bering Drive, Houston, Texas. We hold this space under a five-year lease agreement at a lease rate of approximately $5,000 per month. We believe these properties are adequate for our corporate office needs. ITEM 3. LEGAL PROCEEDINGS We are currently not a party to any material pending legal proceeding. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND SMALL BUSINESS ISSUER PURCHASES OF EQUITY SECURITIES Our common stock is quoted on the OTCBB under the symbol "PTSG" The following table sets forth the quarterly high and low of sales prices per share for the common stock for the last two fiscal years. Our fiscal year ended December 31, 2005. COMMON STOCK PRICE RANGE
--------------------------------------------------- QUARTER HIGH LOW --------------------------------------------------- 1st Quarter 2004 (1) $20.15 $4.42 --------------------------------------------------- 2nd Quarter 2004 (1) $ 6.57 $4.16 --------------------------------------------------- 3rd Quarter 2004 (1) $ 5.79 $2.21 --------------------------------------------------- 4th Quarter 2004 (1) $ 3.90 $1.95 --------------------------------------------------- 1st Quarter 2005 $ 2.60 $1.18 --------------------------------------------------- 2nd Quarter 2005 $ 2.20 $1.13 --------------------------------------------------- 3rd Quarter 2005 $ 1.83 $0.90 --------------------------------------------------- 4th Quarter 2005 $ 1.49 $0.72 ---------------------------------------------------
8 (1) All figures shown for fiscal quarters prior to first quarter 2005 are stated using post-reverse split (6.5-to-1) bid price equivalents. On March 15, 2006, the last sales price for the common stock as reported on the OTCBB was $1.53. On March 15, 2006, there were approximately 2,500 stockholders of record of the common stock. TRANSFER AGENT AND REGISTRAR The transfer agent and registrar for our common stock is: Corporate Stock Transfer 3200 Cherry Creek South Drive Suite 430 Denver, CO 80209 DENVER, CO 80209 DIVIDEND POLICY We have not paid, and do not currently intend to pay cash dividends on our common stock in the foreseeable future. Our current policy is to retain all earnings, if any, to provide funds for operation and expansion of our business. The declaration of dividends, if any, will be subject to the discretion of the Board of Directors, which may consider such factors as our results of operation, financial condition, capital needs and acquisition strategy, among others. EQUITY COMPENSATION PLAN INFORMATION The following table sets forth all equity compensation plans as of December 31, 2005:
------------------------------------------------------------------------------------------------ NUMBER OF SECURITIES REMAINING AVAILABLE FOR FUTURE ISSUANCE UNDER NUMBER OF SECURITIES TO WEIGHTED-AVERAGE EQUITY COMPENSATION BE ISSUED UPON EXERCISE EXERCISE PRICE OF PLANS (EXCLUDING OF OUTSTANDING OPTIONS, OUTSTANDING OPTIONS, SECURITIES REFLECTED IN WARRANTS AND RIGHTS WARRANTS AND RIGHTS COLUMN (A)) PLAN CATEGORY (A) (B) (C) ------------------------------------------------------------------------------------------------ Equity compensation N/A N/A N/A plans approved by security holders ------------------------------------------------------------------------------------------------ Equity compensation 8,495,045 $3.57 N/A plans not approved by security holders ------------------------------------------------------------------------------------------------ TOTAL 8,495,045 $3.57 N/A ------------------------------------------------------------------------------------------------
RECENT SALES OF UNREGISTERED SECURITIES Set forth below is information regarding the issuance and sales of our securities without registration during the last three years. Except as otherwise noted, all sales below were made in reliance on Section 4(2) of the Securities Act of 1933, as amended. No advertising or general solicitation was employed in offering the securities. In each instance, the offerings and sales were made to a limited number of persons, who were either (i) accredited investors, (ii) business associates of the Company (iii) employees of the Company, or (iv) executive officers or directors of the Company. In addition, the transfer of such securities were restricted by the Company in accordance with the requirements of the Act. Furthermore, all of the above-referenced persons were provided with access to our filings with the Securities and Exchange Commission. 9 1. In February 2006, we completed a private placement of 1,928,573 shares of common stock with nine investors for total gross proceeds of $2,700,000 and net proceeds of $2,560,000. We also issued 964,286 common stock warrants related to the private placement at an exercise price of $2.00 and a term of three years. Arabella Securities served as placement agent for the sale of these shares which were placed exclusively to a group of accredited investors. The placement agent received a cash commission representing 5% of the gross proceeds and 96,429 warrants representing 5% of the common shares issued at an exercise price of $2.00 and a term of three years. 2. In November 2005, we entered into an asset purchase agreement with Quinduno Energy, LLC for the purchase of a 100% working interest in 1,755 acres in Robert County, Texas. Pursuant to the November agreement we were required to pay on November 15, 2005, $500,000 in cash and 500,000 shares of our restricted common stock. Pursuant to the same asset purchase agreement with Quinduno Energy listed above we issued on February 27, 2006 $250,000 in cash and 500,000 shares of our restricted common stock. 3. In September 2005, we amended and restated our revolving credit agreement as discussed herein. Pursuant to this agreement we issued 100,000 of our common stock warrants at an exercise price of $2.00. These warrants were issued to the lender for financing costs associated with the revolving credit agreement. These warrants expire in November 2007. 4. In April 2005, we completed the private placement of 8,153,846 shares of common stock with twenty-one investors for total gross proceeds of $10,600,000 and net proceeds of $9,900,000. Sterne, Agee & Leach served as placement agent for the sale of these shares which were placed exclusively to a group of accredited investors primarily consisting of U.S.-based institutional investment funds. The placement agent received a commission of 6% of the gross proceeds. 5. In January 2005, we issued 512,821 shares of our common stock to one accredited investor for $1.95 per share, or $1,000,000. On January 24, 2005, we agreed to sell 512,821 shares of our common stock to two accredited investors who are affiliates of the original accredited investor at a price of $1.95 per share for total proceeds of $1,000,000. We issued 412,821 of these shares in late January 2005 and 100,000 of these shares in April 2005. Subsequently, in April 2005, we issued an aggregate of 512,800 additional shares to these three investors to effect a price adjustment from $1.95 to $1.30 as required under the provisions of the share purchase agreements. No underwriter or other person participated in and no commissions were paid on these transactions. 6. In December 2004, immediately prior to our redomicile and merger, Petrosearch Texas exchanged one new Petrosearch Texas share in exchange for 6.5 existing shares of Petrosearch Texas pursuant to a reverse split approved by the majority of its shareholders. Simultaneously, and solely for the purpose of redomicile, Petrosearch Texas merged into Petrosearch Nevada, a company with identical articles of incorporation, bylaws, capitalization and board of directors members, resulting in each post reverse share of Petrosearch Texas receiving one share of Petrosearch Nevada. We relied upon Section 3(a)9 of the Act for this exchange to approximately 192 existing shareholders of Petrosearch Texas. No underwriter participated in, nor did we pay any commissions or fees to any underwriter or other person in connection with any of these transactions. Additionally, all of the existing Petrosearch Texas warrants were exchanged for our warrants on the same terms, giving effect to the reverse split, pursuant to Section 3(a)9 of the Act for this exchange. As part of this exchange, we issued 3,696,154 warrants to approximately 44 individuals who had previously been issued warrants as compensation to directors, executive officers, and subsidiary presidents, and as consideration to members of the Advisory Committee for their services. No underwriter or other person participated in, nor did we pay any commissions or fees to any underwriter or other person in connection with any of these transactions. 7. In October and December 2003, 2003A Bonds were issued with a total principal amount of $200,000 with $150,000 issued in October and $50,000 issued in December, which were due in October and December 2006, respectively. These bonds have subsequently been paid. The bonds were issued to four accredited investors in a private transaction in reliance on Section 4(2) of the Act. No underwriter participated in, nor 10 did we pay any commissions or fees to any underwriter in connection with any of these transactions. ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS In 2005, as a new management team, our main focus was on improving the quality of our portfolio of oil and gas assets. We increased our proved PV-10 reserves from $13.7 million at December 31, 2004 to $46.5 million as of December 31, 2005. By high grading our portfolio we have acquired assets that have multiple year growth potential that allows us to more efficiently control the amount and timing of our capital expenditures. In 2005 we have also disposed of assets that did not meet our risk/reward parameters. Our current portfolio is extremely diversified relative to oil versus gas, big capital needs versus smaller capital needs, and high risk exploration versus lower risk/reward development. This gives us the ability to make sound decisions as to where our capital should most appropriately be deployed. We believe we were successful in 2005 at creating an extremely high-graded portfolio of oil and gas assets and a sound infrastructure, which enables us in 2006 to focus on the development of our high quality properties which should have a significant impact on our production, revenues and cash flows. RESULTS OF OPERATIONS The following discussion should be read in conjunction with our audited consolidated financial statements and the related notes to the financial statements included in this Form 10-KSB. The factors that most significantly affect our results of operations are: (i) the sale prices of crude oil and natural gas; (ii) the amount of production sales; and (iii) the amount of lease operating expenses. Sales of production and level of borrowings are significantly impacted by our ability to maintain or increase production and reserves from existing oil and gas properties through exploration and development activities. FOR THE YEAR ENDED DECEMBER 31, 2005 COMPARED TO THE YEAR ENDED DECEMBER 31, 2004 REVENUES Consolidated oil and gas production revenues for the year ended December 31, 2005 were $1,701,043 versus $4,718,313 for the year ended December 31, 2004. The decrease in revenues from 2004 to 2005 is a result of several factors including the sale of the Blue Ridge Field in Fort Bend County, Texas in July 2005. The Blue Ridge field accounted for 32,500 barrels of oil in 2004 versus only 12,600 barrels in 2005, due primarily to the sale of the asset in mid 2005. Secondly, the decrease in production in 2005 was due to the continued pressure depletion and eventual temporary shut down in October 2005 of our Gruman 18-1 well in Stark County North Dakota. In mid 2004 the well started to experience significant pressure depletion which continued through 2005. The Gruman 18-1 well produced 98,600 boe in 2004 (86% of that production in the first 6 months of 2004), versus total production of 19,800 boe in 2005. We have attempted to mitigate the effects of the pressure depletion with a submersible pump, however this pump was down from October 27, 2005 through March 9, 2006. We have begun the drilling of an increased density well on March 27, 2006 in an attempt to increase the production of the well significantly. Our future revenue will be principally dependent upon the success of the development of our current quality prospects and projects as well as the market price for crude oil and natural gas. We plan to focus capital resources on the Barnett Shale resource project (pending resolution of all matters associated with Program Agreement and Extension Agreement described herein), the development of our proved properties in Texas, Louisiana and North Dakota, as well as our exploration projects in Texas and Mississippi. We have not previously utilized any hedging instruments and have no plans to do so in the foreseeable future. 11 LEASE OPERATING AND PRODUCTION TAX EXPENSE Lease operating and production tax expense for the years ended December 31, 2005, and December 31, 2004, were $581,313 and $773,723, respectively. These expenses, which are primarily outsourced to third party vendors and contractors relate to the day to day costs that are incurred to operate and maintain our wells and related production equipment. The decrease is partly related to the decrease in production from 2004 to 2005 as explained above. However; although these expenses have decreased from 2004 to 2005, they have not decreased on the same proportion as production revenue. This relates to the fact that even though production taxes reduce proportionately to production revenue, lease operating expenses will not necessarily reduce proportionately; lease operating expenses continue to be incurred even when production is declining as in the case of our North Dakota well. DEPLETION, DEPRECIATION AND AMORTIZATION Costs for depletion, depreciation and amortization for the years ended December 31, 2005, and December 31, 2004, were $563,252 and $2,219,998, respectively. Depletion expense per barrel of oil equivalent was $15.24 and $16.83 for the years ended December 31, 2005 and 2004 respectively. Although there was an increase in properties subject to amortization of depletion of $6,359,073 ($11,849,520 and $5,490,447 in December 31, 2005 and 2004 respectively), that increase was offset by two factors that would cause a decrease in total depletion: 1) the significant decrease in production from 2004 to 2005 (35,676 boe and 131,194 boe for the years ending December 31, 2005 and 2004, respectively), and 2) the increase in proved reserves of 2.1 million boe from 2004 to 2005. Depletion is calculated using the percentage of units of production over the total proved reserves. Therefore, being that our total units produced decreased and our total proved reserves increased, our depletion percentage of proved properties subject to amortization of depletion decreased. GENERAL AND ADMINISTRATIVE EXPENSES General and administrative expenses for the years ended December 31, 2005, and December 31, 2004, were $3,268,088 and $3,239,184 respectively. Although the general and administrative expenses for these periods were comparable, there were differences in the actual expenses that were incurred. In 2004 the Company did not have any employees and all the personnel costs were treated as consulting fees. In January 2005 all of the officers and other personnel became employees. Also in 2005 we reduced significant areas of the general and administrative expenses while also increasing the quality and effectiveness of the resources that we spent our funds on. These decreases are not directly apparent to the total general and administrative expenses due to inclusion of the write-offs in 2005 of bad debts and prepaid credits related to prior period operations. In May 2005 we increased our technical expertise by hiring 5 technical employees, including our COO, Manager of Operations, Manager of Geology, Manager of Land and Manager of Engineering. We believe we achieved a significant accomplishment by increasing our technical expertise and writing off bad debts and prepaid credits with our general and administrative expenses remaining constant from 2004 to 2005. Significant details of general and administrative expenses listed below:
-------------------------------------------------------------- 2004 2005 DIFFERENCE -------------------------------------------------------------- -------------------------------------------------------------- Third Party Consulting $2,051,844 $ 590,581 $(1,461,263) -------------------------------------------------------------- Employee Costs -0- 1,413,398 1,413,398 -------------------------------------------------------------- Travel and Entertainment 213,444 138,227 (75,217) -------------------------------------------------------------- Accounting and Legal 491,154 416,114 (75,040) -------------------------------------------------------------- Bad debts and prepaid -0- 205,443 205,443 credits -------------------------------------------------------------- --------------------------------------------------------------
12 NET LOSS FROM OPERATIONS We generated a net operating loss of $2,711,610 or $0.11 per share, for the year ended December 31, 2005, compared to a net loss of $1,514,592 or $0.09 per share, for the year ended December 31, 2004. The $1,197,018 variance is related mainly to the decrease in production from our North Dakota well as explained above and due to the sale of our Blue Ridge Field asset. There was no profit and loss effect of the sale of the Blue Ridge Field asset because under full cost accounting no gain or loss is recorded on the sale of an asset. As explained above, our main focus during 2005 was to improve the quality of our portfolio of our oil and gas assets and dispose of assets that did not meet our risk/reward parameters. Our current portfolio is extremely diversified. We believe we were successful in 2005 in creating an extremely high-graded portfolio of oil and gas assets and a sound infrastructure, which will enable us to focus on the development of our high quality properties in 2006 which we anticipate, will have a positive impact on our production, revenues and cash flows. LIQUIDITY AND CAPITAL RESOURCES Since inception, we have primarily financed our operating and investing cash flow needs through private offerings of equity securities, sales of crude oil and natural gas, and the use of debt instruments such as corporate bonds and revolving credit facilities. The proceeds from, and the utilization of, all these methods have been and Management believes will continue to be, sufficient to keep the operations funded and the business plan moving forward. We plan to continue to utilize these methods to access capital in order to implement our business plan, which we believe will be an effective vehicle to carry out our business plan. FINANCIAL ADVISORS On December 21, 2005 we engaged the Corporate Finance Division of Macquarie Securities (USA) Inc. as an exclusive financial advisor. Macquarie's services will be utilized in connection with debt or equity transactions the Company may contemplate. PRIVATE PLACEMENTS In April 2005, we completed sales of $12.6 million of our common stock in private offerings. We received net proceeds of approximately $11.9 million which were to be used for general corporate purposes, including the drilling of projects in our prospect inventory. In February 2006, we completed sales of $2.7 million of our common stock in a private offering. We received net proceeds of approximately $2.56 million which are to be used for general corporate purposes, including the drilling of projects in our prospect inventory. REVOLVING CREDIT AGREEMENT In September 2005 we amended and restated our revolving credit agreement to $10 million which allowed Fortuna Energy, L.P. to participate in the ownership and development of an eight prospect package in our inventory. The significant provisions of the Credit Facility are as follows: The Credit Facility matures on the 30-month anniversary of the initial advance (which occurred on September 29, 2005) and may be prepaid at any time. Repayment of each tranche borrowed shall be interest only for six months and shall then amortize on a 30 month basis with all then outstanding tranches due and payable April 1, 2008. The last date for advances shall be October 15, 2007. The proceeds may be utilized for past, present or future acquisitions of oil and gas leases, including associated costs of technical review and analysis, drilling, reworking, production, transportation, 13 marketing and plugging. The proceeds may also be used to fund all lender charges and fees, including legal fees of Fortuna's counsel. Subject to the draw limitations and funds availability provisions described below, we are required to utilize the funds from the Credit Facility to fund lease acquisitions by our Beacon Petrosearch, L.L.C. and Anadarko Petrosearch, L.L.C. subsidiaries before resorting to funds which may be available internally or from third parties (other than drilling co-venturers). The collateral for the Credit Facility includes a first and prior lien on the oil and gas leases acquired with Fortuna's funds, as well as the equipment on any well drilled with Fortuna's funds. The collateral also includes all existing and future lease interests in the eight project package listed above and the State of Oklahoma, and all existing lease interests in North Dakota (regardless of whether Fortuna's funds are utilized in North Dakota) as well as our membership interest (subject to the possible payment to certain independent professionals of either an ownership interest or a share of the net revenues after-payout as discussed above in the section entitled "Business Model") in Beacon Petrosearch, L.L.C. and Anadarko Petrosearch, L.L.C. Under the Credit Facility, Fortuna will receive a 2% overriding royalty interest of Petroseach's proportionate net revenue interest in the leases acquired or drilled using Fortuna's funds, as well as a like overriding royalty in current leases held in Beacon Petrosearch, L.L.C. and certain leases held in Anadarko Petrosearch, L.L.C. in Oklahoma. Under the terms of the Credit Facility, principal is to be repaid in 24 monthly installments equal to 1/30th of the principal commencing six months after the initial advance, with the balance being paid at the maturity of the facility. Interest shall be repaid under the Credit Facility at Wall Street Journal prime +3% per annum payable monthly in arrears. As of March 15, 2006, the principal balance outstanding pursuant to the Credit Facility was $3,525,000. It is Management's intent to utilize the Credit Facility to acquire new leases and develop existing leases with these funds, securing the debt with the collateral required under the terms of the Credit Facility. SALE OF PROPERTY In June 2005 we entered into an option agreement to sell all of the assets of our TK Petrosearch subsidiary for a cash purchase price of approximately $2,140,000. The option agreement was exercised on August 3, 2005 with the effective date of the transfer being July 1, 2005. The assets sold accounted for $1,370,110 of our PV-10 proved reserves as of December 31, 2004, or approximately 10% of our total proved reserve value at that date. PROJECT FINANCING AND RIGHT OF FIRST REFUSAL On January 11, 2006, we entered into an Agreement with Rock Energy Partners ("Rock") covering the geographic areas of current operations in Jefferson County, Mississippi and Colorado County, Texas affecting the Company and Rock, including agreements and stipulations regarding future operations in those geographic areas, the terms under which future exploration and development participation opportunities shall be offered by the Company to Rock, and agreed procedures for conducting internal audits and accounting reconciliations. As part of the transaction with Rock, the parties have executed an Amended Right of First Refusal Agreement (the "Amended ROFR") which replaces the previous Right of First Refusal Agreement between the Company and Rock which was entered in March 2004 (the "ROFR"). The Amended ROFR has more limited applicability to our various projects than the ROFR. While the original agreement required all of our prospects to be presented to Rock for consideration by Rock, the Amended ROFR does not require that all our prospects be offered to Rock for participation. The Amended ROFR also does not require that we offer to Rock prospects in any specified area, although the parties have separately stipulated to certain specified areas of mutual interest in the Mississippi and Colorado County areas 14 based upon historical operations in those areas. The Amended ROFR permits us to decide which projects will be offered to Rock, so long as the projects actually presented are projects in which the Company owns or intends to retain a minimum of ten percent (10%) of the project interest available to the Company. Under the Amended ROFR, Rock's percentage participation is limited to the range between ten percent (10%) minimum participation and forty percent (40%) maximum participation. The minimum and maximum participation limits are proportional to the interest available to the Company. The Amended ROFR also calls for a minimum funding commitment required from Rock equal to $3,000,000 per year for new projects, without the right to carry over to any subsequent year as credit expenditures above the minimum required commitment for that year. Rock is also obligated to spend up to $8,800,000 for the drilling of one new well and one well re-entry to test the deep Wilcox at the SW Garwood prospect during 2006. This obligation of Rock's will cover 100% of the capital requirements for the two projects. The Amended ROFR provides that the Company to retain in each prospect which is accepted by Rock a twenty-five percent (25%) reversionary interest in each interest assigned to Rock, with the reversion to take effect upon "payout" or recoupment of Rock's development costs net to that interest. DRILLING PARTNERSHIPS We continue to strive to develop relationships with institutional or high net worth individuals to participate in our prospects. Management believes this will reduce our capital risk and increase the diversity of the projects in which we use our own capital. We intend to establish these drilling partnership relationships with terms that are standard in the oil and gas industry. FORWARD LOOKING STATEMENT AND INFORMATION This document contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as "believes," "expects," "anticipates," "intends," "plans," "estimates," "should," "likely" or similar expressions, indicates a forward-looking statement. