UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K
| T | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2008
| £ | TRANSITION REPORT PURSUANT TO SECTION 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 incorporation or organization) | (IRS Employer Identification No.) |
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
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes £ No T
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No T
Indicate by check mark whether the issuer: (i) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act of 1934 during the preceding 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 T No £
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by referencein Part III of this Form 10-K or any amendment to this Form 10-K.. T
Indicate by check mark whether the issuer is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in rule 12b-2 of the Exchange Act.
Large accelerated filer £ | Accelerated filer £ | Non-accelerated filer £ | Smaller reporting Company T |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No T
The aggregate market value of common stock held by non-affiliates of the registrant at March 5, 2009, based upon the last reported sales prices on the OTCBB, was $3,863,418
As of March 5, 2009, there were approximately 41,310,578 (net of 1,117,973 treasury shares) shares of common stock outstanding.
| PART I | Page |
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| Item 1A. | | 2 |
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| Item 2. | | 6 |
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| Item 3. | | 10 |
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| Item 4. | | 11 |
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| PART II | |
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| Item 5. | | 11 |
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| Item 7. | | 13 |
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| Item 8. | | 21 |
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| Item 9. | | 21 |
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| Item 9A. | | 21 |
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| Item 9B. | | 22 |
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| PART III | |
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| Item 10. | | 22 |
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| Item 11. | | 25 |
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Item 12. | | 27 |
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| Item 13. | | 28 |
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| Item 14. | | 28 |
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| Item 15. | | 29 |
PART I
Overview
Petrosearch Energy Corporation (the “Company”, “Petrsearch” and “we”), 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 are a resource based energy company with current operations focused in North Texas with existing production in Texas and Oklahoma. A majority of our effort since the sale of our Barnett Shale Project in July, 2008 has been to focus on pursuing strategic alternatives for the Company that will create the most value for our shareholders, as well as focusing on the development of our Texas Panhandle water flood that we operate .
Our History
We are the successor to the business of Petrosearch Corporation, a Texas corporation that was formed in August 2003. In November 2004, shareholders of Petrosearch Corporation 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 re-domicile to Nevada. Upon the completion of the merger, shareholders of Petrosearch Corporation were issued shares of our common and preferred stock representing 100% of the then issued and outstanding common and preferred shares.
Shares of our common stock have been publicly traded on the OTC Bulletin Board under the symbol “PTSG” since November 2005. Our principal offices are located at 675 Bering Drive, Houston, Texas 77057, and our telephone number is 713-961-9337. Our website is www.petrosearch.com.
Business Plan
We are a resource based energy company with operations focused on a waterflood project in North Texas. Our strategic goal is to build intrinsic shareholder value through focused operations from this project while maintaining a low cost structure at every level of our Company. We have also been in the process of identifying and evaluating other potential opportunities that would complement our current business plan and create economic value. We believe that the Company has a strong financial position, given the lack of debt and significant cash position. We intend to use this strong position to create value for the shareholders, whether it be in the form of a merger with a public or private company, or a significant acquisition or sale. The Company is currently involved in ongoing negotiations with a third party in connection with a possible merger transaction. However, as of the date of this agreement no defnititve documents have been executed and no assurance can be given that a transaction will be entered into or completed.
On June 25, 2008 we executed a binding agreement for the sale of our limited partnership interest in DDJET Limited LLP (“DDJET”) (“Barnett Shale project”) to Cinco County Barnett Shale LLC (“Cinco”), one of the other two partners in DDJET, for a cash purchase price of $36,000,000. On June 26, 2008 Cinco paid to Barnett Petrosearch the required $1,800,000 non-refundable deposit to be applied to the purchase price and fulfilled all the other necessary requirements to bind both Cinco and the Company to the sale. On July 18, 2008 the Company received the balance of the proceeds of the sale of $30,729,008, the net amount after deducting the $1,800,000 down payment previously received from Cinco and $3,470,992 of costs previously owed by the Company which were assumed by Cinco pursuant to the June 25, 2008 agreement.
As of December 31, 2008 we have $5,209,093 of pre-tax PV-10 (present value discounted at 10% of future net revenues) for proved reserves associated with our properties,. See “Oil and Natural Gas Reserves” for a reconciliation of after tax PV-10. We are also focused on maintaining a low cost structure throughout our business by maintaining tight control on our corporate overheads and operating costs in our properties.