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future results may differ materially from those expressed in the forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Stockholders are cautioned not to put undue reliance on any forward-looking statements, which speak only to the date made. For those statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events, or performance and underlying assumptions and other statements, which are other than statements of historical facts. These statements are subject to uncertainties and risks including, but not limited to, product and service demands and acceptance, changes in technology, economic conditions, the impact of competition and pricing, and government regulation and approvals. Petrosearch cautions that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from those Petrosearch expects include changes in natural gas and oil prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business. Our expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable basis, including without limitation, our examination of historical operating trends, data contained in our 15 records and other data available from third parties. There can be no assurance, however, that our expectations, beliefs or projections will result, be achieved, or be accomplished. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no duty to update these forward-looking statements. CAUTIONARY NOTE TO U.S. INVESTORS THE UNITED STATES SECURITIES AND EXCHANGE COMMISSION PERMITS OIL AND GAS COMPANIES, IN THEIR FILINGS WITH THE SEC, TO DISCLOSE ONLY PROVED RESERVES THAT A COMPANY HAS DEMONSTRATED BY ACTUAL PRODUCTION OR CONCLUSIVE FORMATION TESTS TO BE ECONOMICALLY AND LEGALLY PRODUCIBLE UNDER EXISTING ECONOMIC AND OPERATING CONDITIONS. WE USE CERTAIN TERMS HEREIN, SUCH AS "PROBABLE", "POSSIBLE", "RECOVERABLE", AND "RISKED," AMONG OTHERS, THAT THE SEC'S GUIDELINES STRICTLY PROHIBIT US FROM INCLUDING IN FILINGS WITH THE SEC. READERS ARE URGED TO CAREFULLY REVIEW AND CONSIDER THE VARIOUS DISCLOSURES MADE BY US WHICH ATTEMPT TO ADVISE INTERESTED PARTIES OF THE ADDITIONAL FACTORS WHICH MAY AFFECT OUR BUSINESS. For a discussion of some additional factors that may cause actual results to differ materially from those suggested by the forward-looking statements, please read carefully the information under "Risk Factors" section below. The identification in this document of factors that may affect future performance and the accuracy of forward-looking statements is meant to be illustrative and by no means exhaustive. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty. We operate in a very competitive and rapidly changing environment. New risks emerge from time to time and it is not possible for our management to predict all risks, nor can we assess the impact of all risks on our business or the extent to which any risk, or combination of risks, may cause actual results to differ from those contained in any forward-looking statements. All forward-looking statements included in this Form 10-KSB are based on information available to us on the date of the Form 10-KSB. Except to the extent required by applicable laws or rules, we undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this Form 10-KSB. RISK FACTORS An investment in our Common Stock involves a high degree of risk. You should carefully consider the risks described below before deciding to purchase shares of our Common Stock. If any of the events, contingencies, circumstances or conditions described in the risks below actually occur, our business, financial condition or results of operations could be seriously harmed. The trading price of our Common Stock could, in turn, decline and you could lose all or part of your investment. RISKS RELATED TO THE COMPANY OUR LIMITED HISTORY MAKES AN EVALUATION OF US AND OUR FUTURE EXTREMELY DIFFICULT, AND PROFITS ARE NOT ASSURED. We have a limited operating history, having begun commercial drilling operations in August 2003. There can be no assurance that we will be profitable in the future or that the shareholders' investments in us will be returned to them in full, or at all, over time. In view of our limited history in the oil and gas exploration business, an investor must consider our business and prospects in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of development. There can be no assurance that we will be successful in undertaking any or all of the activities required for successful commercial drilling operations. Our failure to undertake successfully such activities could materially and adversely affect our 16 business, prospects, financial condition and results of operations. In addition, there can be no assurance that our exploration and production activities will produce oil and gas in commercially viable quantities, if any at all. There can be no assurance that sales of our oil and gas production will ever generate significant revenues, that we will ever generate additional positive cash flow from our operations or that we will be able to achieve or sustain profitability in any future period. WE HAVE EXPERIENCED RECENT SUBSTANTIAL OPERATING LOSSES AND MAY INCUR ADDITIONAL OPERATING LOSSES IN THE FUTURE. During the twelve month period ended December 31, 2005 we incurred a net loss of $2,901,031 In the event we are unable to increase our gross margins, reduce our costs and/or generate sufficient additional revenues to offset our increased costs, we may continue to sustain losses and our business plan and financial condition will be materially and adversely affected. THE TRADING PRICE OF OUR COMMON STOCK ENTAILS ADDITIONAL REGULATORY REQUIREMENTS, WHICH MAY NEGATIVELY AFFECT SUCH TRADING PRICE. The trading price of our common stock is below $5.00 per share. As a result of this price level, trading in our common stock would be subject to the requirements of certain rules promulgated under the Securities Exchange Act of 1934, as amended. These rules require additional disclosure by broker-dealers in connection with any trades generally involving any non-NASDAQ equity security that has a market price of less than $5.00 per share, subject to certain exceptions. Such rules require the delivery, before any penny stock transaction, of a disclosure schedule explaining the penny stock market and the risks associated therewith, and impose various sales practice requirements on broker-dealers who sell penny stocks to persons other than established customers and accredited investors (generally institutions). For these types of transactions, the broker-dealer must determine the suitability of the penny stock for the purchaser and receive the purchaser's written consent to the transaction before sale. The additional burdens imposed upon broker-dealers by such requirements may discourage broker-dealers from effecting transactions in our common stock. As a consequence, the market liquidity of our common stock could be severely affected or limited by these regulatory requirements. IN THE FUTURE, WE WILL INCUR SIGNIFICANT INCREASED COSTS AS A RESULT OF OPERATING AS A PUBLIC COMPANY, AND OUR MANAGEMENT WILL BE REQUIRED TO DEVOTE SUBSTANTIAL TIME TO NEW COMPLIANCE INITIATIVES. Due to the effectiveness of our registration statement on September 8, 2005, we have begun incurring significant legal, accounting and other expenses as a fully-reporting public company. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules subsequently implemented by the SEC, have imposed various new requirements on public companies, including requiring changes in corporate governance practices. Our management and other personnel will need to devote a substantial amount of time to these new compliance initiatives. Moreover, these rules and regulations will increase our legal and financial compliance costs and will make some activities more time-consuming and costly. For example, we expect these rules and regulations to make it more difficult and more expensive for us to obtain director and officer liability insurance, and we may be required to incur substantial costs to maintain the same or similar coverage. In addition, the Sarbanes-Oxley Act requires, among other things, that we maintain effective internal controls for financial reporting and disclosure controls and procedures. In particular, commencing in fiscal 2007, we must perform system and process evaluation and testing of our internal controls over financial reporting to allow management and our independent registered public accounting firm to report on the effectiveness of our internal controls over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act. Our testing, or the subsequent testing by our independent registered public accounting firm, may reveal deficiencies in our internal controls over financial reporting that are deemed to be material weaknesses. Our compliance with Section 404 will require that we incur substantial accounting expense and expend significant management efforts. We currently do not have an internal audit group, and we will need to hire additional accounting and financial staff with appropriate public company experience and technical accounting knowledge. Moreover, if we are not able to comply with the requirements of Section 404 in a timely manner, or if we or our 17 independent registered public accounting firm identifies deficiencies in our internal controls over financial reporting that are deemed to be material weaknesses, the market price of our stock could decline, and we could be subject to sanctions or investigations by the SEC or other regulatory authorities, which would require additional financial and management resources. OUR MANAGEMENT CONTROLS A SIGNIFICANT PERCENTAGE OF OUR CURRENT OUTSTANDING COMMON STOCK AND THEIR INTERESTS MAY CONFLICT WITH THOSE OF OUR SHAREHOLDERS. As of March 15, 2006, our Directors and executive officers and their respective affiliates collectively and beneficially owned approximately 17% of our outstanding common stock, including all warrants exercisable within 60 days. This concentration of voting control gives our Directors and executive officers and their respective affiliates substantial influence over any matters which require a shareholder vote, including, without limitation, the election of Directors, even if their interests may conflict with those of other shareholders. It could also have the effect of delaying or preventing a change in control of or otherwise discouraging a potential acquirer from attempting to obtain control of us. This could have a material adverse effect on the market price of our common stock or prevent our shareholders from realizing a premium over the then prevailing market prices for their shares of common stock. CUMULATIVE VOTING IS NOT AVAILABLE TO STOCKHOLDERS. Cumulative voting in the election of Directors is expressly denied in our Articles of Incorporation. Accordingly, the holder or holders of a majority of the outstanding shares of our common stock may elect all of our Directors. Management's large percentage ownership of our outstanding common stock helps enable them to maintain their positions as such and thus control of our business and affairs. WE ARE DEPENDENT ON KEY PERSONNEL. We depend to a large extent on the services of certain key management personnel, including our executive officers and other key consultants, the loss of any of which could have a material adverse effect on our operations. Specifically, we rely on Mr. Richard Dole, Chairman, President and CEO, to maintain the strategic direction of the Company. We also rely on Mr. Wayne Beninger, Chief Operating Officer, to oversee the technical evaluation of projects as well as operations of the Company. Although Messrs. Dole and Beninger currently serve under employment agreements, there is no assurance that they will continue to be employed by us. We do not maintain, nor do we plan to maintain, key-man life insurance with respect to any of our officers or directors. WE ARE SUBJECT TO POTENTIAL LIABILITY FROM OPERATIONS. We are subject to potential liability from our operations, such as injuries to employees or third parties, which are inherent in the management of oil and gas programs. While we intend to obtain and maintain appropriate insurance coverage for these risks, there can be no assurance that our operations will not expose us to liabilities exceeding such insurance coverage or to liabilities not covered by insurance. OUR APPROACH TO TITLE ASSURANCE COULD MATERIALLY ADVERSELY AFFECT OUR BUSINESS AND OPERATIONS. We intend to purchase working and revenue interests in oil and gas leasehold interests from third parties or directly from the mineral fee owners as the inventory upon which we will perform our exploration activities. The existence of a material title deficiency can render a lease worthless and can result in a large expense to us. Title insurance covering the mineral leaseholds is not generally available and in all instances, we forego the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease until the drilling block is assembled and ready to be drilled. We rely upon the judgment of oil and gas lease brokers or experienced landmen who perform the field work in examining records in the appropriate governmental office before attempting to acquire or place under lease a specific mineral interest. This is customary practice in the oil and gas industry. Our operating agreements require us to obtain a 18 preliminary title review of the spacing unit within which the proposed oil and gas well is to be drilled prior to drilling in order to ensure there are no obvious deficiencies in title to the well. As a result of such examinations, certain curative work may have to be performed to correct deficiencies in the marketability of the title, and such curative work entails expense. The work might include obtaining affidavits of heirship or causing an estate to be administered. Occasionally, the examination made by the title lawyers reveals that the oil and gas lease or leases are worthless, having been purchased in error from a person who is not the owner of the mineral interest desired. In such instances, the amount paid for such oil and gas lease or leases is generally lost. In general, the loss of a lease does not create a material adverse effect. However, if the defective lease covers acreage which is critical to the success of a particular project, the loss could have a material adverse effect by making the target area potentially undrillable. Our customary practice is to obtain a drill site title opinion prior to drilling a well. WE MAY EXPERIENCE POTENTIAL FLUCTUATIONS IN RESULTS OF OPERATIONS. Our future revenues may be affected by a variety of factors, many of which are outside our control, including (a) the success of project results; (b) swings in availability of drilling services needed to implement projects and the pricing of such services; (c) a volatile oil and gas pricing market which may make certain projects that we undertake uneconomic; (d) the ability to attract new independent professionals with prospects in a timely and effective manner; and (e) the amount and timing of operating costs and capital expenditures relating to conducting our business operations and infrastructure. As a result of our limited operating history and the emerging nature of our business plan, it is difficult to forecast revenues or earnings accurately, which may fluctuate significantly from quarter to quarter. WE MAY BE UNABLE TO ATTRACT AND RETAIN INDEPENDENT PROFESSIONALS. Our future success depends in large part on our ability to identify and acquire the talents of highly qualified independent professionals and their specific projects. If we are unable to engage a sufficient number of such professionals, we may not be able to expand our business. We have an innovative expansion concept within a relatively experienced industry. This concept is so non-typical that it may take longer to build its acceptance than we currently anticipate. This could delay implementation of projects and subsequent cash flows. Our concept may prove to be inadequate to attract quality independent oil and gas professionals. Furthermore, our current subsidiaries will bear a great deal of scrutiny by independent professionals before such professionals are willing to contribute their projects to our subsidiaries. We have not conducted, or engaged any other person or entity to conduct, any formal marketing surveys regarding the potential for our proposed business plan. WE RELY UPON AN EXISTING CREDIT FACILITY Our sole exiting credit facility has been provided by Fortuna Energy, L.P., a private entity. Since a private entity is not governed by typical banking regulations, the negotiated terms of the Fortuna Credit Facility are unique and could, in given circumstances, be less favorable to us than traditional financing. Certain of these unique terms are as follows: On September 29, 2005, we renewed and extended our existing revolving credit facility with Fortuna Energy, LP ("Fortuna") hereinafter referred to as the "Credit Facility". The significant revised terms of the Credit Facility are described below. The principal available under the revolving borrowing base is $10,000,000, which will bear interest at Wall Street Journal Prime plus three percent (3%) and mature on April 1, 2008. Principal cannot be drawn under the Credit Facility after October 1, 2007. Each advance of principal under the Credit Facility is treated as a separate loan and is repayable in six (6) interest-only installments, followed by up to twenty four (24) principal and interest installments based upon a 30-month amortization. Additionally, Fortuna shall charge quarter-annually a standby fee equal to one quarter of one percent (0.25%) of the funds available to be drawn. but not requested by us, unless the limitations imposed upon advances under the Credit Facility described below are then applicable. Prepayment is permitted in amounts of $100,000.00 each or more. 19 The proceeds of each advance may be utilized for past, present or future acquisitions of oil and gas leases, including associated costs of technical review and analysis, drilling, reworking, production, transportation, marketing and plugging. The proceeds may also be used to fund all lender charges and fees, including legal fees of Fortuna's counsel. The funds are expected to be budgeted for and utilized on eight (8) separate target projects in Texas, Louisiana and Mississippi. At the time of these amendments to the Credit Facility, Fortuna's collateral included a first and prior lien on our existing Oklahoma oil and gas leases, our interest in the Gruman 18-1 well in North Dakota and our limited liability company membership interests in each of Anadarko Petrosearch, LLC and TK Petrosearch, LLC. Immediately prior to these amendments, we sold our oil and gas leases in Fort Bend County, Texas and these were removed from the Credit Facility. The remaining existing collateral remains unaffected by the amendments. As amended, the collateral for the Credit Facility further includes a first and prior lien on new oil and gas leases acquired with Fortuna's funds, as well as the equipment on any well drilled with Fortuna's funds. The Credit Facility will be further secured by a pledge of our limited liability company membership interests in any existing or newly created subsidiary which is utilized to hold oil and gas leases acquired with Fortuna's funds. Advances under the Credit Facility shall be made available only if at the time of our request (1) our Proved Developed Reserves at all times equal or exceed twenty-five percent (25%) of the outstanding principal and interest indebtedness and, (2) only if the principal balance under the note following the requested advance is less than the sum of (i) actual costs of the oil and gas leases funded through the date of the requested draw with Fortuna funds, and (ii) the sum of 75% of our Proved Developed Reserves and 50% of our Proved Undeveloped Reserves from all properties as reflected in the most recent reserve report prepared by an independent petroleum engineer with qualifications to provide such a report compliant with SEC standards. The terms Proved Developed Reserves and Proved Undeveloped Reserves are defined in Rule 4-10, Regulation S-X. The Credit Facility further requires that we update our reserve reports every six (6) months or earlier should the hypothetical price of hydrocarbons used in preparation of the most recent reserve report decline by 15% or more. If there is a deficiency in these minimum reserve requirements, then we must pledge additional collateral or pay down the loan. Correspondingly, we may obtain a partial release of an item of collateral upon request if these minimum reserve requirements are satisfied after the release. Under the Credit Facility, Fortuna will receive an overriding royalty equal to 2% of our net revenue interest in each oil and gas lease acquired or drilled with the funds derived from the Credit Facility. Fortuna also received 100,000 warrants to purchase shares of our common stock at an exercise price of $2.00 per share As of March 15, 2006 the outstanding principal balance of the facility was $3,525,000. WE PARTICIPATE IN OIL AND GAS LEASES WITH THIRD PARTIES. We may own less than 100% of the working interest in certain leases acquired by us, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for the joint activity obligations of the other working interest owners such as nonpayment of costs and liabilities arising from the actions of the working interest owners. In the event other working interest owners do not pay their share of such costs, we would likely have to pay those costs. In such situations, if we were unable to pay those costs, we could become insolvent. WE MAY ISSUE ADDITIONAL SHARES OF COMMON STOCK IN THE FUTURE, WHICH COULD CAUSE DILUTION TO ALL SHAREHOLDERS. We may seek to raise additional equity capital in the future. Any issuance of additional shares of our common stock will dilute the percentage ownership interest of all shareholders and may dilute the book value per share of our common stock. WE DERIVE OUR REVENUES FROM A LIMITED NUMBER OF CUSTOMERS. 20 During the fiscal year ending December 31, 2005, we derived all of our revenues from a limited number of customers (purchasers of oil and gas). Our revenues from these customers were comprised of the following percentages: Eighty Eight Oil, LLC- 51.8%; Gulfmark Energy, Inc.- 32.5%; Bear Paw Energy, LLC - 4.1%; Plains Marketing - 10.1%; and others 1.5%. The loss of any particular customer could have a material adverse impact on our financial condition if we are not able to find another purchaser of comparable quantities of oil and gas. EXPANSION OF OUR EXPLORATION PROGRAM WILL REQUIRE CAPITAL FROM OUTSIDE SOURCES. We do not currently have the financial resources to explore and drill all of our currently identified prospects. Absent raising additional capital or entering into joint venture agreements, we will not be able to increase our exploration and drilling operations at the projected rate. This could limit the size of our business. There is no assurance that capital will be available in the future to us or that capital will be available under terms acceptable to us. We will need to raise additional money, either through the sale of equity securities (which could dilute the existing stockholders' interest), through the entering of joint venture agreements (which, while limiting our risk, could reduce our ownership interest in particular assets), or from borrowings from third parties (which could result in additional assets being pledged as collateral and which would increase our debt service requirements). Additional capital could be obtained from a combination of funding sources, many of which could have a material adverse effect on our business, results of operations and financial condition. These potential funding sources, and the potential adverse effects attributable thereto, include: - cash flow from operating activities, which is sensitive to prices we receive for oil and natural gas and the success of current and future operations; - borrowings from financial institutions, which may subject us to certain restrictive covenants, including covenants restricting our ability to raise additional capital or pay dividends; - debt offerings, which would increase our leverage and add to our need for cash to service such debt (which could result in additional assets being pledged as collateral and which could increase our debt service requirements); - additional offerings of equity securities, which would cause dilution of our common stock; - sales of prospects generated by the exploration program, which would reduce future revenues from that program; - additional sales of interests in our projects, which could reduce future revenues; and - arrangement of a business development loan from, or prepayment of terminal use fees by, prospective sellers or purchasers of oil and gas. Our ability to raise additional capital will depend on the results of operations and the status of various capital and industry markets at the time such additional capital is sought. Accordingly, capital may not become available to us from any particular source or at all. Even if additional capital becomes available, it may not be on terms acceptable to us. Failure to obtain additional financing on acceptable terms may have a material adverse effect on our business, results of operations and financial condition. WE DEPEND ON INDUSTRY VENDORS AND MAY NOT BE ABLE TO OBTAIN ADEQUATE SERVICES. We are and will continue to be largely dependent on industry vendors for the success of our oil and gas exploration projects. These contracted services include, but are not limited to, accounting, drilling, 21 completion, workovers (remedial down hole work on a well) and reentries (entering an existing well and changing the direction and/or depth of a well), geological evaluations, engineering, leasehold acquisitoin (landmen), operations, legal, investor relations/public relations, and prospect generation. We could be harmed if we fail to attract quality industry vendors to participate in the drilling of prospects which we identify or if our industry vendors do not perform satisfactorily. We often have, and will continue to have, little control over factors that would influence the performance of our vendors. WE RELY ON THIRD PARTIES FOR PRODUCTION SERVICES AND PROCESSING FACILITIES. The marketability of our production depends upon the proximity of our reserves to, and the capacity of, facilities and third party services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities. The unavailability or lack of capacity of such services and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. A shut-in or delay or discontinuance could materially adversely affect our financial condition. In addition, federal and state regulation of oil and natural gas production and transportation affect our ability to produce and market oil and natural gas on a profitable basis. WE MAY NOT OPERATE ALL PROJECTS. We may not operate all properties in which we have an interest; as a result, we may have limited ability to exercise influence over, and control the risks associated with, operations of these properties. The failure of a well operator to adequately perform operations, an operator's breach of the applicable agreements or an operator's failure to act in ways that are in our best interest could reduce our production and revenues. The success and timing of our development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator's: - timing and amount of capital expenditures; - expertise and financial resources; - inclusion of other participants in drilling wells; and - use of technology. OUR DIRECTORS AND OFFICERS HAVE LIMITED LIABILITY AND HAVE RIGHTS TO INDEMNIFICATION. Our Articles of Incorporation and Bylaws provide, as permitted by governing Nevada law, that our Directors and officers shall not be personally liable to us or any of our stockholders for monetary damages for breach of fiduciary duty as a Director or officer, with certain exceptions. The Articles further provide that we will indemnify our Directors and officers against expenses and liabilities they incur to defend, settle, or satisfy any civil litigation or criminal action brought against them on account of their being or having been its Directors or officers unless, in such action, they are adjudged to have acted with gross negligence or willful misconduct. The inclusion of these provisions in the Articles may have the effect of reducing the likelihood of derivative litigation against Directors and officers, and may discourage or deter stockholders or management from bringing a lawsuit against Directors and officers for breach of their duty of care, even though such an action, if successful, might otherwise have benefited us and our stockholders. The Articles provide for the indemnification of our officers and Directors, and the advancement to them of expenses in connection with any proceedings and claims, to the fullest extent permitted by Nevada law. The Articles include related provisions meant to facilitate the indemnitee's receipt of such benefits. These provisions cover, among other things: (i) specification of the method of determining entitlement to indemnification and the selection of independent counsel that will in some cases make such determination, (ii) specification of certain time periods by which certain payments or determinations must be made and actions must be taken, and (iii) the establishment of certain presumptions in favor of an indemnitee. 22 Insofar as indemnification for liabilities arising under the Securities Act may be permitted to our directors, officers and controlling persons pursuant to the foregoing provisions, we have been advised that in the opinion of the Securities and Exchange Commission, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable. GENERAL RISKS OF THE OIL AND GAS BUSINESS INVESTMENT IN THE OIL AND GAS BUSINESS IS RISKY. Oil and gas exploration and development is an inherently speculative activity. There is no certain method to determine whether or not a given lease will produce oil or gas or yield oil or gas in sufficient quantities and quality to result in commercial production. There is always the risk that development of a lease may result in dry holes or in the discovery of oil or gas that is not commercially feasible to produce. There is no guarantee that a producing asset will continue to produce. Because of the high degree of risk involved, there can be no assurance that we will recover any portion of our investment or that our investment in leases will be profitable. WE ARE SUBJECT TO DRILLING AND OPERATIONAL HAZARDS. The oil and gas business involves a variety of operating risks, including: - blowouts, cratering and explosions; - mechanical and equipment problems; - uncontrolled flows of oil and gas or well fluids; - fires; - marine hazards with respect to offshore operations; - formations with abnormal pressures; - pollution and other environmental risks; and - natural disasters. Any of these events could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses. Locating pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks. In accordance with customary industry practice, we will maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. WE HAVE COMPETITION FROM OTHER COMPANIES. A large number of companies and individuals engage in drilling for gas and oil, and there is competition for the most desirable prospects. We will encounter intense competition from other companies and other entities in the sale of our gas and oil production. We could be competing with numerous gas and oil companies which may have financial resources significantly greater than ours. Further, the quantities of gas and oil to be delivered by us may be affected by factors beyond our control, such as the inability of the wells to deliver at the necessary quality and pressure, premature exhaustion of reserves, changes in governmental regulations affecting allowable production and priority allocations and price limitations imposed by federal and state regulatory agencies. 23 WE MAY BE UNABLE TO ACQUIRE OIL AND GAS LEASES. To engage in oil and gas exploration, we must first acquire rights to conduct exploration and recovery activities on identified prospects. We may not be successful in acquiring "farm-outs" (agreements whereby the owner of lease interests grants to a third party the right to earn an assignment of an interest in the lease, typically by drilling one or more wells), permits, lease options, leases or other rights to explore for or recover oil and gas. The U.S. Department of the Interior and the states in which we and our subsidiaries conduct operations award oil and gas leases on a competitive bidding basis. Non-governmental owners of the onshore mineral interests within the area covered by our exploration program are not obligated to lease their mineral rights to us except where we have already obtained lease options. In addition, other major and independent oil and gas companies with financial resources significantly greater than ours may bid against us for the purchase of oil and gas leases. If we or our subsidiaries are unsuccessful in acquiring these leases, permits, options and other interests, our prospect inventory for exploration and drilling could be significantly reduced, and our business, results of operations and financial condition could be substantially harmed. THE UNAVAILABILITY OR HIGH COST OF DRILLING RIGS, EQUIPMENT, SUPPLIES, PERSONNEL AND OILFIELD SERVICES COULD MATERIALLY ADVERSELY IMPACT US. Drilling activity in the area of our proposed initial activities is extremely high. Increased drilling activity in these areas could decrease the availability of rigs and our access to oilfield services. Either shortages or increases in the cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our operations. There can be no assurance that we will be able to obtain the necessary equipment or services may not be available to us at economical prices. OIL AND GAS PRICES ARE VOLATILE. Our revenues, cash flow, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on the prices that we receive for oil and gas production. Declines in oil and gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil and gas prices also may reduce the amount of oil and gas that we can produce economically. High oil and gas prices could preclude acceptance of our business model. Depressed prices in the future would have a negative effect on our future financial results. Historically, oil and gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Prices for oil and gas are subject to wide fluctuations in response to relatively minor changes in supply of and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include: - the domestic and foreign supply of oil; - the level of consumer product demand; - weather conditions; - political conditions in oil producing regions, including the Middle East; - the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; - the price of foreign imports; - actions of governmental authorities; - domestic and foreign governmental regulations; 24 - the price, availability and acceptance of alternative fuels; and - overall economic conditions. These factors and the volatile nature of the energy markets make it impossible to predict with any certainty future oil and gas prices. Our inability to respond appropriately to changes in these factors could negatively affect their profitability. WE MAY HAVE WRITEDOWNS OF OUR ASSETS DUE TO PRICE VOLATILITY. SEC accounting rules require us to review the carrying value of our oil and gas properties on a quarterly basis for possible write-down or impairment. Under these rules, capitalized costs of proved reserves may not exceed a ceiling calculated at the present value of estimated future net revenues from those proved reserves. Capital costs in excess of the ceiling must be permanently written down. A decline in oil and natural gas prices could cause a write down which would negatively affect our net income. ESTIMATES OF OIL AND GAS RESERVES ARE UNCERTAIN AND MAY VARY SUBSTANTIALLY FROM ACTUAL PRODUCTION. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of expenditures, including many factors beyond our control. Our oil and gas reserves set forth in this Form 10-KSB represent the estimated quantities of oil and gas based on reports prepared by third party reserve engineers. There is a reasonable certainty of recovering the proved reserves as disclosed in those reports. Information relating to our proved oil and gas reserves is based upon engineering data which demonstrates, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and judgment. As a result, estimates of different engineers often vary. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds, and are inherently imprecise. You should not assume that the present values referred to herein represent the current market value of our estimated oil and natural gas reserves. In accordance with requirements of the SEC, the estimates of present values are based on prices and costs as of the date of the estimates. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Quantities of proved reserves are estimated based on economic conditions, including oil and natural gas prices in existence at the date of assessment. Our reserves and future cash flows may be subject to revisions based upon changes in economic conditions, including oil and natural gas prices, as well as due to production results, results of future development, operating and development costs and other factors. Downward revisions of our reserves could have an adverse affect on our financial condition, operating results and cash flows. WE ARE SUBJECT TO GOVERNMENTAL REGULATIONS. Gas and oil operations in the United States are subject to extensive government regulation and to interruption or termination by governmental authorities on account of ecological and other considerations. The Environmental Protection Agency of the United States and the various state departments of environmental affairs closely regulate gas and oil production effects on air, water and surface resources. Furthermore, proposals concerning regulation and taxation of the gas and oil industry are constantly before Congress. It is impossible to predict future proposals that might be enacted into law and the effect they might have on us. Thus, restrictions on gas and oil activities, such as production restrictions, price controls, tax increases and pollution and environmental controls may have a material adverse effect on us. 25 THE OIL AND GAS INDUSTRY IS SUBJECT TO HAZARDS RELATED TO POLLUTION AND ENVIRONMENTAL ISSUES. Hazards in the drilling and/or the operation of gas and oil properties, such as accidental leakage or spillage, are sometimes encountered. Such hazards may cause substantial liabilities to third parties or governmental entities, the payment of which could reduce distributions or result in the loss of our leases. Although it is anticipated that insurance will be obtained by third-party operators for our benefit, we may be subject to liability for pollution and other damages due to environmental events which cannot be insured against due to prohibitive premium costs, or for other reasons. Environmental regulatory matters also could increase substantially the cost of doing business, may cause delays in producing oil and gas or require the modification of operations in certain areas. Our operations are subject to numerous stringent and complex laws and regulations at the federal, state and local levels governing the discharge of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements, and the imposition of injunctions to force future compliance. The Oil Pollution Act of 1990 and its implementing regulations impose a variety of requirements related to the prevention of oil spills, and liability for damages resulting from such spills in United States waters. OPA 90 imposes strict joint and several liability on responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operation regulation. If a party fails to report a spill or to cooperate fully in a cleanup, liability limits likewise do not apply. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages. For onshore facilities, the total liability limit is $350 million. OPA 90 also requires a responsible party at an offshore facility to submit proof of its financial ability to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. The Comprehensive Environmental Response, Compensation, and Liability Act, also known as the "Superfund" law, and analogous state laws impose strict, joint and several liability on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These parties include the owner or operator of the site where the release occurred, and those that disposed or arranged for the disposal of hazardous substances found at the site. Responsible parties under CERCLA may be subject to joint and several liability for remediation costs at the site, and may also be liable for natural resource damages. Additionally, it is not uncommon for neighboring landowners and other third parties to file tort claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. State statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. In addition, there are state statutes, rules and regulations governing conservation matters, including the unitization or pooling of oil and gas properties, establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. Such statutes and regulations may limit the rate at which oil and gas could otherwise be produced from our properties and may restrict the number of wells that may be drilled on a particular lease or in a particular field. WE MAY EXPERIENCE RAPID INCREASES IN OUR OPERATING COSTS. The gas and oil industry historically has experienced periods of rapid cost increases from time to time. Increases in the cost of exploration and development would affect our ability to acquire equipment and supplies. Increased drilling activity could lead to shortages of equipment and material which would make timely drilling and completion of wells impossible. The costs of producing oil and gas and conducting field operations may also be subject to rapid cost changes that are not in our control. There is no assurance that over the life of any project there will not be fluctuating or increasing costs in doing business. 26 TERRORIST ATTACKS AND CONTINUED HOSTILITIES IN THE MIDDLE EAST OR OTHER SUSTAINED MILITARY CAMPAIGNS MAY ADVERSELY IMPACT THE INDUSTRY AND US. The terrorist attacks that took place in the United States on September 11, 2001, were unprecedented events that have created many economic and political uncertainties, some of which may materially adversely impact us. The long-term impact that terrorist attacks and the threat of terrorist attacks may have on the oil and gas business is not known at this time. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may adversely impact us in unpredictable ways. CRITICAL ACCOUNTING POLICIES Our discussion and analysis of our financial condition and results of operations are based upon financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We analyze our estimates, including those related to oil and gas properties, income taxes, commitments and contingencies and stock based compensation, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates. We believe the following critical accounting policies are subject to significant judgments and estimates used in the preparation of our financial statements: Oil and Gas properties. The Company uses the full cost method of accounting for oil and gas operations. Accordingly, all costs, including nonproductive costs and certain overhead costs associated with acquisition, exploration and development of oil and gas properties, are capitalized. Net capitalized costs are limited to the future net revenues, after income taxes, discounted at 10% per year, from proven oil and gas reserves plus the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and remediation costs, if any, are depleted by an equivalent units-of-production method, converting gas units (MCF) to oil units (barrels) at the ratio of six MCF of gas to one barrel of oil. Also, with full cost accounting, no gain or loss is recognized upon the disposal of oil and gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of undeveloped leaseholds and other geological and exploration costs, and totaled $3,513,597 at December 31, 2005. These costs are reviewed periodically by management for impairment, with the impairment provision included in the cost of the oil and gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results, re-evaluations of properties, terms of oil and gas leases not held by production and available funds for exploration and development. Income taxes. The Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities, and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. Periodically, management performs a forecast of its taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established, if in management's opinion, it is more likely than not, that some portion will not be realized. At December 31, 2005, a valuation allowance of $1,628,636 has been provided for deferred tax assets. Commitments and contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Management does not see any circumstances that would require the Company 27 to record a loss contingency; therefore, to date no commitments or contingencies have been recorded. Stock Based Compensation Through December 31, 2005 we have accounted for stock-based awards to employees in accordance with Accounting Principles Board Opinion ("APB") No. 25, Accounting for Stock Issued to Employees". Under APB 25, compensation expense is only recorded for employees if the exercise price of the Company's stock option is less than the market value of the underlying stock on the date of grant. Therefore, through December 31, 2005, the Company has followed a policy to only grant to employees, stock options with an exercise price greater than the market value of the underlying stock. We have accounted for stock-based awards to non-employees in accordance with the Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based Compensation". SFAS No. 123 requires that compensation expense be recorded for stock options awarded to non-employees valued at the fair value on the date of the award. Management estimates the fair value of the stock options using the Black-Scholes option-pricing model and in the calculation, makes subjective assumptions for the applicable interest rates, stock volatility and dividend yield. In all cases, the calculated compensation is recognized as an expense over the period that the employee performs the related services. Compensation expense of $-0- was recorded in the year ending December 31, 2005. In December 2004, the FASB issued SFAS No. 123 (revised 2004), "Share-Based Payment", that will require, starting in fiscal year 2006, compensation costs related to share-based payment transactions to be recognized in financial statements. With limited exceptions, the amount of compensation cost associated with all stock option grants will be measured based on the grant-date fair value of the equity instruments. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. The standard replaces SFAS No. 123, "Accounting for Stock-Based Compensation", and supersedes APB Opinion No. 25, "Accounting for Stock Issued to Employees". It is effective for small business issuers for the first interim or annual reporting period beginning after December 15, 2005, meaning that the Company will apply the guidance to all employee awards of share-based payment granted, modified or settled in the first quarter of 2006. ITEM 7. FINANCIAL STATEMENTS The information required by this Item 7 is included in this report beginning on page F-1 ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE There have been no changes in or disagreements with accountants on accounting and financial disclosure. ITEM 8A. CONTROLS AND PROCEDURES Richard D. Dole, our Chief Executive Officer, and David J. Collins, our Chief Financial Officer, have concluded that our disclosure controls and procedures are appropriate and effective. They have evaluated these controls and procedures as of December 31, 2005. There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. ITEM 8B. OTHER INFORMATION None 28 PART III ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT DIRECTORS AND EXECUTIVE OFFICERS The following table sets forth our Directors and executive officers as of December 31, 2005.