As of December 31, 2008, the Company had proved reserves of 1,662,786 barrels of oil equivalent (Boe). This is a decrease of 496,685, or twenty three percent from the proved reserves as of December 31, 2007 which were 2,159,471 Boe. This decrease relates to i) the sale of the Barnett Shale project in July 2008; and ii) the reclassification of reserves from proved to probable for the Gruman 18-1 due to mechanical and down-hole problems with the well. As of December 31, 2008, the Company’s standardized measure of discounted future net cash flows relating to the Company’s interest in proved oil and gas reserves were $4,839,059.
Employees
As of December 31, 2008, we had five full-time employees and one part time employee, of which three are in executive positions. None of our employees are represented by a union and we consider our employee relations to be good.
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 occurs, 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 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 year ended December 31, 2008 we incurred a net operating loss of $18,811,019. 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.
Generally, the Securities and Exchange Commission defines a “penny stock” as any equity security not traded on an exchange or quoted on NASDAQ that has a market price of less than $5.00 per share. The trading price of our common stock is below $5.00 per share. As a result of this price level, our common stock is considered a penny stock and trading in our common stock is subject to the requirements of certain rules promulgated under the Securities Exchange Act of 1934. These rules require additional disclosure by broker-dealers in connection with any trades generally involving penny stocks 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.
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.
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 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.
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).
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, 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 acquisition (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.
There is limited liquidity in our shares.
There is a limited market for our shares of common stock and an investor may not be able to liquidate his or her investment regardless of the necessity of doing so. The prices of our shares are highly volatile. This could have an adverse effect on developing and sustaining the market for our securities. If the market price of our common stock declines significantly, you may be unable to resell your common stock at or above the public offering price. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly, including a decline below the public offering price, in the future. In addition, the stock markets in general can experience considerable price and volume fluctuations.
General Risks of the Oil and Gas Business
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.
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.
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, 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 or a change in reserve estimates 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-K 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.
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.
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.
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.
Barnett Shale Project -- In December 2006, through our wholly owned subsidiary, Barnett Petrosearch LLC (“Barnett Petrosearch”), we joined in the formation of a partnership, DDJET Limited LLP (“DDJET”), for the development of a natural gas integrated venture to explore and develop assets in the Barnett Shale. We owned a 5.54% interest in DDJET along with partners Metroplex Barnett Shale LLC (a wholly owned subsidiary of Exxon Mobil Corporation), and Cinco County Barnett Shale LLC (“Cinco” - a privately held Dallas-based company). On February 29, 2008 we announced that we executed an authorization for the general partner of the Partnership to immediately commence a sales marketing program to interested potential purchasing parties in order to fully assess the current market value of the Partnership. On June 25, 2008 we executed a binding agreement for the sale of our limited partnership interest in DDJET to Cinco, one of the other two partners in DDJET, for a cash purchase price of $36,000,000. On June 26, 2008 Cinco paid to Barnett Petrosearch the required $1,800,000 non-refundable deposit to be applied to the purchase price and fulfilled all the other necessary requirements to bind both Cinco and the Company to the sale. On July 18, 2008 the Company received the balance of the proceeds of the sale of $30,729,008, the net amount after deducting the $1,800,000 down payment previously received from Cinco and $3,470,992 of costs previously owed by the Company to the Partnership which were assumed by Cinco pursuant to the June 25, 2008 agreement.
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 project is focused on infill drilling and the implementation of a water flood on the property. Our leases at Quinduno have a large established resource base of over 23 million barrels of original oil in place. Since its discovery in 1953, approximately 5.1 million barrels have been produced using primary production.
One infill well has been drilled to date. We have an ongoing program to enter each of the 19 old wells that have not been plugged. So far, we have entered nine of these older wells to determine their mechanical status and establish potential productivity. Three of these wells have been equipped and are now capable of producing. Another three wells have been equipped/converted for water injection which was initiated in September 2008. We have prepared a detailed study and development plan for the field. As of December 31, 2008, our independent engineers, Ryder Scott, estimated our net share of proved oil reserves extractable by water flood at 1.5 million barrels of oil equivalent. Slightly deeper than the water flood zone, the Moore County Limestone formation has undrilled exploration potential that may be tested in a future well.