----------------------------------------------------------- NAME AGE POSITION ---- --- -------- ----------------------------------------------------------- ----------------------------------------------------------- Richard D. Dole 60 Director, Chairman, President and CEO ----------------------------------------------------------- Wayne Beninger. 52 Chief Operating Officer ----------------------------------------------------------- David Collins 37 Chief Financial Officer ----------------------------------------------------------- Eric D. Brown 41 Vice President of Finance ----------------------------------------------------------- Gerald Agranoff 59 Director ----------------------------------------------------------- Richard Majeres 39 Director -----------------------------------------------------------
RICHARD D. DOLE, DIRECTOR, CHAIRMAN OF THE BOARD, PRESIDENT AND CEO Mr. Dole joined us as a Director in July 2004, and assumed the positions of Chairman, President and CEO in December 2004. Mr. Dole previously served as Vice President and Chief Financial Officer for Burlington Resources International from 1998 to 2000. Since that time he has been active in consulting and financial services. He was a co-founder of Benefits Access Solutions, LLC, a company formed to provide financial services and benefit options to employees and members of corporate organizations. He was also co-founder and managing partner of Innovation Growth Partners, LLC, a firm that provided management and consulting services to early stage companies. Mr. Dole's extensive industry experience includes being National Partner-in-Charge of Business Process Solutions at KPMG. Prior to that he was with Coopers & Lybrand (now PriceWaterhouse Coopers) where he served as Assurance and Business Advisory Partner for nearly 20 years and also served in numerous senior management roles, including National Chairman for the Energy and Natural Resources Industry practices for over 15 years and as the Vice Chairman for the U.S. Process Management business unit. From August 2003 to July 2004, Mr. Dole was also a member of the Board of Directors of Westport Resources Corporation (NYSE: WRC), a member of its audit committee and a designated financial expert. He currently serves as a director of Double Eagle Petroleum Company (DBLE, NASDAQ, small cap) and chairs the audit committee and is the designated financial expert. Mr. Dole graduated from Colorado State University. WAYNE BENINGER, CHIEF OPERATING OFFICER Mr. Beninger joined us as Chief Operating Officer in May 2005. Prior to May 2005, Mr. Beninger served as President of Southwest Oil & Gas Management, Inc. ("SOGMI") which he founded in 1997 to provide oil and gas property evaluation services, geologic prospect review, contract operating services, technical support for initial public offerings and strategic planning solutions for domestic and international projects. Prior to Mr Beninger joining the Company, SOGMI provided a significant amount of our engineering and geological services for all projects. From 1995 to 1997, Mr. Beninger was the Vice President for Strategic Planning with WRT Energy Corporation. From 1982 to 1995 he was first employed by, and then was a partner in, The Scotia Group, a domestic and international consulting firm where he provided petroleum engineering and geological services for companies and projects in the majority of active petroleum basins in both the U.S. and overseas. He has been active in the oil and gas industry since 1976. Mr. Beninger holds undergraduate degrees in both petroleum engineering and geology from the University of Southern California and has a number of industry publications to his credit. He is a member of the Society of Petroleum Engineers, Pi 29 Epsilon Tau (petroleum engineering honorary fraternity) and Sigma Gamma Epsilon (geologic honorary fraternity). DAVID COLLINS, VICE PRESIDENT, CHIEF FINANCIAL OFFICER Mr. Collins joined Petrosearch Corporation as a Vice President and the Chief Financial Officer in October 2003. Previously, he served as the Controller of Kazi Management VI, LLC, a diversified investment and management organization actively involved in energy, retail food chains, aquaculture and biotechnology from February 2002 to October 2003. At Kazi Management VI, he was responsible for the financial operations of multiple accounting offices across the United States, as well as fourteen international and domestic Companies. Mr. Collins was also the Chief Financial Officer of ZK Petroleum, an independent oil producer in South Texas. Prior to Kazi Management VI, he served as an independent analyst for The March Group in St. Thomas, U.S.V.I. from February 2001 to January 2002. Mr. Collins previously held the position of Chief Financial Officer of Federation Logistics, LLC in the New York metropolitan area from November 1994 to January 2001. Mr. Collins graduated from Villanova University in 1990 with a Bachelor's degree in Accountancy. He became a Certified Public Accountant and began his career in the Financial Services Division of Ernst and Young in New York City. At Ernst and Young, he performed audits of Fortune 500 Companies. ERIC D. BROWN, VICE PRESIDENT OF FINANCE Mr. Brown joined us in March 2004 as a consultant and became Vice President of Finance on January 1, 2005. Previously, he served as vice president and national sales manager of GE Capital Public Finance Inc., a subsidiary of the General Electric Company. While at General Electric, beginning in March 1997, Mr. Brown was responsible for strategic direction, creation of new financing vehicles, deal structuring, implementation and management of the corporate finance arm of GE Capital Public Finance. Before joining General Electric, he served as Managing Director of the Massachusetts Industrial Finance Agency and previously worked for various financial institutions in New York City doing structured and corporate finance. Mr. Brown holds degrees in Economics and French from Bowdoin College in Brunswick, Maine. Subsequent to the year end Mr. Brown tendered his resignation effective April 1, 2006, to pursue other activities. GERALD N. AGRANOFF, DIRECTOR Gerald N. Agranoff joined us as a Director in May 2004. Mr. Agranoff has been counsel to the firm of Kupferman & Kupferman, L.L.P. in New York since 2004 and has been a general partner of SES Family Investment and Trading Partnership, L.P., an investment partnership since 2004. Mr Agranoff has also been a member of Inveraray Capital Management L.L.C., the investment manager of Highlander Fund B.V. and Highlander Partners (USA) L.P since 2002. He is also a director and the chair of the audit committee of Triple Crown Media Inc (symbol, TCMI). Active in Wall Street financial transactions for over two decades, his specialties include taxation, investments and corporate finance. From 1975 through 1981, Mr. Agranoff was engaged exclusively in the private practice of law in New York and was an adjunct-instructor at New York University's Institute of Federal Taxation. Previously, he served as attorney-advisor to a Judge of the United States Tax Court. He holds an L.L.M. degree in Taxation from New York University and J.D. and B.S. Degrees from Wayne State University. RICHARD MAJERES, DIRECTOR Richard Majeres joined us as a Director in May 2004. In December 2000, Mr. Majeres was one of the founding partners of the Houston public accounting firm Ubernosky & Majeres, PC, which currently operates as Ubernosky, Passmore & Majeres, LLP, offering tax, audit, accounting and management consulting services. Mr. Majeres has served as a partner of this firm since its inception in December 2000. From January 1999 to November 2000, Mr. Majeres was a partner at Cox & Lord, PC. Mr. Majeres graduated from Bemidji State University, Bemidji, Minnesota in 1989 with a bachelor's degree in accounting. Upon graduation, he served as a field auditor with the Federal Energy Regulatory Commission of the Department of Energy. Mr. Majeres became a certified public accountant in 1992. He has extensive experience with oil and gas entities, including exploration and development partnerships and corporations and currently focuses a majority of his efforts on the Firm's audit practice. 30 COMMITTEES OF THE BOARD OF DIRECTORS We held two in person and four telephonic meetings of the Board of Directors during the fiscal year ended December 31, 2005, and the Board of Directors took action at Board meetings or by unanimous written consent eight times during that period. Mr. Dole is our only Director who is also an Officer. We currently have an audit committee of the Board of Directors made up of Richard Majeres and Gerald Agranoff. The Board of Directors is in the process of evaluating the need for other appropriate committees for our future growth. We do not currently have a process for security holders to send communications to the Board of Directors. However, we welcome comments and questions from our shareholders. Shareholders can direct communications to our Chief Executive Officer, Richard D. Dole, at our executive offices, 675 Bering Drive, Suite 200, Houston, Texas 77057. While we appreciate all comments from shareholders, we may not be able to individually respond to all communications. We attempt to address shareholder questions and concerns in our press releases and documents filed with the SEC so that all shareholders have access to information about us at the same time. Mr. Dole collects and evaluates all shareholder communications. If the communication is directed to the Board of Directors generally or to a specific director, Mr. Dole will disseminate the communications to the appropriate party at the next scheduled Board of Directors meeting. If the communication requires a more urgent response, Mr. Dole will direct that communication to the appropriate executive officer. All communications addressed to our directors and executive officers will be reviewed by those parties unless the communication is clearly frivolous. Our Bylaws provide that nominations of persons for election to the Board of Directors of the corporation may be made at a meeting of stockholders by or at the direction of the Board of Directors or by any stockholder of the corporation entitled to vote in the election of directors at the meeting who complies with the following notice procedures, as set forth in the Bylaws: Nominations of persons for election to the Board of Directors may be made at a meeting of the shareholders at which directors are to be elected (a) by or at the direction of the Board of Directors, or (b) by any shareholder of the Company who is a shareholder of record at the time of the giving of such shareholders notice provided for in Paragraph 3.3 (of the Bylaws), who shall be entitled to vote at such meeting in the election of directors and who complies with the requirements of Paragraph 3.3 (of the Bylaws). Such nominations, other than those made by or at the direction of the Board of Directors shall be preceded by timely advance notice in writing to the Secretary. To be timely, a shareholder's notice shall be delivered to, or mailed and received at, the principal executive offices of the Company (1) with respect to an election to be held at the annual meeting of the shareholders of the Company, not later than the close of business on the 90th day prior to the first anniversary of the preceding year's annual meeting; provided, however, in the event that the date of the annual meeting is more than 30 days before or more than 60 days after such anniversary date, notice by the shareholder to be timely must be so delivered not later than the close of business on the later of the 90th day prior to such annual meeting or the 10th day following the day on which public announcement of the date of such meeting is first made by the Company; and (2) with respect to an election to be held at a special meeting of shareholders of the Company for the election of directors not later than the close of business on the 10th day following the day on which notice of the date of the special meeting was mailed to shareholders of the Company as provided in Paragraph 2.4 (of the Bylaws) or public disclosure of the date of the special meeting was made, whichever first occurs. Any such shareholder's notice to the Secretary shall set forth (x) as to each person whom the shareholder proposes to nominate for election or re-election as a director, (i) the name, age, business address and residence address of such person; (ii) the principal occupation or employment of such person; (iii) the number of shares of each class of capital stock of the Company's beneficially owned by such person; (iv) the written consent of such person to having such person's name placed in nomination at the meeting and to serve as a director if elected; (v) any other information relating to such person that is required to be disclosed in solicitations of proxies for election of directors, or is otherwise required, pursuant to Regulation 14A under the Exchange Act, and (vi) as to the 31 shareholder giving the notice, (i) the name and address, as they appear on the Company's books of such shareholder, and (ii) the number of shares of each class of voting stock of the Company which are then beneficially owned by such shareholder. The presiding officer of the meeting of shareholders shall determine whether the requirements of Paragraph 3.3 (of the Bylaws) have been met with respect to any nomination or intended nomination. If the presiding officer determines that any nomination was not made in accordance with the requirements of Paragraph 3.3 (of the Bylaws), he shall so declare at the meeting and the defective nomination shall be disregarded. Notwithstanding the foregoing provisions , a shareholder shall also comply with all applicable requirements of the Exchange Act and the rules and regulations thereunder with respect to the matters set forth in Paragraph 3.3 of the Bylaws. For (purposes of the notice provisions of the Bylaws), public disclosure shall be deemed to first be given to shareholders when disclosure of such date of the meeting of shareholders is first made in a press release reported by the Dow Jones News Services, Associated Press or comparable national news service, or in a document publicly filed by the Company with the Securities and Exchange Commission pursuant to Sections 13, 14 or 15(d) of the Exchange Act. COMPLIANCE WITH SECTION 16(A) OF THE SECURITIES EXCHANGE ACT OF 1934 Section 16(a) of the Securities Exchange Act of 1934 requires our directors and executive officers, and persons who own beneficially more than ten percent of our common stock, to file reports of ownership and changes of ownership with the Securities and Exchange Commission. Based solely on the reports we have received and on written representations from certain reporting persons, we believe that the directors, executive officers, and greater than ten percent beneficial owners have complied with all applicable filing requirements. CODE OF ETHICS Effective August 19, 2005, the Board of Directors adopted a Code of Ethics for our directors, officers and employees. A copy of our Code of Ethics was filed with our Form SB-2 registration statement on June 6, 2005. ITEM 10. EXECUTIVE COMPENSATION The following table sets forth certain compensation information for the following individuals for the three most recently completed fiscal years ended December 31, 2005. No other compensation was paid to our named executive officers other than the compensation set forth below. The compensation reflected in this section has been awarded by us and our predecessor, Petrosearch Texas.
------------------------------------------------------------------------------------------------------------ SUMMARY COMPENSATION TABLE ------------------------------------------------------------------------------------------------------------- ANNUAL COMPENSATION LONG TERM COMPENSATION ------------------------------------------------------------------------------------------------------------- AWARDS PAYOUTS --------------------------------- OTHER OPTIONS/ ANNUAL RESTRICTED SARS LTIP ALL OTHER COMP- STOCK WARRANTS PAYOUTS COMP- NAME TITLE YEAR SALARY BONUS ENSATION AWARDED (#) ($) ENSATION ------------------------------------------------------------------------------------------------------------- Richard Chairman, 2005 $180,000 -0- -0- -0- -0- -0- -0- Dole(1) CEO and 2004 $ 90,000 -0- -0- -0- 3,930,046 -0- -0- President 2003 -0- -0- -0- -0- 15,385 -0- -0- ------------------------------------------------------------------------------------------------------------- 32 Bradley Former 2005 -0- -0- -0- -0- -0- -0- -0- Simmons (2) Director, 2004 $180,000 $50,000 -0- -0- -0- -0- $ 110,000(3) CEO and 2003 $320,370 -0- -0- -0- 730,769 -0- -0- President ------------------------------------------------------------------------------------------------------------- Wayne Chief 2005 135,417 25,000 -0- -0- 365,000 -0- -0- Beninger (4) Operating 2004 -0- -0- -0- -0- -0- -0- -0- Officer 2003 -0- -0- -0- -0- -0- -0- -0- ------------------------------------------------------------------------------------------------------------- David Collins Chief 2005 $180,000 -0- -0- -0- 50,000 -0- -0- (5) Financial 2004 $165,000 $25,000 -0- $ 15,000 -0- -0- -0- Officer 2003 -0- -0- -0- $ 45,000 323,077 -0- -0- ------------------------------------------------------------------------------------------------------------- Eric Brown (6) V.P., 2005 $180,000 -0- -0- -0- 500,000 -0- -0- Finance 2004 $105,000 -0- -0- -0- 53,846 -0- -0- 2003 -0- -0- -0- -0- -0- -0- -0- -------------------------------------------------------------------------------------------------------------
Notes to Summary Compensation Table: (1) Mr. Dole was appointed as a Director in July 2004. On December 30, 2004, Mr. Dole assumed the roles of Chairman of our Board of Directors, President and Chief Executive Officer Mr. Dole entered into an employment agreement with the Company in November 2004 for a term of 2 years which called for compensation of $15,000 per month. Mr. Dole became an employee of the Company as of January 1, 2005. (2) Mr. Simmons served as a Director and Chief Executive Officer and President until his resignation on December 30, 2004. Mr. Simmons entered into a consulting agreement with the Company in December 2004 for a term of one year which calls for compensation of $15,000 per month. In September 2005 the Company and Mr. Simmons mutually agreed to terminate his consulting agreement. (3) During 2004, the Board of Directors approved advances to Mr. Simmons which were to be evaluated at year-end as possible compensation. The Board of Directors authorized a portion of the advances as a year-end performance bonus for 2004; the remaining balance of the advances was converted to a non-interest bearing receivable to the Company as of December 31, 2004. The outstanding balance of the loan as of December 31, 2005 was -0-. (4) Mr. Beninger was appointed Chief Operating Officer in May, 2005. Mr. Beninger became an employee and entered into an employment agreement with the Company on May 1, 2005, for a term of 2 years which calls for compensation of $20,830 per month and a $50,000 annual bonus each year. (5) Mr. Collins was appointed Chief Financial Officer in September, 2004. Mr. Collins became an employee of the Company as of January 1, 2005. Mr. Collins entered into an employment agreement with the Company May 1, 2005, for a term of 2 years which calls for compensation of $15,000 per month. (6) Mr. Brown was appointed Vice President of Finance on December 30, 2004. Mr. Brown became an employee of the Company as of January 1, 2005. Mr. Brown entered into an employment agreement with the Company May 1, 2005, for a term of 2 years which calls for compensation of $15,000 per month. Subsequent to the year end Mr. Brown tendered his resignation effective April 1, 2006. DIRECTOR COMPENSATION In May 2004, as director compensation, Messrs. Agranoff and Majeres each received 61,538 warrants to purchase shares of our common stock at a strike price of $6.50 per share which will expire on May 20, 2007. Additionally, in December 2004, Mr. Agranoff was paid $4,500 for consulting services to us. 33 From January 1, 2005 until December 31, 2005, Mr. Agranoff received $4,500 per month for consulting services provided to us including consultation, participation and review of our restructuring, the private placement transaction and the SB-2 Registration Statement. These services are no longer provided by Mr. Agranoff. On March 25, 2005, the Board of Directors approved compensation to each of Gerald Agranoff, Richard Majeres and Don Henrich (our former Director) in an amount of (i) $25,000, which was payable $5,000 in cash and $20,000 in restricted stock, and (ii) 50,000 warrants to purchase our common stock at a strike price of $1.95 per share. EMPLOYMENT AGREEMENTS The employment contracts in existence with officers and key personnel include the above referenced November 15, 2004, contract with Richard Dole (Chairman, President and CEO), and employment contracts with each of David Collins (Vice President and Chief Financial Officer), Eric Brown (Vice President of Finance), and Wayne Beninger, our Chief Operating Officer, each dated as of May 1, 2005. The employment contracts with Messrs. Dole, Collins, Brown and Beninger provide for an employment term of two years. Each of the employment contracts provides for termination by the Company upon death or disability, with six month severance payments. Each of the employment contracts permits termination by the Company for cause, which includes malfeasance, misuse of funds, insubordination, a material uncured breach or conviction for a felony or crime of moral turpitude. The agreements may be voluntarily terminated by the employee at any time, with no severance payment. Additionally, the respective employees may elect to terminate their employment contract and receive severance pay upon a material uncured breach by the Company or a change in control, if within forty five days of the change in control the employee is not offered a position with the identical salary for a period equal to the then remaining term plus one year. For purposes of each agreement, a change in control is defined as a change in the majority of the Board of Director positions accompanying the acquisition of voting securities by a third party (other than directly from the Company) equivalent to forty percent of the voting control of the Company (other than a subsidiary or employee benefit plan), or accompanying a sale of all of the assets or a merger (other than involving a subsidiary). Upon termination for cause, the employee is not entitled to severance pay. A termination without cause while a contract is pending, other than due to a change in control, entitles the employees other than Mr. Dole to compensation through the end of the contract term plus an additional three months. A termination without cause of Mr. Dole or non-renewal of Mr. Dole's agreement gives rise to a severance pay obligation equal to twelve months. Upon a termination coupled with a change in control where the particular employee is not offered a position for the identical salary, and in the case of Messrs. Dole and Beninger, the same position, the employee is entitled to severance compensation equal to the face period of the employment contract then pending at termination (e.g. a 1-year contract would give rise to twelve months severance pay).
OPTION/SAR/WARRANT GRANTS IN LAST FISCAL YEAR --------------------------------------------- (Individual Grants) ------------------- ------------------------------------------------------------------------------------------- Number of Percent of Total Securities Options/SARs/ Underlying Warrants Granted Exercise of Base Name Warrants/Options/ to Employees in Price ($/Sh) Expiration Date SARS Granted (#) Fiscal Year (%) ------------------------------------------------------------------------------------------- Richard Dole -0- -0- N/A N/A ------------------------------------------------------------------------------------------- Wayne Beninger 365,000 36.0% $ 1.95 11/15/2008 ------------------------------------------------------------------------------------------- David Collins 50,000 4.9% $ 1.95 11/15/2008 ------------------------------------------------------------------------------------------- Eric Brown 500,000 49.3% $ 1.95 11/15/2008 ------------------------------------------------------------------------------------------- Richard Majeres 50,000 4.9% $ 1.95 11/15/2008 ------------------------------------------------------------------------------------------- Gerald Agranoff 50,000 4.9% $ 1.95 11/15/2008 -------------------------------------------------------------------------------------------
34
AGGREGATED OPTION/SAR/WARRANT EXERCISES IN LAST FISCAL YEAR AND FY-END OPTION/SAR VALUES --------------------------------------------- ---------------------------------------------------------------------------------------------- Number of Value of Unexercised Unexercised In-The- Underlying Money Shares Acquired Options/SARs/ Options/SARs/ Name on Exercise (#) Value Realized ($) Warrants at FY end Warrants at FY end (#); ($); Exercisable/ Exercisable/ Unexercisable Unexercisable ---------------------------------------------------------------------------------------------- Richard Dole -0- -0- 2,995,430/-0- -0-/-0- ---------------------------------------------------------------------------------------------- Wayne Beninger -0- -0- 399,616/-0- -0-/-0- ---------------------------------------------------------------------------------------------- David Collins -0- -0- 373,077/-0- -0-/-0- ---------------------------------------------------------------------------------------------- Eric Brown -0- -0- 553,847/-0- -0-/-0- ---------------------------------------------------------------------------------------------- Richard Majeres -0- -0- 111,538/-0- -0-/-0- ---------------------------------------------------------------------------------------------- Gerald Agranoff -0- -0- 111,538/-0- -0-/-0- ----------------------------------------------------------------------------------------------
There were no stock options, SAR's or warrants exercised by any of our named executive officers during our most recent fiscal year ended December 31, 2005. Other than those awards listed above, we have no long-term incentive plans. ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER The following table sets forth certain information at March 15, 2006 with respect to the beneficial ownership of shares of common stock by (i) each person known to us who owns beneficially more than 5% of the outstanding shares of common stock, (ii) each of our Directors, (iii) each of our Executive Officers and (iv) all of our Executive Officers and Directors as a group. Unless otherwise indicated, each stockholder has sole voting and investment power with respect to the shares shown. As of March 15, 2006, we had 31,057,101 shares of common stock issued and outstanding.
--------------------------------------------------------------------------------- TITLE OF CLASS NAME AND ADDRESS OF NUMBER OF SHARES PERCENTAGE OF BENEFICIAL OWNER OF COMMON STOCK COMMON STOCK (1) --------------------------------------------------------------------------------- Common Stock Richard D. Dole 3,060,815(2) 8.99% Chairman, President and CEO 675 Bering Drive, Suite 200 Houston, Texas 77057 --------------------------------------------------------------------------------- Common Stock Wayne Beninger 647,308 (3) 2.06% Chief Operating Officer 675 Bering Drive, Suite 200 Houston, Texas 77057 --------------------------------------------------------------------------------- Common Stock David J. Collins 913,263(4) 2.91% Vice President and Chief Financial Officer 675 Bering Drive, Suite 200 Houston, Texas 77057 35 --------------------------------------------------------------------------------- Common Stock Eric D. Brown 696,360(5) 2.20% Vice President of Finance 675 Bering Drive, Suite 200 Houston, Texas 77057 --------------------------------------------------------------------------------- Common Stock Gerald Agranoff 121,795 (6) 0.39% Director 675 Bering Drive, Suite 200 Houston, Texas 77057 --------------------------------------------------------------------------------- Common Stock Richard Majeres 196,795 (7) 0.63% Director 675 Bering Drive, Suite 200 Houston, Texas 77057 --------------------------------------------------------------------------------- --------------------------------------------------------------------------------- ALL OFFICERS AND DIRECTORS 5,636,336 17.18% AS A GROUP (TOTAL OF 6) --------------------------------------------------------------------------------- --------------------------------------------------------------------------------- Common Stock GLG Partners, LP 1,795,098 (8) 5.78% 1 Curzon Street London, XO W1J 5HB --------------------------------------------------------------------------------- Common Stock North Sound Capital, LLC 2,770,000 (9) 8.92% 20 Horseneck Lane Greenwich, CT 06830 --------------------------------------------------------------------------------- Common Stock Charles L Barney 1,538,464 (10) 4.95% 90 Echo Lane, Suite 364 Houston, TX 77024 ---------------------------------------------------------------------------------
(1) Under Rule 13d-3 promulgated under the Exchange Act, a beneficial owner of a security includes any person who, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares: (i) voting power, which includes the power to vote, or to direct the voting of shares; and (ii) investment power, which includes the power to dispose or direct the disposition of shares. Certain shares may be deemed to be beneficially owned by more than one person (if, for example, persons share the power to vote or the power to dispose of the shares). In addition, shares are deemed to be beneficially owned by a person if the person has the right to acquire the shares (for example, upon exercise of an option) within 60 days of the date as of which the information is provided. In computing the percentage ownership of any person, the amount of shares is deemed to include the amount of shares beneficially owned by such person (and only such person) by reason of these acquisition rights. As a result, the percentage of outstanding shares of any person as shown in this table does not necessarily reflect the person's actual ownership or voting power with respect to the number of shares of common stock actually outstanding on March 15, 2006. As of March 15, 2006 there were 31,057,101 shares of our common stock issued and outstanding. (2) Includes 65,385 shares of common stock held directly and 2,995,430 shares issuable upon the exercise of warrants to purchase additional shares of common stock. Excludes 950,000 warrants issued to Mr. Dole that have been gifted to his children, to which Mr. Dole disavows beneficial ownership. (3) Includes 247,692 shares of common stock held directly and 399,616 shares issuable directly upon the exercise of warrants to purchase additional shares of common stock. (4) Includes 413,263 shares held indirectly through DC Financial Services, LLC, 126,923 shares held directly and 373,077 shares issuable directly upon the exercise of warrants to purchase additional shares of common stock. (5) Includes 139,743 shares held indirectly through Famco of Maryland LP, 2,770 held directly, and 553,847 shares issuable directly upon the exercise of warrants to purchase additional shares of common stock. 36 (6) Includes 10,257 shares held directly and 111,538 shares issuable upon the exercise of warrants to purchase additional shares of common stock. (7) Includes 85,257 shares held directly by Mr. Majeres and 111,538 shares issuable upon the exercise of warrants to purchase additional shares of common stock. (8) Includes 1,421,200 shares held by GLG North American Opportunity Fund; 322,308 shares held by GLG North American Equity Fund; 13,000 shares held by CITI GLG North American Fund Limited; and 38,590 shares held by Lyxor/GLG Pan European Equity Fund Limited. (9) Includes 775,600 shares held by North Sound Institutional Fund and 1,994,400 shares held by North Sound International Fund. (10) Includes 1,076,926 shares held by C Barney Investments, Ltd. and 461,538 shares held by Mark X Energy Company. _____________________________ We are not aware of any arrangements that could result in a change of control. The disclosure required by Item 201(d) of Regulation S-B is set forth in ITEM 5 herein. ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Except as described below, none of the following persons has any direct or indirect material interest in any transaction to which we were or are a party during the past two years, or in any proposed transaction to which we propose to be a party: (A) any of our directors or executive officers; (B) any nominee for election as one of our directors; (C) any person who is known by us to beneficially own, directly or indirectly, shares carrying more than 5% of the voting rights attached to our common stock; or (D) any member of the immediate family (including spouse, parents, children, siblings and in-laws) of any of the foregoing persons named in paragraph (A), (B) or (C) above. Mr. Wayne Beninger, who became our Chief Operating Officer on May 16, 2005, is the owner of Southwest Oil & Gas Management ("SOGMI") which has provided engineering and geological consulting services for our projects. During the fiscal year ended December 31, 2004, we paid SOGMI approximately $600,000 for such services. When Mr. Beninger became our employee, the agreement with SOGMI was terminated. From January 1, 2005, until the agreement was terminated on May 15, 2005, we paid SOGMI approximately $365,529 for engineering and geological consulting services. We believe the prices and bids for engineering and geological consulting services previously paid to SOGMI have been competitive with those quoted for similar services by unrelated third parties. Mr. Beninger has an option to purchase for $1.00 a 5% interest (after payout to the company and our drilling partner) in our subsidiary that holds the Jefferson County, Mississippi project. One of our former Directors, Mr. Don Henrich, is a principal officer of Maverick Drilling Co., Inc., a company which is owned by his wife, with which we contracted for drilling services in Fort Bend County, Texas. Additionally, Mrs. Henrich owned a 15-30% working interest in our Fort Bend County Prospect, which was sold in July, 2005. During the fiscal year ending December 31, 2005, we paid Maverick Drilling 37 Company approximately $316,000. We believe Maverick's prices and bids for drilling services have been competitive with those quoted for similar services by unrelated third parties. ITEM 13. EXHIBITS Exhibit 10.1 - First Amended and Restated Program Agreement, dated February 6, 2006. Exhibit 10.2 - Extension Agreement, dated March 30, 2006 Exhibit 23.1 - Consent of Independent Engineers - McCartney Engineering LLC, dated March 29, 2006 Exhibit 23.2 - Consent of Independent Engineers Ryder Scott Company, dated March 29, 2006 Exhibit 31.1 - Certification of Chief Executive Officer of Petrosearch Energy Corporation required by Rule 13a-14(1) or Rule 15d - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Exhibit 31.2 - Certification of Chief Financial Officer of Petrosearch Energy Corporation required by Rule 13a-14(1) or Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Exhibit 32.1 - Certification of Chief Executive Officer of Petrosearch Energy Corporation pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and Section 1350 of 18 U.S.C. 63. Exhibit 32.2 - Certification of Chief Financial Officer of Petrosearch Energy Corporation pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and Section 1350 of 18 U.S.C. 63. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES The following table sets forth the aggregate fees paid or accrued for professional services rendered by Ham, Langston & Brezina for the audit of our annual financial statements for fiscal year 2005 and fiscal year 2004 and the aggregate fees paid or accrued for audit-related services and all other services rendered by Ham, Langston & Brezina for fiscal year 2005 and fiscal year 2004.
2005 2004 ------------ ------------ Audit fees $ 48,000 $ 62,500 Audit-related fees 23,000 26,500 Tax fees 9,805 4,850 All other fees 27,309 11,664 ------------ ------------ Total $ 108,114 $ 105,514 ============ ============
The category of "Audit fees" includes fees for our annual audit, quarterly reviews and services rendered in connection with regulatory filings with the SEC, such as the issuance of comfort letters and consents. The category of "Audit-related fees" includes employee benefit plan audits, internal control reviews and accounting consultation. The category of "Tax fees" includes consultation related to corporate development activities. All above audit services, audit-related services and tax services were pre-approved by the Audit Committee, which concluded that the provision of such services by Ham, Langston & Brezina was compatible with the maintenance of that firm's independence in the conduct of its auditing functions. 38 SIGNATURES In accordance with the requirements of Section 13 of 15(d) of the Exchange Act, the Registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 31, 2006. PETROSEARCH ENERGY CORPORATION By /s/ Richard D. Dole ---------------------- Richard D. Dole President and Chief Executive Officer By /s/ David Collins ------------------- David Collins Chief Financial Officer and Principal Accounting Officer In accordance with the requirements of the Securities Act of 1933, this Form 10-KSB has been signed below by or on behalf of the following persons in the capacities and on the dates stated.
Signature Title Date By /s/ Richard D. Dole President, Chief Executive Officer March 31, 2006 ----------------------- and Chairman of the Board Richard D. Dole By /s/ David J. Collins Chief Financial Officer March 31, 2006 ----------------------- and Principal Accounting Officer David J. Collins By /s/ Gerald Agranoff Director March 31, 2006 ----------------------- Gerald Agranoff By /s/ Richard Majeres Director March 31, 2006 ----------------------- Richard Majeres
39 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ------------------------------------------------------- To the Board of Directors and Stockholders Petrosearch Energy Corporation We have audited the accompanying consolidated balance sheets of Petrosearch Energy Corporation and subsidiaries as of December 31, 2005 and 2004 and the related consolidated statements of operations, stockholders' equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Petrosearch Energy Corporation and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America. /s/ Ham, Langston & Brezina, L.L.P. Houston, Texas March 29, 2006 F-1
PETROSEARCH ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS DECEMBER 31, 2005 AND 2004 ASSETS 2005 2004 ------ ------------ ------------ Current assets: Cash $ 4,052,844 $ 1,100,568 Accounts receivable: Joint owners-billed, net of allowance of $83,073 at 1,342,386 935,622 December 31, 2005 Joint owners-unbilled 1,958 624,541 Oil and gas production sales 9,345 264,623 Prepaid expenses and other current assets 517,482 389,048 ------------ ------------ Total current assets 5,924,015 3,314,402 ------------ ------------ Property and equipment: Oil and gas properties, full cost method of accounting: Properties subject to amortization 11,849,520 5,490,447 Properties not subject to amortization 3,513,597 3,548,812 Other property and equipment 147,047 69,136 ------------ ------------ Total 15,510,164 9,108,395 Less accumulated depreciation, depletion and amortization (1,966,000) (2,164,936) ------------ ------------ Total property and equipment, net 13,544,164 6,943,459 Prepaid oil and gas costs 81,603 82,280 Other assets 66,462 65,901 ------------ ------------ Total assets $19,616,244 $10,406,042 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY ------------------------------------ Current liabilities: Current portion of long-term debt $ 908,168 $ 2,890,000 Accounts payable 561,546 847,332 Accrued liabilities 750,036 1,338,641 ------------ ------------ Total current liabilities 2,219,750 5,075,973 ------------ ------------ Long-term debt, net of current portion 2,537,251 - Other long-term obligations 670,456 - Stockholders' equity: Preferred stock, par value $1.00 per share, 20,000,000 shares authorized: Series A 8% convertible preferred stock, 1,000,000 shares 483,416 483,416 authorized; 483,416 shares issued and outstanding Series B convertible preferred stock, 100,000 shares authorized; 43,000 43,000 43,000 shares issued and outstanding Common stock, par value $0.001 per share, 100,000,000 shares 28,497 18,792 Authorized; 28,497,761 and 18,792,120 shares issued and outstanding at December 31, 2005 and 2004, respectively Additional paid-in capital 18,089,828 6,884,784 Unissued common stock 545,000 - Accumulated deficit (5,000,954) (2,099,923) ------------ ------------ Total stockholders' equity 14,188,787 5,330,069 ------------ ------------ Total liabilities and stockholders' equity $19,616,244 $10,406,042 ============ ============
The accompanying notes are an integral part of these consolidated financial statements. F-2
PETROSEARCH ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004 2005 2004 ------------ ------------ Oil and gas production revenues $ 1,701,043 $ 4,718,313 ------------ ------------ Operating costs and expenses: Lease operating and production taxes 581,313 773,723 Depreciation, depletion and amortization 563,252 2,219,998 General and administrative 3,268,088 3,239,184 ------------ ------------ Total costs and expenses 4,412,653 6,232,905 ------------ ------------ Operating loss (2,711,610) (1,514,592) ------------ ------------ Other income (expense): Interest income 51,031 7,754 Interest expense (240,452) (64,282) ------------ ------------ Total other income (expense) (189,421) (56,528) ------------ ------------ Net loss $(2,901,031) $(1,571,120) ============ ============ Basic and diluted net loss per common share $ (0.11) $ (0.09) ============ ============ Weighted average common shares 25,409,348 17,576,294 ============ ============
The accompanying notes are an integral part of these consolidated financial statements. F-3
PETROSEARCH ENERGY CORPORATION CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004 SERIES A SERIES B SERIES C SERIES D COMMON STOCK PREFERRED STOCK PREFERRED STOCK PREFERRED STOCK PREFERRED STOCK SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT ----------- -------- ---------- ----------- -------- -------- ---------- --------- ---------- --------- Balance at December 31, 16,836,861 $16,837 1,000,000 $1,000,000 43,000 $ 43,000 75,000 $ 75,000 37,500 $ 37,500 2003 Common stock issued for cashless 85,537 86 - - - - - - - - exercise of warrants Common stock issued for 1,374,338 1,374 - - - - - - - - cash Common stock issued for 12,308 12 - - - - - - - - property costs Common stock issued for 16,923 17 - - - - - - - - services Issuance of committed stock 535,349 535 - - - - - - - - Collection of subscription - - - - - - - - - - receivable Reduction of subscription receivable in - - - - - - - - - - lieu of compensation Exchange of Series A preferred stock 79,474 79 (516,584) (516,584) - - - - - - for common stock Exchange of Series C preferred stock 34,615 35 - - - - (75,000) (75,000) - - for common stock Exchange of Series D preferred stock 23,077 23 - - - - - - (37,500) (37,500) for common stock Cancellation of common stock for payment of (206,362) (206) - - - - - - - - receivables Issuance of warrants for - - - - - - - - - - services Net loss - - - - - - - - - - ----------- -------- ---------- ----------- -------- -------- ---------- --------- ---------- --------- Balance at December 31 18,792,120 $18,792 483,416 $ 483,416 43,000 $ 43,000 - $ - - $ - 2004 =========== ======== ========== =========== ======== ======== ========== ========= ========== ========= TOTAL ADDITIONAL UNISSUED STOCK STOCK PAID-IN COMMON SUBSCRIPTIONS ACCUMULATED HOLDERS CAPITAL STOCK RECEIVABLE DEFICIT EQUITY ------------ ------------ --------------- ------------- ------------ Balance at December 31, $ 1,695,830 $ 2,618,076 $ (329,410) $ (528,803) $ 4,628,030 2003 Common stock issued for cashless (86) - - - - exercise of warrants Common stock issued for 1,852,106 - - - 1,853,480 cash Common stock issued for 51,908 - - - 51,920 property costs Common stock issued for 80,463 - - - 80,480 services Issuance of committed stock 2,617,541 (2,618,076) - - - Collection of subscription - - 35,000 - 35,000 receivable Reduction of subscription receivable in - - 45,000 - 45,000 lieu of compensation Exchange of Series A preferred stock 516,505 - - - - for common stock Exchange of Series C preferred stock 74,965 - - - - for common stock Exchange of Series D preferred stock 37,477 - - - - for common stock Cancellation of common stock for payment of (321,804) - 249,410 - (72,600) receivables Issuance of warrants for 279,879 - - - 279,879 services Net loss - - - (1,571,120) (1,571,120) ------------ ------------ --------------- ------------- ------------ Balance at December 31 $ 6,884,784 $ - $ - $ (2,099,923) $ 5,330,069 2004 ============ ============ =============== ============= ============