To provide water for injection, in November 2006 we executed a water supply agreement with a landowner in the leasehold, which allows us to draw fresh water from the aquifer underlying the landowner’s property. In that same month, we received approval from the Panhandle Groundwater Authority District (“PGAD”) to produce up to 5,000 barrels per day from the aquifer for use in the flood. We received the approval from the PGAD over the protest filed with the PGAD by the Canadian River Municipal Water Authority (“CRMWA”) attempting to preserve the freshwater for local municipal use only in the area in which we own the rights to the fresh water. We also applied to the Texas Railroad Commission to amend a previously granted saltwater injection permit to include fresh water injection. On January 5, 2007 we received a letter from the Texas Railroad Commission (“TRRC”) informing us of a protest by CRMWA contesting our application for fresh water injection in the Quinduno Field water flood. However, as of November 7, 2007, CRMWA has withdrawn their protest and request for hearing as part of an agreement with CRMWA that addresses their concerns with our use of fresh water for enhanced oil recovery.
In January 2008 we signed an agreement with Complete Production Services Inc. (“CPS”), an international oilfield service company which provides that CPS, at its sole expense, will design and construct a water treatment facility no later than 90 days from the effective date of the agreement that will be capable of treating all of our production water up to a maximum of 10,000 bbls per day and likewise treat and provide to the Company a minimum of 5,000 bbls per day of production water from third party sources. We, in turn, committed to be capable of injecting not less than 2,000 bbls of treated water per day derived from third party production water within 30 days after the facility is opened, which we have met. We further committed to be capable of injecting not less than 5,000 bbls of treated water per day derived from third party production water within 180 days after the facility opens, which we fully expect to meet. In addition we are re-injecting our own treated production water from the oil and gas lease we operate. We are required to pay a scaled management fee to CPS which commenced on the date the facility opened on the basis of the volume of treated and re-injected water derived from our production. We have approval from the regulatory agencies to add eight more wells to the existing flood permit, as required under the agreement, to ensure our ability to inject the volumes that CPS will make available. We do not anticipate any difficulty with obtaining the approval.
The Company made the decision to commence the project and implement the first phase of the water flood project using a portion of the proceeds from the sale of the DDJET partnership interest. This first phase, which commenced in September 2008, enables the Company to spend the least amount of capital needed to measure the level of initial response of the water injection. The Company will then be able to make decisions on the future development of the project, and its impact on future potential strategic alternatives. Due to many different factors, a response time for the water flood can not be accurately projected, but the Company is hopeful that the initial level of response will be known in the next six months. As of the date of this filing there has been no meaningful response from the waterflood.
Gruman Prospect, Stark County, North Dakota - On March 28, 2006, we spudded the Gruman 18-3 well intended to be either an increased density well if it proved to be up dip of the Gruman 18-1 producing well or a water injection well if it was down dip. The well reached total depth of 9,890 feet on April 14, 2006, and was completed as an injection well. On February 1, 2007, we began injecting produced water into the Gruman 18-3 well. The goal was to reduce the cost of operating the Gruman 18-1 by eliminating the need to truck produced water to a disposal facility. Further testing or stimulation may be necessary to achieve the desired future injection rates.
During 2008 the pump on the Gruman 18-1 producer has been repaired or replaced three times. The pump was last repaired in early July 2008 after which fluid flow into the wellbore diminished to near zero. In order to re-establish production we are considering supplementing the produced water injection volume in the Gruman 18-3 well with water from the Dakota formation for pressure maintenance in the mound. Further, we are giving consideration to deepening the 18-1 well to expose more of the mound. The Gruman well continued to have pump and motor issues. This along with an unexpected decline in reservoir pressure has severely affected our ability to produce the well. There has been no production on the well since May 2008. Additionally, due to the mechanical and down-hole problems with the well, the reserves that were previously classified as proved are no longer able to be classified as such.
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 |
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.
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.
At December 31, 2008 our standardized measure of discounted future net cash flows was $4,839,059. The present value of future net pre-tax cash flows attributable to estimated net proved reserves, discounted at 10% per annum, is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. The table below provides a reconciliation of Pre-tax PV-10 to the standardized measure of discounted future net cash flows at December 31, 2008. Pre-tax PV-10 may be considered a non-GAAP financial measure under the SEC’s regulations. We believe Pre-tax PV-10 to be an important measure for evaluating the relative significance of our natural gas and oil properties. Pre-tax PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. We further believe investors and creditors may utilize our Pre-tax PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. However, Pre-tax PV-10 is not a substitute for the standardized measure. Our Pre-tax PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our natural gas and oil reserves.
| Net present value of future net cash flows, before income taxes | | $ | 5,209,093 | |
| Future income taxes, discounted at 10% | | | (370,034 | ) |
| | | | | |
| Standardized measure of discounted future net cash flows | | $ | 4,839,059 | |
The following table sets forth summary information with respect to our proved reserves as of December 31, 2008, as estimated by compiling reserve information, which was prepared by the engineering firms of Ryder Scott Company 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, 2008 | | | | | | | | | | | | |
| Proved Developed | | | 13,077 | | | | - | | | | 13,077 | | | $ | 215,417 | |
| Proved Undeveloped | | | 1,522,042 | | | | 766,000 | | | | 1,649,709 | | | $ | 4,993,676 | |
| | | | | | | | | | | | | | | | | |
| Total Proved | | | 1,535,119 | | | | 766,000 | | | | 1,662,786 | | | $ | 5,209,093 | |
(1) Estimated using a conversion ratio of 1.0 Bbl/6.0 Mcf (thousand cubic feet).
Total pre-tax PV-10 value decreased to $5,209,093 as of December 31, 2008 from $55,485,780 as of December 31, 2007. The factors that caused the significant decrease in the PV-10 value and the decrease in the reserve quantities from 2007 to 2008 were related mainly to i) the significant decrease in the price of oil as of the end of 2008 as opposed to the end of 2007; ii) the sale of the Barnett Shale project in July 2008; and iii) the mechanical and down hole problems associated with our Gruman 18-1 well in North Dakota that caused the reserves to be reclassified as probable, as opposed to proved.
We note that reserve and cash flow estimates utilize experience and judgment as well as actual data, but actual results are often different than the estimate. 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 interests (WI) that we maintain in each well as of March 5, 2009:
| | | No. of Wells | | | WI (Oil) | | | WI (Gas) | |
| Gordon 1-18 | | | 1 | | | | 95 | % | | | N/A | |
Quinduno(1) | | | 4 | | | | 100 | % | | | 100 | % |
| Corbett N. 13 #1 | | | 1 | | | | 10 | % | | | 10 | % |
| Total Productive Wells | | | 6 | | | | | | | | | |
| | (1) | Project in which the Company’s working interest reduces to 90% (as described herein– North Texas/Panhandle Water Flood Project Section) |
Acreage
The following table summarizes our gross and net developed and undeveloped natural gas and crude oil wells and acreage under lease as of March 5, 2009:
| | | | | Wells | | | Acreage | |
| State | | | | Gross | | | Net | | | Gross | | | Net | |
| Developed acreage: | | | | | | | | | | | | | | |
| Texas: | | | | | | | | | | | | | | |
| Maddox (Quinduno) | | 16 Oil | | | 16 | | | | 16 | | | | 1,755 | | | | 1,755 | |
| North Dakota | | Oil | | | 1 | | | | .85 | | | | 280 | | | | 238 | |
| Oklahoma: | | | | | | | | | | | | | | | | | | |
| Gordon 1-18 | | Oil | | | 1 | | | | .95 | | | | 610 | | | | 579 | |
| Corbett N.#13-1 | | Gas | | | 1 | | | | .10 | | | | 552 | | | | 55 | |
| Total Developed | | | | | 19 | | | | | | | | 3,197 | | | | 2,627 | |
| Undeveloped acreage: | | | | | | | | | | | | | | | | | | |
| N/A | | | | | | | | | | | | | - | | | | - | |
| Total Undeveloped | | | | | | | | | | | | | - | | | | - | |
| Total | | | | | 19 | | | | | | | | 3,197 | | | | 2,627 | |
Operator Activities
We currently operate 100% of our producing properties, and generally seek to become the operator of record on properties we drill or acquire.