The accompanying notes are an integral part of these consolidated financial statements. F-4
PETROSEARCH ENERGY CORPORATION CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004 SERIES A SERIES B SERIES C SERIES D COMMON STOCK PREFERRED STOCK PREFERRED STOCK PREFERRED STOCK PREFERRED STOCK SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT ------------ ------- ------- -------- ------ ------- -------- --------- -------- -------- Balance at December 31, 18,792,1200 $18,792 483,416 $483,416 43,000 $43,000 - $ - - $ - 2004 Common Stock issued for cash 9,174,873 9,174 - - - - - - - - Common stock issued and committed for 500,000 500 - - - - - - - - oil and gas properties Compensation awarded to Board of 30,768 31 - - - - - - - - Directors Issuances of warrants with - - - - - - - - - - debt Cancellation of warrants - - - - - - - - - - Net loss - - - - - - - - - - ------------ ------- ------- -------- ------ ------- -------- --------- -------- -------- 28,497.761 $28,497 483,416 $483,416 43,000 $43,000 - $ - - $ - ============ ======= ======= ======== ====== ======= ======== ========= ======== ======== ADDITIONAL UNISSUED STOCK STOCK PAID-IN COMMON SUBSCRIPTIONS ACCUMULATED HOLDERS CAPITAL STOCK RECEIVABLE DEFICIT EQUITY ------------ ------------ ------------- ------------- ----------- Balance at December 31, $ 6,884,784 $ - $ - $ (2,099,923) $5,330,069 2004 Common Stock issued for cash 10,600,545 - - - 10,609,719 Common stock issued and committed for 544,500 545,000 - - 1,090,000 oil and gas properties Compensation awarded to Board of 59,969 - - - 60,000 Directors Issuances of warrants with 88,422 - - - 88,422 debt Cancellation of warrants (88,392) - - - (88,392) Net loss - - - (2,901,031) (2,901,031) ------------ ------------ ------------- ------------- ----------- $18,089,828 $ 545,000 $ - $ (5,000,954) $14,188,787 ============ ============ ============= ============= ===========
The accompanying notes are an integral part of these consolidated financial statements. F-5
PETROSEARCH ENERGY CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004 2005 2004 ------------ ------------ Cash flows from operating activities: Net loss $(2,901,031) $(1,571,120) Adjustments to reconcile net loss to net cash used in operating activities: Depletion, depreciation and amortization expense 563,252 2,219,998 Write off of prepaid oil and gas costs 60,000 32,219 Reduction in subscription receivable in lieu of compensation - 45,000 Common stock and warrants issued as compensation for services 60,000 360,359 Amortization of deferred rent 77 - Amortization of debt discount and financing costs 48,283 - Bad debt expense 145,443 Changes in operating assets and liabilities: Accounts receivable 368,664 (1,330,588) Related party receivable - (16,926) Prepaid expenses and other assets (235,055) (284,360) Accounts payable and accrued liabilities (599,672) 248,926 ------------ ------------ Net cash used in operating activities (2,490,039) (296,492) ------------ ------------ Cash flows from investing activities: Capital expenditures, including purchases and development of properties (7,815,083) (6,356,134) Purchase of prepaid credits for oil and gas properties, net (59,323) Proceeds from sale of overriding royalty interest - 100,000 Proceeds from sale of property 2,072,002 18,000 ------------ ------------ Net cash used in investing activities (5,802,404) (6,238,134) ------------ ------------ Cash flows from financing activities: Proceeds from the sale of common stock 10,609,719 1,853,480 Proceeds from collection of stock subscription receivable - 1,231,250 Proceeds from notes payable 3,950,000 3,100,000 Repayment of bonds payable (200,000) Repayment of notes payable (3,315,000) (210,000) ------------ ------------ Net cash provided by financing activities 11,244,719 5,774,730 ------------ ------------ Net increase (decrease) in cash and cash equivalents 2,952,276 (759,896) Cash and cash equivalents at beginning of year 1,100,568 1,860,464 ------------ ------------ Cash and cash equivalents at end of year $ 4,052,844 $ 1,100,568 ============ ============ Supplemental disclosures of cash flow information: Interest paid $ 227,192 $ 40,470 ============ ============ Income taxes paid $ - $ - ============ ============
The accompanying notes are an integral part of these consolidated financial statements. F-6 PETROSEARCH ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES ------------------------------------------------ ORGANIZATION ------------ Petrosearch Energy Corporation (the "Company"), a Nevada Corporation formed in November 2004, is an independent oil and gas company based in Houston, Texas, with a second office in Dallas, Texas. The Company is engaged in the exploration for and the acquisition, development and production of crude oil and natural gas. The Company has established production in North Dakota, Oklahoma and Texas and is currently engaged in exploration and development activities, including direct operator activities, through its subsidiary, Petrosearch Operating Company, L.L.C., in North Dakota, Louisiana, Texas, Oklahoma, and Mississippi. The Company identifies high quality prospects and projects and provides the capital, technical support and business resources needed to develop the projects. The Company also pursues ventures with other independent companies when targets of exceptional potential are available and considers acquisition of producing properties with additional development potential. The Company is the successor of Petrosearch Corporation ("Petrosearch Texas") which was formed in August 2003 in the state of Texas pursuant to a reverse merger agreement with Texas Commercial Resources, Inc. ("TCRI"). In November 2004, shareholders of Petrosearch Texas approved a 6.5-to-1 reverse stock split which took effect immediately prior to its merger with the Company on December 30, 2004 (the "Merger"). Upon completion of the Merger, shareholders of Petrosearch Texas were issued common shares of Petrosearch Energy Corporation representing 100% of the then issued and outstanding common shares. The consolidated financial statements presented herein include the accounts of the Company and its wholly-owned subsidiaries. All significant inter-company accounts and transactions have been eliminated. ACCOUNTING ESTIMATES -------------------- The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. These estimates primarily involve the useful lives of property and equipment, the impairment of unproved oil and gas properties, the valuation of deferred tax assets and the realization of accounts receivable. OIL AND GASPROPERTIES --------------------- The Company follows the full cost method of accounting for crude oil and natural gas properties. Under this method, all direct costs and certain directly related internal costs associated with acquisition of properties and successful, as well as unsuccessful, exploration and development activities are capitalized. Depreciation, depletion and amortization of capitalized crude oil and natural gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves. Net capitalized costs of crude oil and natural gas properties, as adjusted for asset retirement obligations, net of salvage value, are limited, by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10 percent, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. Excess costs are charged to proved property impairment expense. No gain or loss is recognized upon sale or disposition of crude oil and natural gas properties, except in unusual circumstances. F-7 The following table reflects the depletion expense incurred from oil and gas properties during the years ended December 31, 2005 and 2004:
2005 2004 -------- ---------- Depletion Expense $543,654 $2,207,949 ======== ========== Depletion expense per bbl produced $ 15.24 $ 16.83 ======== ==========
At December 31, 2005 and 2004, unproved oil and gas properties not subject to amortization included $3,513,597 and $3,548,812, respectively, of property acquisition, exploration and development costs that are not being amortized. These costs will begin to be amortized when they are evaluated and proved, reserves are discovered, impairment is indicated or when the lease terms expire. Unproved leasehold costs consist of interest in leases located in Mississippi, Oklahoma and Texas. The following table reflects the periods when costs were incurred for unproved oil and gas properties costs:
2004 2005 TOTAL ---------- ---------- ---------- Property acquisition costs $1,185,625 $1,678,257 $2,863,882 Exploration costs - 649,715 649,715 ---------------------------------- Total $1,185,625 $2,327,972 $3,513,597 ========== ========== ==========
Unproved properties represent costs associated with properties on which the Company is performing exploration activities or intends to commence such activities. These costs are reviewed periodically for possible impairments or reduction in value based on geological and geophysical data. If a reduction in value has occurred, costs being amortized are increased. OTHER PROPERTY AND EQUIPMENT ---------------------------- Property and equipment is stated at cost. Depreciation is computed using the straight-line method over the estimated useful lives of 3 to 5 years for office furniture and equipment and transportation and other equipment. Additions or improvements that increase the value or extend the life of an asset are capitalized. Expenditures for normal maintenance and repairs are expensed as incurred. Disposals are removed from the accounts at cost less accumulated depreciation and any gain or loss from disposition is reflected in operations. Depreciation expense for other property and equipment for the years ended December 31, 2005 and 2004 was $19,598 and $12,049, respectively. ASSET RETIREMENT OBLIGATIONS ---------------------------- Effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations ("SFAS 143"). This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. SFAS 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For oil and gas properties, this is the period in which an oil or gas well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of our oil and gas properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is reversed. Prior to 2005, the discounted fair value of the Company's expected future obligation was estimated to approximate salvage value, and, thus, no obligation was recorded. The estimated asset F-8 retirement obligation as of December 31, 2005, of $633,455 is attributable to property additions in 2005 and as been recognized as a long-term obligation in the accompanying balance sheet as of December 31, 2005. CASH AND CASH EQUIVALENTS ------------------------- For purposes of reporting cash flows, the Company considers all short-term investments with an original maturity of three months or less when purchased to be cash equivalents. RECEIVABLES ----------- The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectibility. Many of the Company's receivables are from joint interest owners on properties of which the Company is the operator. Thus, the Company may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company's crude oil and natural gas receivables are collected within two months. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2005 and 2004, the Company provided an allowance of $83,073 and $ -0- for doubtful accounts for trade receivables or joint interest owner receivables. FAIR VALUE OF FINANCIAL INSTRUMENTS --------------------------------------- The Company includes fair value information in the notes to financial statements when the fair value of its financial instruments is different from the book value. When the book value approximates fair value, no additional disclosure is made. The Company assumes the book value of those financial instruments that are classified as current approximates fair value because of the short maturity of these instruments. For non-current financial instruments, the Company uses quoted market prices or, to the extent that there are no available quoted market prices, market prices for similar instruments. RESTORATION, REMOVAL AND ENVIRONMENTAL LIABILITIES -------------------------------------------------- The Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliably determinable. As of December 31, 2005, the Company believes it has no such liabilities. CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS ------------------------------------------------ Financial instruments which subject the Company to concentrations of credit risk include cash and cash equivalents and accounts receivable. The Company maintains its cash and cash equivalents with major financial institutions selected based upon management's assessment of the banks' financial stability. Balances regularly exceed the $100,000 federal depository insurance limit. The Company has not experienced any losses on deposits. The Company performs ongoing credit evaluations and, generally, requires no collateral from its customers or other joint interest owners. As of December 31, 2005, 98% of accounts receivable from oil and gas sales was from one customer and 86% of accounts receivable from joint interest owners was from one joint interest owner. During the years ended December 31, 2005 and 2004, respectively, 98% and 100% of the Company's revenue was received from four and three customers as follows: F-9
2005 2004 ---------- ---------- Customer A $ 879,542 $3,114,087 Customer B 552,998 1,321,128 Customer C 172,540 283,098 Customer D 69,622 - Others 26,341 - ---------------------- Total $1,701,043 $4,718,313 ========== ==========
REVENUE RECOGNITION ------------------- The Company recognizes crude oil and natural gas revenue from its interest in producing wells as crude oil and natural gas is sold from those wells, net of royalties. EARNINGS (LOSS) PER SHARE ------------------------- The Company provides basic and dilutive earnings (loss) per common share information for each year presented. The basic net loss per common share is computed by dividing the net loss by the weighted average number of common shares outstanding. Diluted net loss per common share is computed by dividing the net loss, adjusted on an "as if converted" basis, by the weighted average number of common shares outstanding plus potential dilutive securities. For the years ended December 31, 2005 and 2004, potential dilutive securities, assuming the Company had net income, that had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share consisted of warrants for the purchase of 651,281 and 5,207,070 common shares, respectively, and convertible preferred stock convertible into 94,218 and 612,416 common shares, respectively. Per share calculations reflect the effects of the recapitalization and reverse stock split for all periods presented. STOCK BASED COMPENSATION ------------------------ SFAS No. 123, "Accounting for Stock-Based Compensation" established financial accounting and reporting standards for stock-based employee compensation plans. It defined a fair value based method of accounting for an employee stock option or similar equity instrument and encouraged all entities to adopt that method of accounting for all of their employee stock compensation plans and include the cost in the income statement as compensation expense. However, it also allows an entity to continue to measure compensation cost for those plans using the intrinsic value based method of accounting prescribed by Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to Employees". The Company accounts for compensation cost for stock option plans in accordance with APB Opinion No. 25. See "New Accounting Pronouncements" below for information regarding the Company's adoption of SFAS No. 123 (revised 2004), "Share-Based Payment" ("SFAS 123(R)") on January 1, 2006. CAPITALIZED INTEREST -------------------- The Company capitalizes interest ($46,630 in 2005 and $ -0- in 2004) on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. INCOME TAXES ------------ The Company uses the liability method in accounting for income taxes. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and income tax carrying amounts of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. A valuation allowance, if necessary, is provided against deferred tax assets, based upon management's F-10 assessment as to their realization. NEW ACCOUNTING PRONOUNCEMENTS ----------------------------- The following discussions provide information about new accounting pronouncements that have been issued by the FASB: In December 2004, the FASB issued SFAS 123(R), which is a revision of SFAS 123. SFAS 123(R) supersedes APB 25 and amends SFAS No. 95, "Statement of Cash Flows". Generally, the approach in SFAS 123(R) is similar to the approach described in SFAS 123. However, SFAS 123(R) will require all share-based payments to employees, including grants of employee stock options, to be recognized as stock-based compensation expense in the Company's Consolidated Statements of Operations based on their fair values. Proforma disclosure is no longer an alternative. SFAS 123(R) must be adopted no later than January 1, 2006 and permits public companies to adopt its requirements using one of two methods: - A "modified prospective" method in which compensation cost is recognized beginning with the effective date based on the requirements of SFAS 123(R) for all share-based payments granted after the adoption date and based on the requirements of SFAS 123 for all awards granted to employees prior to the effective date of SFAS 123(R) that remain unvested on the adoption date. - A "modified retrospective" method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS 123 for purposes of proforma disclosures. The Company adopted the provisions of SFAS 123(R) on January 1, 2006 using the modified prospective method. As permitted by SFAS 123, the Company accounted for share-based payments to employees prior to January 1, 2006 using the intrinsic value method prescribed by APB 25 and related interpretations. As such, the Company generally did not recognize compensation expense associated with employee stock option grants. Currently, the Company has no plans to issue stock warrants to any parties other than in financing arrangements with third parties. Consequently, based on current plans, the adoption of SFAS 123(R)'s fair value method will not have a significant impact on the Company's future results of operations or financial position. Had the Company adopted SFAS 123(R) in prior periods, the impact would have approximated the impact of SFAS 123 as described in the proforma disclosures. The adoption of SFAS 123(R) will not result in any compensation charges in 2006 related to options outstanding at December 31, 2005, because all employee stock options were vested as of December 31, 2005. SFAS 123(R) also requires that tax benefits in excess of recognized compensation expenses be reported as a financing cash flow, rather than an operating cash flow as required under prior literature. This requirement may serve to reduce the Company's future cash flows from operating activities and increase future cash flows from financing activities, to the extent of associated tax benefits that may be realized in the future. In June 2005, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 154, "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3". This Statement provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. This Statement also provides guidance for determining whether retrospective application of a change in accounting principle is impracticable and for reporting a change when retrospective application is F-11 impracticable. The correction of an error in previously issued financial statements is not an accounting change. However, the reporting of an error correction involves adjustments to previously issued financial statements similar to those generally applicable to reporting an accounting change retrospectively. Therefore, the reporting of a correction of an error by restating previously issued financial statements is also addressed by this Statement. This Statement shall be effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. At this time, the Company has no plans to adopt a change in accounting principle; however, this guidance could have a significant impact on the Company in the event that an accounting change is made in the future. In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) 47, "Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143". This interpretation clarifies that the term, conditional asset retirement obligation, as used in FASB Statement No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred, generally upon acquisition, construction, or development and/or through the normal operation of the asset. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. SFAS No. 143 acknowledges that, in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. We do not expect this guidance to have a significant impact on the Company. 2. SALE OF OIL AND GAS PROPERTIES ------------------------------ Effective July 1, 2005, the Company's wholly owned subsidiary, TK Petrosearch, L.L.C., sold its interest in the Blue Ridge Salt Dome Field for $2,072,002 to the individual who has managed the TK PetroSearch, LLC subsidiary. The assets sold accounted for $1,370,110 of the Company's PV-10 of proved reserves as of December 31, 2004, or approximately 10% of the Company's total PV-10 value. The property had an estimated remaining 68,700 barrels of proved oil reserves at the time of the sale. The transaction has been reflected in the accompanying financial statements as a reduction of capitalized oil and gas properties as required by accounting principles generally accepted in the United States of America. The following represents the unaudited proforma effect on the consolidated statement of operations for the year ended December 31, 2005 as if the transaction occurred on January 1, 2005. The sale represents $30.16 per barrel of oil of the proved reserves sold.