Drilling Activities
The following table sets forth our drilling activities for the last three fiscal years. Our working interests in the productive wells owned as of December 31, 2008, range from a direct working interest of 100% to 10%. In 2008 we drilled two wells in our Barnett Shale Project that was sold in June of 2008. Additionally, there were two wells in our Barnett Shale Project that were drilled as of June 30, 2008 but were not completed before our sale of the Project in July 2008.
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | | |
| Development Wells: | | | | | | | | | |
| Productive | | | - | | | | - | | | | 1 | |
| Non-Productive | | | - | | | | - | | | | 1 | |
| Total | | | - | | | | - | | | | 2 | |
| | | | | | | | | | | | | |
| Exploratory Wells: | | | | | | | | | | | | |
| Productive | | | 2 | | | | 12 | | | | 1 | |
| Non-Productive | | | - | | | | 3 | | | | 1 | |
| Total | | | 2 | | | | 15 | | | | 2 | |
| | | | | | | | | | | | | |
| Total Wells: | | | | | | | | | | | | |
| Productive | | | 2 | | | | 12 | | | | 2 | |
| Non-Productive | | | - | | | | 3 | | | | 2 | |
| | | | 2 | | | | 15 | | | | 4 | |
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, 2008 and December 31, 2007
| | | 2008 | | | 2007 | |
| Average sales price per barrel of oil | | $ | 90.99 | | | $ | 69.55 | |
| Average sales price per Mcf of gas | | $ | 8.90 | | | $ | 6.19 | |
| Lifting costs per barrel of oil equivalent* | | $ | 34.77 | | | $ | 20.32 | |
* Excludes the costs of re-entry into wells to assess non-producing assets
On April 11, 2007, the Company was served with a lawsuit filed against it titled Cause No. 2007-16502; D. John Ogren, R. Bradford Perry and Chester Smitherman v. Petrosearch Corporation; 133rd Judicial District Court, Harris County, Texas. The plaintiffs were three (3) Series A Preferred shareholders who derived their original shares from Texas Commercial Resources, Inc. (“TCRI”) and became Series A Preferred shareholders of Petrosearch Energy Corporation as a result of the prior mergers. The plaintiffs had alleged that Petrosearch Corporation (and TCRI, its predecessor) failed to pay accrued, cumulative dividends and refused to allow conversion of their Series A Preferred Stock into Common Stock. The plaintiffs had alleged breach of contract, fraud and violation of Section 33 of the Texas Securities Act and have requested the award of actual and exemplary damages, interest and attorneys’ fees. The lawsuit likewise requested the Court to compel the payment of accrued dividends and the examination of the Company’s books and records. The lawsuit was settled in September 2008 and the settlement was paid 100% by the Company's insurance policy. The payment of the settlement is not an admission of liability, as the Company denies all allegations of wrongdoing contained in the lawsuit.
The Company currently is not a party to any other material pending legal proceedings.
| SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
None.
PART II
| MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND 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, 2008.
| Quarter | | High | | | Low | |
1st Quarter 2007 | | $ | 1.60 | | | $ | 0.61 | |
2nd Quarter 2007 | | $ | 1.85 | | | $ | 1.20 | |
3rd Quarter 2007 | | $ | 1.59 | | | $ | 1.00 | |
4th Quarter 2007 | | $ | 1.25 | | | $ | 0.74 | |
1st Quarter 2008 | | $ | 0.98 | | | $ | 0.57 | |
2nd Quarter 2008 | | $ | 0.81 | | | $ | 0.28 | |
3rd Quarter 2008 | | $ | 0.55 | | | $ | 0.26 | |
4th Quarter 2008 | | $ | 0.29 | | | $ | 0.12 | |
Treasury Stock – Stock Repurchase Plan
In July 2008 the Board of Directors approved a stock repurchase plan (the “Repurchase Plan”) in which the Company is authorized to repurchase up to $5 million of market value or 10 million shares of its common stock in open market purchases or in privately negotiated transactions. The purchases are to be at the discretion of senior management and will be dependent upon market conditions. The Repurchase Plan did not require any minimum purchase and can be suspended or terminated by the Board of Directors at any time.