PROFORMA PROFORMA AS REPORTED ADJUSTMENTS (UNAUDITED) ------------- ------------- ------------- Oil and gas production revenues $ 1,701,043 $ (552,998) $ 1,148,045 Costs and expenses 4,412,653 359,162 4,053,491 ------------- ------------- ------------- Operating loss (2,711,610) (193,836) (2,905,446) Other expenses (189,421) - (189,421) ------------- ------------- ------------- Net loss $ (2,901,031) $ (193,836) $( 3,094,867) ============= ============= ============= Basic and diluted net loss per common share $ (0.11) $ (0.01) $ (0.12) ============= ============= =============
F-12 3. PURCHASE OF OIL AND GAS PROPERTIES ---------------------------------- Effective September 28, 2005, the Company purchased an additional 21.25% working interest in the Gruman #18-1 Well and Gruman Leases for $637,500, increasing the Company's working interest in the properties to 85%. As of the time of the closing, the purchase provided additional PV-10 value of approximately $3,500,000 (based upon independent engineering report as of July 1, 2005), made up of additional proved reserves of 89,755 barrels of oil and 25,672 MCF of gas. The purchase price represents $6.67 per barrel of oil equivalent of the proved reserves purchased. Effective November 15, 2005, the Company entered into an agreement to purchase a 100% working interest in 1780 acres of leases in the Quinduno Field located in Roberts County, Texas from Quinduno Energy, L.L.C. The agreement provides for the payment of the purchase price of $2,000,000 cash and 3,000,000 shares of unregistered common shares of the Company to occur in three phases as the project progresses. Should the project not proceed past the first phase, Petrosearch's maximum obligation would be $750,000 in cash and 1,000,000 unregistered common shares plus the cost of capital expenditures for the first phase which are estimated to be $2,900,000. Upon completion of the entire project, the seller will back in for a 10% working interest after Petrosearch has been repaid all capital expenditure costs plus $9.5 million. Based on the valuation of the acquisition of $9.5 million on November 15, 2005, this purchase represents $3.37 per barrel of oil equivalent of the proved reserves purchased. At any time after completion of the first phase of the project, should the Company, in the Company's sole discretion, determine to terminate further operations, then the Company must offer Quinduno the Company's interest in the leases for a purchase price equal to an internal rate of return to the Company of twenty-two and one half percent (22.5%), calculated monthly, using the closing date under the Agreement as the commencement date and, taking into account all acquisition cash, all capital expenditures, plus a sum of $7,500,000 and the net income received from the project. Quinduno will have 45 days to exercise its right of refusal to repurchase the leases, at which time, upon Quinduno's refusal to repurchase, the Company may sell the Company's interest in the leases to a third party. 4. PREPAID EXPENSES AND OTHER CURRENT ASSETS ----------------------------------------- Prepaid expenses and other current assets consist of the following at December 31, 2005 and 2004:
2005 2004 ----------- ---------- Prepaid expenses $ 152,386 $ 90,207 Note receivable - 110,000 Prepaid bonds 277,000 177,000 Current portion of financing costs 42,890 - Other receivables 45,206 - Other assets - 11,841 ----------------------- $ 517,482 $ 389,048 =========== ==========
F-13 5. ACCRUED LIABILITIES ------------------- Accrued liabilities consist of the following at December 31, 2005 and 2004:
2005 2004 -------- ---------- Revenue payable and operated prepayment liability $ 21,297 $ 139,270 Accrued interest payable 36,794 25,187 Accrued liabilities for capital additions 500,000 1,017,058 Accrued liability for Professional Fees 50,000 - Other accrued expenses 141,945 157,126 -------------------- $750,036 $1,338,641 ======== ==========
6. REVOLVING CREDIT AGREEMENT -------------------------- On October 1, 2004, the Company entered into a revolving credit agreement to borrow up to $18,000,000 over a one-year period from a company whose managing partner is a shareholder of the Company. Draws under the agreement were subject to limits after the initial draw at a maximum rate of $4,500,000 for each three-month period following the initial draw date with undrawn funds to be carried forward to the succeeding draw period. Draws were also limited based on the Company's actual cost of oil and gas leases and the amount of the Company's proved producing reserves. Advances under the revolving credit agreement bear interest at a rate of six percent (6%) per year which was payable each quarter, and were collateralized by the Company's oil and gas properties. The agreement stipulates that, after 60 days of each particular draw, the Company repay the outstanding principal in monthly installments equal to 10% of the original amount of the particular draw and continue on the same calendar date of each succeeding month thereafter. The outstanding principal and interest balance matures two years from the date of the initial draw, which is October 2006. The Company was assessed a one quarter of one percent (0.25%) standby fee on available undrawn principal each quarter. As additional consideration for this agreement, the Company assigned the lender a one percent (1%) overriding royalty interest in certain producing wells in Oklahoma and Texas and a commitment to provide a one percent (1%) overriding royalty interest in all future leases acquired using funds from this agreement. Per the agreement, this overriding royalty interest is earned by the lender upon funding and is not subject to revision or reassignment upon repayment or termination of the loan. As a result, the Company capitalized the net present value of this overriding royalty interest of $24,825, plus additional loan costs of $38,743, as deferred loan cost in the consolidated balance sheet as of December 31, 2004. These loan costs were being amortized into interest expense over the two-year life of the agreement. On September 29, 2005, the Company entered into an amended and restated revolving credit agreement to borrow up to $10,000,000 over a two-year period to October 1, 2007, from a private, non-public entity. The outstanding loan balance under the original revolving credit agreement dated October 1, 2004, of $825,000 and accrued interest through the date of the amended agreement, were deemed to be principal and interest outstanding under the amended and restated revolving credit agreement. Proceeds of the credit line are to be used to finance activity related to eight new prospects including costs associated with acquisitions of oil and gas leases, oil and gas drilling, reworking, production, transportation, marketing and plugging activities under the leases, and all lender charges and fees. Advances under the amended and restated revolving credit agreement bear interest at a rate of the Wall Street Journal Prime Rate plus three percent (3%) per year. Each advance of principal under the amended facility is treated as a separate loan and is repayable in six (6) interest only installments followed by up to twenty four (24) principal and interest installments based upon a 30-month amortization. The Company will be assessed a one quarter of one percent (.25%) standby fee on available undrawn principal each quarter. The note matures on April 1, 2008. As of December 31, 2005, the balance outstanding under the line of credit agreement was $3,525,000, $940,000 of which is due in the next twelve months, $1,410,000 of which is due in F-14 2007, and $1,175,000 of which is due in 2008. The loan is collateralized by a first lien on the particular oil and gas leases acquired with the funds, but the Company is entitled to obtain partial releases if the ratio of proved developed and proved undeveloped reserves underlying the collateral base meets certain criteria. According to the terms of the agreement, the unused available funds under the line of credit will only be available for draw by the Company if at all times the Company's proved developed reserves equal or exceed twenty-five percent (25%) of the outstanding principal and interest indebtedness under the agreement and if the principal balance of the note outstanding after the requested draw is less than the sum of 1) the actual costs of the oil and gas lease purchased and or funded, and 2) the sum of 75% of the Company's proved developed reserves and 50% of the Company's proved undeveloped reserves from all sources pledged as collateral. Because the lender obtains its funds from the private capital markets and or individuals who desire to participate in the lenders investment bank activities, the lender does not have a guaranteed source of money in which to fund this transaction with the Company. As a result, the lender has not guaranteed that all proposed funding under this agreement will be available if and when the Company elects to make draw requests. As consideration for entering into the agreement, the lender will receive an overriding royalty in each oil and gas lease acquired with facility funds equal to 2% of the Company's acquired net revenue interest in the lease. The overriding royalty interests are earned when the lender funds have been utilized by the Company for direct and or indirect acquisition expenses or drilling expenses. In addition, the lender received 100,000 warrants to purchase common stock of the Company at an exercise price of $2.00 per share and an expiration date of November 1, 2007. Under the terms of the credit facility, the Company is required to offer to the lender the opportunity to participate in up to a minimum of 33.3% and up to 100% based on the sole discretion of the Company. The Company allocates the proceeds received from debt with detachable warrants using the relative fair value of the individual elements at the time of issuance. The amount allocated to the warrants as a debt discount was calculated at $88,422 and was $79,581 at December 31, 2005. The debt discount is recognized as interest expense over the period until the notes mature. In the event the debt is settled prior to the maturity date, an expense will be recognized based on the difference between the carrying amount and the amount of the payment. 7. INCOME TAXES ------------ Through December 31, 2005, the Company has incurred losses since its inception and, therefore, has not been subject to federal income taxes. As of December 31, 2005, the Company had net operating loss ("NOL") carryforwards for income tax purposes of approximately $11,400,000 which expire in various tax years through 2025. Under the provisions of Section 382 of the Internal Revenue Code, the ownership change in the Company that resulted from the recapitalization of the Company could limit the Company's ability to utilize its NOL carryforward to reduce future taxable income and related tax liabilities. Additionally, because United States tax laws limit the time during which NOL carryforwards may be applied against future taxable income, the Company may be unable to take full advantage of its NOL for federal income tax purposes should the Company generate taxable income. The composition of deferred tax assets and the related tax effects at December 31, 2005 and 2004 are as follows: F-15
2005 2004 ------------ ---------- Deferred tax assets: Net operating loss carry-forward $ 3,874,325 $1,327,265 Allowance for doubtful accounts 42,868 - Contribution carryover 2,346 2,346 ------------------------ Total deferred tax assets 3,919,539 1,329,611 Less valuation allowance (1,628,636) (647,632) ------------------------ Net deferred tax asset 2,290,903 681,979 ------------------------ Deferred tax liabilities: Book/tax basis difference in oil and gas properties (2,277,366) (671,268) Book/tax basis difference in property and equipment (13,537) (10,711) ------------------------ Total deferred tax liability (2,290,903) (681,979) ------------------------ Net deferred tax $ - $ - ============ ==========
The difference between the income tax benefit in the accompanying statement of operations and the amount that would result if the U.S. Federal statutory rate of 34% were applied to pre-tax loss for the years ended December 31, 2005 and 2004 is as follows:
2005 2004 AMOUNT % AMOUNT % ---------- ------- ---------- ------- Benefit for income tax at federal $(986,351) (34.0)% $(534,180) (34.0)% statutory rate Non-deductible expenses 5,347 0.0 159,654 10.1 Increase in valuation allowance 981,004 28.0 374,526 23.9 ---------------------------------------- $ - -% $ - -% ========== ======= ========== =======
8. RIGHT OF FIRST REFUSAL AGREEMENT -------------------------------- Effective December 30, 2005, Petrosearch Energy Corporation, joined by six of its subsidiaries, entered into an Agreement with Rock Energy Partners Operating, L.P. and Rock Energy Partners, L.P. (collectively referred to herein as "Rock"). The Agreement generally covers the geographic areas of current operations in Jefferson County, Mississippi and Colorado County, Texas affecting the Company and Rock, including agreements and stipulations regarding future operations in those geographic areas, the terms under which future exploration and development participation opportunities will be offered by the Company to Rock, and agreed procedures for conducting internal audits and accounting reconciliations. As part of the transaction with Rock, the parties have executed an Amended Right of First Refusal Agreement (the "Amended ROFR") which replaces the previous Right of First Refusal Agreement between the Company and Rock which was entered in March 2004 (the "ROFR"). The Amended ROFR has more limited applicability to the Company's various projects than the ROFR. While the original agreement required all Company prospects to be presented to Rock for consideration by Rock, the Amended ROFR does not require that all Company prospects be offered to Rock for participation. The Amended ROFR also does not require that the Company offer to Rock prospects in any specified area, although the parties have separately stipulated to certain specified areas of mutual interest in the Mississippi and Colorado County areas based upon historical operations in those areas. The Amended ROFR permits the Company to decide which projects will be offered to Rock, so long as the projects actually presented are projects in which the Company owns or intends to retain a minimum of ten percent (10%) of the project interest available to the Company. F-16 Under the Amended ROFR, Rock's percentage participation is limited to the range between ten percent (10%) minimum participation and forty percent (40%) maximum participation, while the ROFR permitted Rock to take up to 100% of a prospect, if desired. All of the above participation interests are fractions of the interest available to the Company. The Amended ROFR also calls for a minimum funding commitment required from Rock equal to $3,000,000 per year, without the right to carry over to any subsequent year as a credit excess expenditures above the minimum required commitment for that year. The term of the Amended ROFR will automatically renew from December 31 of a given year to December 31 of the following year: 1) if Rock meets its funding minimum in a calendar year, 2) if the funding minimum is not met, but the Company otherwise has failed to offer a sufficient number of projects to Rock such that theoretical participation by Rock in one-half of the offered prospects to the extent of twenty five percent (25%) would have resulted in Rock achieving the funding minimum; or 3) if more than one-half of the prospects offered to Rock are offered during October, November or December of a calendar year. The Amended ROFR provides that the reversionary interest to be retained by the Company in each prospect which is accepted by Rock shall be a twenty-five percent (25%) reversionary interest in each interest assigned to Rock, with the reversion to take effect upon "payout" or recoupment of Rock's development costs net to that interest. Under the Amended ROFR, if the particular prospect is a drilling project without existing oil and gas production, then payout will be computed on a well-by-well basis. However, if the prospect includes existing oil and gas production acquired by the parties, then payout will be computed on a prospect-wide basis, inclusive of drilling costs expended after acquisition on reworked and new wells. Under the Amended ROFR, the Company has agreed to reduce its after payout reversionary interest in an accepted project in the event the Company gives better after-payout terms to a third party in the same prospect, thereby providing Rock the same benefits of the terms offered to any such third party. The Company's Jefferson County, Mississippi operations have, to date, been conducted by the Company's operating subsidiary, Petrosearch Operating Company, L.L.C. ("POC"). Prior to this transaction, one hundred percent (100%) of the applicable oil and gas leases on which drilling of the Phillips-Burkley No. 1 well have occurred were assigned to Rock subject to a reversionary interest retained and owned by the Company's subsidiary, Buena Vista Petrosearch, L.L.C. ("BVPS"), which was to take effect when Rock recouped 100% of its development costs. As part of the transaction, the Company may fund all exploration costs of the Phillips-Burkley No. 1 well going forward pursuant to a new operating agreement between POC and BVPS. Further, as part of the transaction, Rock will be assigned a 50% net revenue interest in the BVPS once the company has recouped its investment in the subsidiary. Rock will retain its ownership of the gas pipeline associated with the project but will grant us the right to transport gas through the pipeline at the rate of ten cents per Mcf through December 31, 2006 and five cents per Mcf thereafter. Rock has executed a promissory note in favor of the Company in the principal amount of $825,449 to repay the outstanding acquisition and development costs of the project which accrued prior to September 30, 2005. The balance of this note has been included in accounts receivable-joint owners as of December 31, 2005. This note bears interest at the rate of 6% and is payable in four equal monthly installments expected to begin June 1, 2006. The sharing of production proceeds, if any, derived from the Phillips-Burkley No. 1 well will be staged. Beginning with the effective date of the agreement until the Company recoups from production all sums paid by the Company toward Phillips-Burkley #1 operations after September 30, 2005 (the "Stage 1 Payout"), the Company will retain all of the net profits, if any, as a production payment. After the Stage 1 Payout event occurs, the Company and Rock shall share equally in the production payment. At such time during this sharing period, the Company and Rock will each receive $3,905,505 (the "Stage 2 Payout"). Subsequent to the Stage 2 Payout, certain persons vested with a collective 20% reversionary interest in BVPS (one of whom is the Company's chief operating officer who owns a 5% reversionary interest) will be entitled to receive their limited liability company interest which will decrease the collective interests of the Company and Rock in BVPS to 80% of profits from leasehold revenues. At the point of the Stage 2 Payout, Rock's 40% interest as the owner of one-half of BVPS shall be F-17 assigned to it by BVPS, thereby eliminating Rock's interest in BVPS in favor of a direct working interest ownership. However, Rock has the right to waive this automatic conversion to direct ownership after Stage 2 Payout if it desires. As part of the transaction, if either the Company or Rock acquires an oil and gas lease within the area of mutual interest designated by the parties, then the acquiring party shall offer to the other the right to acquire at cost a 50% interest in the acquired oil and gas lease within the Mississippi AMI leases. Under the prior agreements between the parties, one hundred percent (100%) of the Colorado County "Garwood" Prospect was assigned by the Company to Rock subject to a reversionary interest retained and owned by Pursuit Petrosearch, L.L.C. ("Pursuit"), the Company's subsidiary, which was to take effect when Rock recouped 100% of its development costs on a well-by-well basis. As in the case of the Jefferson County, Mississippi operations, the operator for the "Garwood" Prospect to date has been POC. Under the terms of the transaction, the parties have divided this geographic region into three (3) parts, the Garwood North Leases, the Garwood South Leases and the Garwood Area of Mutual Interest or "AMI" Leases. As to the Garwood North area, POC will remain the operator. As to the Garwood South and Garwood AMI Leases, Rock will be the operator. However, Rock has engaged POC as a contract operator for a term which is yet to be determined in order to take advantage of POC's existing regulatory registrations and bonding status. The ROFR provided for a reversionary interest equal to thirty-three and one-third percent (33.33%) of the interest assigned to Rock which interest would take effect upon Rock recouping 100% of its acquisition and development costs. Under the terms of the transaction, the Company's after payout reversionary interest has been adjusted to 21.5% as to Garwood South Leases and will be computed on a the well-by-well basis. The Company's after payout reversionary interest will remain 33.33% as to the wells drilled on Garwood North Leases, likewise on a well-by-well basis. For purposes of calculating "payout", the parties have stipulated to certain existing balances outstanding which are owed by Rock to the Company, subject to completion of an audit. These sums will be applied as payout calculation deficits in the payout formulae as more fully described in the transaction documents. Rock agreed to expend net to its interests during calendar year 2006 not less than $8,000,000 toward development of the Garwood North and Garwood South leases. The parties contemplate that this commitment will be met by Rock's participation in two projects contemplated in 2006, being a new well in the Garwood North area and a recompletion of an existing wellbore known as the Kallina #2 well. The timing of the 2006 projects will not be overlapped so that costs may be closely monitored. Rock is not obligated to commit to operations exceeding $8,800,000, should the proposed projects exceed $8,000,000 in the aggregate. For five (5) years from the date of the Agreement, the Company and Rock have agreed that as to oil and gas leases in the Garwood prospect, which one or the other has acquired prior to consummation of the Agreement which are neither in the Garwood North nor Garwood South area, the party which has acquired the particular lease shall offer the other the right to acquire percentage ownership in the lease, being 80% if the offer is made to Rock and 20% if the offer is made to the Company. 9. COMMITMENTS AND CONTINGENCIES ----------------------------- OPERATING LEASE --------------- The Company rents office space under long-term office leases that expire through 2010. The future minimum lease payments required under the operating leases that have initial non-cancelable lease terms in excess of one year amount to $493,077 of which $94,196 is to be paid in 2006, $96,234 is to be paid in 2007, $99,989 is to be paid in 2008, $101,888 is to be paid in 2009, and $100,770 is to be paid in 2010. Rent expense incurred under operating leases during the years ended December 31, 2005 and 2004 was $101,321 and $85,172, respectively. LEGAL PROCEEDINGS ----------------- We are currently not a party to any material legal proceedings. F-18 10. STOCKHOLDERS' EQUITY -------------------- COMMON STOCK ------------- Effective April 23, 2004, the Company amended its articles of incorporation to increase the total number of shares of stock that the Company has the authority to issue to 1,020,000,000, consisting of 1,000,000,000 shares of common stock, par value $.001 per share, and 20,000,000 shares of preferred stock, par value $1.00 per share. Upon the merger on December 30, 2004, the Company's authorized shares of common stock decreased to 100,000,000 from 1,000,000,000. The authorized preferred stock of 20,000,000 remained the same. PREFERRED STOCK --------------- The Company's articles of incorporation authorize the issuance of up to 20,000,000 shares of preferred stock with characteristics determined by the Company's board of directors. As a result of the recapitalization of the Company in 2003, effective November 5, 2003, the Company had 1,000,000 shares of Series A 8% Convertible Preferred Stock ("Series A Preferred") authorized, issued and outstanding as of December 31, 2003. The shares have a par and stated value of $1.00 per share. If declared by the Board of Directors, dividends are to be paid quarterly in cash or in common stock of the Company to the holders of shares of the Series A Preferred. The shares of the Series A Preferred rank senior to the common stock both in payment of dividends and liquidation preference. The Series A Preferred is convertible into common stock of the Company at a conversion price of $6.50 per share (post-reverse split). Beginning August 19, 2003, the Company had the right to redeem all or part of the shares of Series A Preferred for cash at a redemption price equal to $6.50 per share plus all accrued and unpaid dividends on the shares to be redeemed. During 2004, 516,584 shares of Series A Preferred were converted to 79,474 shares of the Company's common stock. As of December 31, 2005, no dividends have been declared and approximately $131,000 of dividends were in arrears related to the Series A Preferred if the Company decided to declare dividends. As a result of the recapitalization of the Company, effective November 5, 2003, the Company has 100,000 shares authorized and 43,000 shares issued and outstanding of Series B Convertible Preferred Stock ("Series B Preferred") as of December 31, 2005 and 2004. The shares have a par and stated value of $1.00 per share. The shares of the Series B Preferred rank senior to the common stock in liquidation preference. The Series B Preferred is convertible into common stock of the Company at an initial conversion price of $2.14 per share (post-reverse split) at the option of the holder. Beginning October 1, 2003, the Company had the right to redeem all or part of the shares of Series B Preferred for cash at a redemption price equal to $6.50 per share. As a result of the recapitalization of the Company, effective November 5, 2003, the Company had 100,000 shares authorized and 75,000 shares issued and outstanding of Series C Convertible Preferred Stock ("Series C Preferred") as of December 31, 2003. The shares had a par and stated value of $1.00 per share. The shares of the Series C Preferred ranked senior to the common stock in liquidation preference. The Series C Preferred was convertible into common stock of the Company at an initial conversion price of $2.14 per share (post-reverse split) at the option of the holder. Beginning December 13, 2003, the Company had the right to redeem all or part of the shares of Series C Preferred for cash at a redemption price equal to the stated value of $1.00 per share. During 2004 all 75,000 shares of Series C Preferred were converted to 34,615 shares (post-reverse split) of the Company's common stock. As a result of the recapitalization of the Company, effective November 5, 2003, the Company had 600,000 shares authorized and 37,500 shares issued and outstanding of Series D 8% Convertible Preferred Stock ("Series D Preferred") as of December 31, 2003. The shares had a par and stated value of $1.00 per share. If declared by the Board of Directors, dividends were to be paid quarterly in cash or in common stock of the Company to the holders of shares of the Series D Preferred. The shares of the Series D Preferred ranked senior to the common stock both in payment of dividends F-19 and liquidation preference. The Series D Preferred was convertible into common stock of the Company at a conversion price of $1.62 per share (post-reverse split) at the option of the holder. Beginning March 10, 2004, the Company had the right to redeem all or part of the shares of Series D Preferred for cash at a redemption price equal to the stated value of $1.00 per share plus all accrued and unpaid dividends on the shares to be redeemed. During 2004 all 37,500 Series D Preferred were converted to 23,077 shares (post-reverse split) of the Company's common stock. STOCK WARRANTS -------------- The Company periodically issues incentive stock warrants to executives, officers, directors and employees to provide additional incentives to promote the success of the Company's business and to enhance the ability to attract and retain the services of qualified persons. The issuance of such warrants are approved by the Board of Directors. The exercise price of a warrant granted is determined by the fair market value of the stock on the date of grant. For purposes of determining compensation expense associated with stock warrants, the intrinsic value of the Company's stock was determined based upon the quoted market price of the Company's common stock for executives, officers and directors and fair value of the Company's stock was determined based upon the Black-Scholes option pricing model for non-employees. During 2004, the Company granted warrants to purchase 973,082 shares of common stock (post-reverse split) at prices ranging from $5.20 per share to $9.75 per share. All warrants were granted at an exercise price equal to or greater than the fair market value at the date of grant and, thus, no compensation cost was recorded. All of these warrants are immediately exercisable except for 115,384 that vest one year from the date of grant. These warrants expire in 2007. During November 2004, the Company, prior to its merger with Petrosearch Texas, entered into a two-year employment agreement with its new chief executive officer ("CEO") for which the CEO was granted warrants to purchase 3,637,738 shares of the Company's common stock at $1.95 per share, which was the fair market value of the common stock at the date of grant and, thus, no compensation cost was recorded. The warrants expire four years from the date of grant. During 2004, the Company granted warrants to purchase 76,923 shares of common stock at a price range of $5.20 to $9.75 per share to certain of its advisory board members. These warrants were exercisable immediately and expire three years from the date of grant. Using the Black Scholes Option Pricing Model, the issuance of the warrants resulted in $279,879 of additional compensation expense included in the accompanying statement of operations for the year ended December 31, 2004. The Company no longer has an advisory board. During 2005, the Company granted warrants to purchase 1,215,000 shares of common stock of the Company to board of directors and employees for services performed during 2005. The warrants expire in 2008 and have an exercise price of $1.95, which exceeded the fair market value of the common stock at the date of grant and, thus, no compensation cost was recorded. In September, 2005, the Company granted warrants to purchase 100,000 shares of common stock of the Company with an exercise price of $2.00 and an expiration date in 2007 to a lender for financing costs associated with the Company's amended credit facility with the lender (Note 6). The value allocated to the warrants as a debt discount was $88,422. During December, 2005, the Company extended the expiration date of warrants held by an officer of the Company to purchase 92,308 shares of common stock of the Company at an exercise price of $0.98 per share from August 28, 2006, to November 15, 2008. During 2005, the Company cancelled warrants to purchase 153,847 shares of common stock of the Company valued at $88,392 to reduce a note receivable from a former officer of the Company. Until the Company's adoption of the provisions of SFAS 123(R) on January 1, 2006 (See Note 1), the Company elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25) and related Interpretations in accounting for its employee stock F-20 warrants because, as discussed below, the alternative fair value accounting provided for under FASB Statement No. 123, "Accounting for Stock-Based Compensation", requires use of option valuation models that were not developed for use in valuing employee stock options/warrants. Under APB 25, if the exercise price of the Company's employee stock options is greater than or equal to the market price of the underlying stock on the date of grant, no compensation expense is recognized. Proforma information regarding net income (loss) and earnings (loss) per share is required by Statements 123 and 148, and has been determined as if the Company had accounted for its employee stock warrants under the fair value method of these Statements. For warrants granted during the years ended December 31, 2005 and 2004, the fair value for such warrants was estimated at the date of grant using a Black-Scholes option-pricing model with the following assumptions:
2005 2004 ---------- ---------- Dividend yield -0- -0- Expected volatility 70% 135% Risk free interest 3.00% 2.25% Expected lives 2-4 years 3-4 years
The Black-Scholes option valuation model was developed for use in estimating fair value of traded options or warrants that have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock warrants have characteristics significantly different from those of traded options/warrants, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock warrants. For purposes of proforma disclosures, the estimated fair value of the warrants is included in expense over the vesting period or expected life of the warrant.