In October and November of 2008, the Company purchased 214,800 shares of its common stock at an average share price of approximately $0.21 to be classified as treasury stock. In February 2009 the Company purchased 903,173 shares of its common stock at an average price of $0.18 (see below). As of March 5, 2009 pursuant to the Repurchase Plan the company has purchased an aggregate of 1,117,973 shares of common stock at an average price of $.186. All purchase prices were negotiated based on recent market prices.
In February of 2009, the Company entered into an agreement with a warrant holder which provides for the following: 1) purchase by the Company of 903,173 shares of common stock held by the warrant holder, 2) purchase by the Company of 5,000,000 warrants of the warrant holder, and 3) settlement of any and all liquidated damages under the registration rights of the warrants. The total amount paid by the Company to the warrant holder as part of this agreement is $285,000 which was paid in February of 2009.
Warrant Buybacks
In February and March of 2009 the Company repurchased 13,930,479 of the 14,807,859 total warrants outstanding as of December 31, 2008 for an average purchase price of less than $0.01 per warrant as negotiated. These warrants have been cancelled. The balance of the warrants now outstanding represents 6.4% of the total outstanding warrants as of December 31, 2008 and leaves the Company with a total of 877,380 warrants as of the date of this filing.
Record Holders
On March 5, 2009, the last sales price for the common stock as reported on the OTCBB was $0.14 and there were 41,310,578 shares (net of 1,117,973 treasury shares) common shares outstanding. On March 5, 2009, there were approximately 2,500 stockholders of record of the common stock.
No prediction can be made as to the effect, if any, that future sales of shares of our common stock or the availability of our common stock for future sale will have on the market price of our common stock prevailing from time-to-time. The additional registration of our common stock and the sale of substantial amounts of our common stock in the public market could adversely affect the prevailing market price of our common stock.
On September 4, 2008 the Company filed Preliminary Schedule 14A stating that at the annual shareholder meeting the Company plans to seek shareholder approval to amend the Articles of Incorporation to increase the number of authorized shares of common stock from 100,000,000 to 300,000,000. The proposed increase in the authorized Common Stock was recommended by the Board to assure that an adequate supply of authorized unissued shares is available for use primarily in connection with corporate transactions, such as mergers and/or acquisitions. However; the Company at this time has decided to delay the shareholders meeting pending its decision regarding its plans to pursue strategic alternatives for the Company.
ISSUER PURCHASES OF EQUITY SECURITIES
| Period | | (a) Total Number of Shares (or Units) Purchased (1) | | | (b) Average Price Paid per Share (or Unit) | | | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs | | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs |
| October 2008 (October 10 - October 17) | | | 194,800 | | | $ | 0.21 | | | | 194,800 | | |
| November 2008 (November 3) | | | 20,000 | | | $ | 0.20 | | | | 20,000 | | |
| February 2009 (February 18) | | | 903,173 | | | $ | 0.18 | | | | 903,173 | | |
| Total | | | 1,117,973 | | | $ | 0.19 | | | | 1,117,973 | | 8,882,027 shares/$4,792,741 (2) |
| (1) | All of the shares purchased were through a plan publicly announced on July 2, 2008 |
| (2) | This plan for the repurchase of $5 million of market value or 10 million shares of its common stock was announced on July 2, 2008. Any purchases under the plan are anticipated to occur over the 12 month period ending on July 1, 2009. The repurchase plan may be suspended or terminated at any time. |
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
DIVIDEND POLICY
There are no restrictions in our Articles of Incorporation or Bylaws that prevent us from declaring dividends. The Nevada Revised Statutes, however, do prohibit us from declaring dividends where, after giving effect to the distribution of the dividend:
| 1. | We would not be able to pay our debts as they become due in the usual course of business; or |
| 2. | Our total assets would be less than the sum of our total liabilities plus the amount that would be needed to satisfy the rights of stockholders who have preferential rights superior to those receiving the distribution. |
We have not declared any dividends and we do not plan to declare any dividends in the foreseeable future. Our current policy is to retain any earnings in order to finance the expansion of our operations. Our Board of Directors will determine future declaration and payment of dividends, if any, in light of the then-current conditions they deem relevant and in accordance with the Nevada Revised Statutes.