2005 2004 ------------ ------------ Net loss as reported $(2,901,031) $(1,571,120) Add: Stock-based employee compensation expense - - included in reported net loss, net of tax Deduct: Stock-based employee compensation expense (833,855) (6,619,962) determined under the fair value method, net of tax ------------ ------------ Proforma net loss $(3,734,886) $(8,191,082) ============ ============ Basic and diluted net loss per common share, as reported $ (0.11) $ (0.09) ============ ============ Proforma basic and diluted net loss per common share $ (0.15) $ (0.47) ============ ============
No tax effects were included in the determination of proforma net loss because the deferred tax asset resulting from stock-based employee compensation would be offset by an additional valuation allowance for deferred tax assets. A summary of the Company's stock warrant activity (reverse split adjusted) and related information F-21 for the years ended December 31, 2005 and 2004 follows:
WEIGHTED NUMBER OF AVERAGE SHARES UNDER EXERCISE EXERCISE WARRANT PRICE PRICE ------------- ----------- --------- Balance outstanding at December 31, 2003 2,761,539 $0.98-$9.75 $ 4.62 Issued 1,050,000 $4.88-$9.75 $ 4.62 Effect of merger 3,637,738 $ 1.95 $ 1.95 Exercised (115,385) $ 2.60 $ 2.60 ------------- Balance outstanding at December 31, 2004 7,333,892 $0.98-$9.75 $ 3.77 Issued 1,407,308 $0.98-$2.00 $ 1.89 Cancelled (246,155) $ 0.98 $ 0.98 ------------- Balance outstanding at December 31, 2005 8,495,045 $0.98-$9.75 $ 3.57 =============
All outstanding stock warrants are exercisable at December 31, 2005. A summary of outstanding stock warrants at December 31, 2005 follows:
WEIGHTED NUMBER OF REMAINING AVERAGE COMMON STOCK CONTRACTED EXERCISE EXERCISE EQUIVALENTS EXPIRATION DATE LIFE (YEARS) PRICE PRICE ------------ --------------- ------------ ----------- --------- 630,769 August 2006 .67 $0.98 $0.98 692,308 September 2006 .68 $1.63 $1.63 1,076,923 November 2006 .92 $9.75 $9.75 211,538 February 2007 1.17 $9.75 $9.75 30,769 March 2007 1.25 $9.75 $9.75 300,000 April 2007 1.34 $9.75 $9.75 161,538 May 2007 1.42 $6.50-$9.75 $7.27 76,923 July 2007 1.50 $5.20-$6.50 $6.24 269,231 September 2007 1.67 $4.88-$5.20 $5.15 100,000 November 2007 1.92 $2.00 $2.00 150,000 March 2008 2.25 $1.95 $1.95 20,000 August 2008 2.62 $1.95 $1.95 4,775,046 November 2008 2.92 $1.95 $1.93 ----------------- 8,945,045 =================
11. RELATED PARTY TRANSACTIONS -------------------------- During the years ended December 31, 2005 and 2004, the Company was engaged in various transactions with related parties as follows: During the years ended December 31, 2005 and 2004, a vendor owned by the spouse of a director of the Company through December 8, 2005, at which time he resigned as director, provided drilling services totaling $485,570 and $280,457, respectively. The balance owed to this vendor was $-0- and $45,705 at December 31, 2005 and 2004, respectively. The director's spouse was also a 15 - 30% working interest owner in the Fort Bend County Prospect (Blue Ridge) which the Company sold in 2005. Accounts receivable from the spouse for joint interest billings was $-0- and $268,973 as of December 31, 2005 and 2004, respectively. F-22 Mr. Wayne Beninger, who became the Company's Chief Operating Officer on May 16, 2005, is the owner of Southwest Oil & Gas Management (Southwest) which has provided engineering and geological consulting services for the Company's projects. During the fiscal year ended December 31, 2004, the Company paid Southwest approximately $600,000 for such services. When Mr. Beninger became an employee of the Company, the agreement with Southwest was terminated. From January 1, 2005, until the agreement was terminated on May 15, 2005, the Company paid Southwest approximately $365,000 for engineering and geological consulting services. Mr. Beninger has an option to purchase for $1.00 a 5% interest (after payout to the Company and its drilling partner) in the Company's subsidiary that holds the Jefferson County, Mississippi project. During 2004, the Company's board of directors provided executives an option to repay the $149,410 of notes receivable that were outstanding on December 1, 2004, in cash or a return of shares of common stock at $1.56 per share, when the current fair market value of the common stock was $1.95 per share, resulting in the executives having to return 20% more shares to the Company rather than what would have been returned based on the fair market value of the common stock. The principal of $149,410 and interest balance of $9,366 were repaid by all officers in December 2004 through the return of 95,776 and 6,004 shares of the Company's common stock, respectively, held by the executives. As of December 1, 2004, $145,000 was recorded in stock subscription receivable from executives of the Company. The stock subscription receivables of $100,000 were repaid in 2004 through the return of 64,103 shares of the Company's common stock under the terms described in the previous paragraph. The stock subscription receivable of $45,000 was repaid in lieu of compensation in 2004. The related party receivable balance from executives increased from $51,900 at December 1, 2004, to $63,234 in 2004 as a result of advances to two officers of the Company. The total balance was repaid to the Company in 2004 through the return and cancellation of 40,480 shares of common stock of the Company personally held by the two officers. 12. EARNINGS PER SHARE ------------------ Following is a reconciliation of the numerators and denominators of the basic and diluted EPS computations for the years ended December 31, 2005 and 2004:
2005 2004 ------------ ------------ Net loss $(2,901,031) $(1,571,120) Less: Preferred stock dividends (38,673) (38,673) ------------ ------------ Net loss available to common stockholders (numerator) $(2,939,704) $(1,609,793) ============ ============ Weighted average shares of common stock (denominator) 25,409,348 17,576,294 ============ ============ Basic and diluted net loss per share $ (0.12) $ (0.09) ============ ============
13. NON-CASH INVESTING AND FINANCING ACTIVITIES ------------------------------------------- During the years ended December 31, 2005 and 2004, the Company engaged in various non-cash financing and investing activities as follows: F-23
2005 2004 ---------- --------- Transfer of overriding royalty interest for debt issuance costs $ 64,784 $ - ========== ========= Reduction of prepaid services for development of oil and gas properties $ - $ 333,765 ========== ========= Issuance of common stock for acquisition of Property $1,090,000 $ 51,920 ========== ========= Cancellation of common stock for reduction in subscription receivable $ - $ 249,410 ========== ========= Cancellation of common stock for reduction in related party receivable $ - $ 72,600 ========== ========= Increase in accounts payable and accrued liabilities for property costs $ 500,000 $ 429,069 ========== ========= Increase in property costs for asset retirement obligation accrual $ 633,455 $ - ========== ========= Issuance of warrants with debt $ 88,422 $ - ========== ========= Cancellation of warrants for reduction in note receivable $ 88,392 $ - ========== ========= Transfer of automobile for reduction in liability $ 15,346 $ - ========== =========
14. IMPAIRMENT AND SALE OF OIL AND GAS PROPERTIES --------------------------------------------- At December 31, 2005 and 2004, the net capitalized costs of crude oil and natural gas properties did not exceed the present value of the estimated reserves; as such, no write-down was recorded. 15. BUSINESS SEGMENTS ----------------- The Company believes that all of its material operations are conducted in the exploration and production of oil and gas in the United States and currently reports as a single segment. 16. SUPPLEMENTAL OIL AND GAS INFORMATION - UNAUDITED ------------------------------------------------ The following supplemental information regarding the oil and gas activities of the Company is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission ("SEC") and SFAS No. 69, Disclosures About Oil and Gas Producing Activities (`Statement 69"). ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES --------------------------------------------------- Set forth below is a summary of the changes in the estimated quantities of the Company's crude oil and condensate, and gas reserves for the periods indicated, as estimated by the Company as of December 31, 2005. All of the Company's reserves are located within the United States. Proved reserves cannot be measured exactly because the estimation of reserves involves numerous judgmental determinations. Accordingly, reserve estimates must be continually revised as a result of new information obtained from drilling and production history, new geological and geophysical data and changes in economic conditions. Proved reserves are estimated quantities of gas, crude oil, and condensate, which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. F-24
OIL GAS ---------- ---------- QUANTITY OF OIL AND GAS RESERVES (BBLS) (MCF) -------------------------------------------- ---------- ---------- Total proved reserves at December 31, 2003 460,654 177,438 Extensions and discoveries 25,856 1,158,000 Production (120,525) (64,009) Revisions to previous estimate 7,812 (24,392) ---------- ---------- Total proved reserves at December 31, 2004 373,797 1,247,037 Extensions and discoveries 2,033,869 1,121,000 Production (33,676) (4,725) Sale of Assets (64,771) - 0 - Revisions to previous estimate 36,575 (519,565) Total proved reserves at December 31, 2005 2,345,794 1,843,747 ========== ========== PROVED DEVELOPED RESERVES: December 31, 2005 330,838 229,747 ========== ========== December 31, 2004 181,945 94,075 ========== ==========
CAPITALIZED COSTS OF OIL AND GAS PRODUCING ACTIVITIES ----------------------------------------------------- The following table sets forth the aggregate amounts of capitalized costs relating to the Company's oil and gas producing activities and the aggregate amount of related accumulated depletion, depreciation and amortization as of December 31, 2005 and 2004:
2005 2004 ------------ ------------ Unproved oil and gas properties $ 3,513,597 $ 3,548,812 Proved oil and gas properties 11,849,520 5,490,447 ------------ ------------ Total 15,363,117 9,039,259 Less accumulated depletion, depreciation and amortization (1,929,727) (2,152,511) ------------ ------------ Net capitalized costs $13,433,390 $ 6,886,748 ============ ============
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES -------------------------------------------------- The following table reflects the costs incurred in oil and gas property acquisition, exploration and development activities during the years ended December 31, 2005 and 2004:
2005 2004 ---------- ---------- Acquisition costs $4,079,919 $3,298,830 ========== ========== Exploration costs $1,147,816 $2,288,195 ========== ========== Development costs $1,096,124 $1,397,403 ========== ==========
F-25 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS -------------------------------------------------------- The following table reflects the Standardized Measure of Discounted Future Net Cash Flows relating to the Company's interest in proved oil and gas reserves as of December 31, 2005 and 2004:
2005 2004 ------------- ------------ Future cash inflows $158,565,979 $23,742,174 Future development and production costs (59,263,004) (6,250,065) ------------- ------------ Future net cash inflows before income taxes 99,302,975 17,492,109 Future income taxes (27,804,833) (4,961,317) ------------- ------------ Future net cash flows 71,498,142 12,530,792 10% discount factor (36,654,786) (2,704,002) ------------- ------------ Standardized measure of discounted future net cash inflow $ 34,843,356 $ 9,826,790 ============= ============
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS -------------------------------------------------------- Future net cash flows at each year end, as reported in the above schedule, were determined by summing the estimated annual net cash flows computed by: (1) multiplying estimated quantities of proved reserves to be produced during each year by current prices, and (2) deducting estimated expenditures to be incurred during each year to develop and produce the proved reserves (based on current costs). Income taxes were computed by applying year-end statutory rates to pretax net cash flows, reduced by the tax basis of the properties and available net operating loss carryforwards. The annual future net cash flows were discounted, using a prescribed 10% rate, and summed to determine the standardized measure of discounted future net cash flow. The Company cautions readers that the standardized measure information which places a value on proved reserves is not indicative of either fair market value or present value of future cash flows. Other logical assumptions could have been used for this computation which would likely have resulted in significantly different amounts. Such information is disclosed solely in accordance with Statement 69 and the requirements promulgated by the SEC to provide readers with a common base for use in preparing their own estimates of future cash flows and for comparing reserves among companies. Management of the Company does not rely on these computations when making investment and operating decisions. 17. SUBSEQUENT EVENTS ----------------- CAPITAL RAISE On February 8, 2006, Petrosearch Energy Corporation completed a private placement of equity securities solely to accredited investors for total proceeds of $2,700,000 (the "Offering"). Pursuant to the Offering, the Company issued 1,928,572 shares of the Company's common stock at a price of $1.40 per share and 964,286 three year warrants to purchase shares of the Company's common stock with an exercise price of $2.00 per share to the accredited investors. On February 3, 2006, the Company engaged a placement agent to handle the Offering. At the time of closing, the Company paid a placement fee of 5% of the gross proceeds of the Offering. Additionally, at the time of closing, the placement agent received 96,429 warrants to purchase shares of the Company's common stock equal to 5% of the number of shares of common stock issued to the F-26 accredited investors at the time of closing of the Offering. The warrants issued to the placement agent are exercisable for three years and have an exercise price of $2.00 per share. The shares of common stock and the shares of common stock underlying the warrants have piggyback registration rights. The Company intends to use the proceeds of the Offering for working capital and general corporate purposes. BARNETT SHALE AGREEMENT On March 30, 2006, we entered into an Extension Agreement with ExxonMobil Corporation, Harding Company ("Harding"), Eagle Oil & Gas Co., PS Gas Partners, LLC, and Gas Partners, L.P. (the "Extension Agreement"), under which the parties have agreed to extend until May 2, 2006, ExxonMobil's preferential purchase rights related to the separate sale agreements between Harding Company and each of the other parties relating to the Barnett Shale project, including our February 6, 2006, First Amended and Restated Program Agreement with Harding Company (the "First Amended and Restated Program Agreement") previously announced in our Form 8-K filing on February 6, 2006. The First Amended and Restated Program Agreement followed a June 29, 2005 Lease Acquisition and Development Agreement between ExxonMobil Corporation and Harding Company and a Memorandum of Understanding Regarding Gas Evacuation from ExxonMobil and Harding Barnett Shale E&P Venture covering the project (the "ExxonMobil/Harding Agreements"). Under the ExxonMobil/Harding Agreements, Harding is responsible to serve as operator for a significant portion of the area of mutual interest and to acquire and develop the leases in the area of mutual interest. ExxonMobil is responsible for the operation and construction of the gathering and evacuation system associated with the area of mutual interest and will serve as operator for the balance of the area of mutual interest. At the time of the execution of the First Amended and Restated Program Agreement, Harding had not obtained from ExxonMobil a consent to transfer and a waiver of Exxon/Mobil's a preferential purchase right set forth in the ExxonMobil/Harding agreement. At the time of our execution of and initial funding under the First Amended and Restated Program Agreement, we did not have a direct contractual relationship with ExxonMobil. We believed that all conditions necessary to assign and convey the working interest from Harding had been met. We subsequently learned that ExxonMobil had not waived the contingencies and that ExxonMobil desired to explore possible alternative ownership structures beneficial to all concerned before making a determination with respect to the preferential right to purchase. The purpose of the Extension Agreement is to give all the parties involved the ability to explore possible alternative structures with the goal to form an integrated venture which would include both upstream and pipeline assets and activities, which would better align each party's interest, and which would enhance the ability of the venture to assure that adequate pipeline capacity would be available to move natural gas to market. The opportunity to participate in an integrated venture which includes the gathering and evacuation system was not present in the First Amended and Restated Program Agreement. The potential alternative structure has potential positive features. The Extension Agreement likewise preserves to the parties all of their respective rights and claims as they existed prior to the execution of the Extension Agreement. In the event that the parties cannot achieve a mutually agreed alternative structure on or before May 2, 2006, ExxonMobil could exercise its preferential purchase right which, if exercised, would prevent our participation in the project. In the event of such a loss of this opportunity to participate in the project, our legal rights are not prejudiced by the Extension Agreement and we would then expect to pursue all potential remedies available to us relating to the factual circumstances surrounding these agreements. F-27