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth all equity compensation plans as of December 31, 2008:
| Plan category | | Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) | | | Weighted-average exercise price of outstanding options, warrants and rights (b) | | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) | |
| Equity compensation plans approved by security holders | | | N/A | | | | N/A | | | | N/A | |
| Equity compensation plans not approved by security holders | | | N/A | | | | N/A | | | | N/A | |
| Total | | | N/A | | | | N/A | | | | N/A | |
RECENT SALES OF UNREGISTERED SECURITIES
All previous sales of unregistered securities during 2008 have been previously disclosed in Form 10-Q’s and Form 8-Ks.
| MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Overview
We believe we have been successful over the past several years at building a quality portfolio of oil and gas assets through economical financings and when necessary, monetizing those assets at opportune times to create the most value for the Company. Given the current market conditions over the broad economy and more specifically the oil and natural gas market, the sale of our Barnett Shale asset in July 2008 near the peak of natural gas prices was extremely fortunate. The sale left the Company with a substantive cash balance, no debt and a significant waterflood asset. We intend to use this strong position to create value for the shareholders, whether it is in the form of a merger with a public or private company, or a significant acquisition or sale. The Company is currently involved in ongoing negotiations with a third party in connection with a possible merger transaction. However, as of the date of this agreement no definitive documents have been executed and no assurance can be given that a transaction will be entered into or completed.
RESULTS OF OPERATIONS
The following discussion should be read in conjunction with our audited consolidated financial statements as of December 31, 2008 and the related notes to the financial statements.
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, 2008 Compared to the Year Ended December 31, 2007
Revenues
Consolidated oil and gas production revenue for the year ended December 31, 2008 was $1,400,480 versus $1,827,664 for the year ended December 31, 2007. The decrease in revenue is from the decrease in production associated with the down-hole mechanical and pressure depletion problems associated with the Gruman – North Dakota well and as a result of the sale of the SW Garwood properties in May 2008. The significant decrease from these two properties was partially offset by increased revenues from our Barnett Shale project which was sold in July 2008. See below for revenue detail for the years ended December 31, 2008 and 2007.
| | | 12/31/2008 | | | % of | | | 12/31/2007 | | | % of | |
| | | YTD | | | Total | | | YTD | | | Total | |
| | | | | | | | | | | | | |
| Barnett Shale | | $ | 999,945 | | | | 71 | % | | $ | 601,814 | | | | 33 | % |
| Gruman - North Dakota | | | 177,436 | | | | 13 | % | | | 790,976 | | | | 43 | % |
| SW Garwood | | | 26,255 | | | | 2 | % | | | 220,356 | | | | 12 | % |
| Panhandle - Water Flood | | | 9,442 | | | | 1 | % | | | 12,854 | | | | 1 | % |
| Oklahoma | | | 165,904 | | | | 12 | % | | | 150,240 | | | | 8 | % |
| Other | | | 21,498 | | | | 2 | % | | | 51,424 | | | | 3 | % |
| Total | | $ | 1,400,480 | | | | 100 | % | | $ | 1,827,664 | | | | 100 | % |
To further explain the variance in revenue from 2007 to 2008, we have provided the following break-out of production and prices for the two years.
| | | 2008 | | | 2007 | |
| | | | | | | | | |
| Barrels of Oil | | | 3,790 | | | | 12,842 | |
| Price per Barrel | | $ | 90.99 | | | $ | 69.55 | |
| | | | | | | | | |
| Mcf of Gas | | | 115,464 | | | | 135,061 | |
| Price per Mcf | | $ | 8.90 | | | $ | 6.19 | |
As noted in the above table, the increase in oil and gas prices helped offset the decrease in revenue since 2007 from lower production. The total effects on revenue from the oil and gas price increases were approximately $275,357 and $366,248, respectively.
Lease Operating and Production Tax Expense
Lease operating and production tax expenses for the year ended December 31, 2008 was $808,172 versus $731,915 for the year ended December 31, 2007, respectively. These expenses relate to the costs that are incurred to operate and maintain our wells and related production equipment, including the costs applicable to the operating costs of support equipment and facilities. Although there was a twenty three percent decrease in revenue from the year ended December 31, 2007 to the year ended December 31, 2008, the lease operating expenses increased ten percent because of increased expense work-over related to the Quinduno Field and the Gruman – North Dakota wells. The workovers for the Quinduno field were related to the commencement of the initial stags of the waterflood in 2008, while the workovers related to the Gruman North Dakota well were done in an attempt to resolve the mechanical and down-hole issues with the well. Unfortunately, the workovers on the Gruman – North Dakota well were not successful in getting the well back to producing.
Depletion, Depreciation and Amortization
Costs for depletion, depreciation and amortization for the year ended December 31, 2008, and 2007, were $577,394 and $909,311, respectively. This decrease is mainly due to a significant decrease in the amortizable costs at December 31, 2008 as compared to the same period in 2007 and a significant decrease in production for that same period. Given the fact that depletion is calculated by multiplying the net amortizable costs times the units of production in the related period relative to the total proved reserves, the depletion amount for the year ended December 31, 2008 was significantly lower than the depletion for the same period in 2007.
General and Administrative Expenses
General and administrative expenses for the years ended December 31, 2008 and 2007 were $3,112,047 and $3,022,739, respectively. The difference of $89,308 is approximately a three percent increase. Although the total general and administrative expenses had a minimal increase from 2007 to 2008 personnel costs were up twenty nine percent; however, this increase in personnel cost was off set by a decrease in travel, corporate, accounting, legal and professional, third party consultants and office expenses. The increase in personnel costs was due mainly to the issuance of equity bonuses (non-cash) to management and all full time employees. These non-cash bonuses were awarded to management and employees in 2008 given the fact that all of the management and employees stock warrants had expired in 2008. A summary listing of general and administrative expenses is provided below.
| | | YE December 31 | | | YE December 31, | |
| | | 2008 | | | 2007 | |
| | | | | | | |
| Personnel Costs | | $ | 1,739,296 | | | $ | 1,345,281 | |
| Travel, Meals, and Entertainment | | | 45,097 | | | | 53,609 | |
| Corporate Expenses | | | 249,269 | | | | 311,371 | |
| Accounting, Legal, and Professional Fees | | | 548,967 | | | | 762,684 | |
| Third Party Consultants and Contractors | | | 206,584 | | | | 239,440 | |
| Office Expenses | | | 190,654 | | | | 203,539 | |
| Other | | | 132,180 | | | | 106,815 | |
| | | | | | | | | |
| Total General and Administrative | | $ | 3,112,047 | | | $ | 3,022,739 | |
Net Operating Loss
We generated a net operating loss of $(18,811,019), for the year ended December 31, 2008, compared to a net operating loss of $(2,836,301), for the year ended December 31, 2007. The main reason for the significant difference of $(15,974,718) relates to a required non-cash impairment of the Company’s oil and gas properties. Under the Full Cost Method of accounting for oil and gas properties, there is a ceiling on the amount of capitalized costs of assets. That “ceiling” mainly refers to the fact that the net unamortized oil and gas assets can not exceed the present value discounted at 10% of future net revenues (“PV-10”) of the proved reserves. Due to the significant
decrease in oil and gas prices as of December 31, 2008, the PV-10 of our proved reserves was significantly lower than our unamortized costs, resulting in a significant non-cash impairment. The variance also related to a decrease in revenues, offset by a significant decrease in depreciation, depletion and amortization and minimal increases in general and administrative and lease operating expenses.
Other Income (Expense)
We had Other Income of $15,768,571 for the year ended December 31, 2008, compared to Other Expense of $3,699,131 for the year ended December 31, 2007, an increase of $19,467,702 from the prior year. This increase is mainly due to the gain on the sale of our Barnett Shale project and a decrease in interest expense resulting from extinguishment of all debt in 2008, which were partially offset by a loss on extinguishment of debt in 2008.
For the Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006
Revenues
Consolidated oil and gas production revenue for the year ended December 31, 2007 was $1,827,664 versus $1,232,958 for the year ended December 31, 2006. The increase in revenue is from the Barnett Shale Project which did not account for any of the revenue in the year ended 2006 and accounted for approximately 33% of the revenue for the year ended December 31, 2007. In addition, our 16% reversionary interest in one SW Garwood well was in effect for all of 2007, and only a portion of the prior year. The increase in revenue from the Barnett producing properties and our reversionary interest in one of the SW Garwood wells were partially offset by a slight decrease in production from our Gruman North Dakota well and a decrease in our producing Oklahoma wells. The sale of the Barnett Shale interest will significantly reduce our production revenues going forward as indicated by the fact that the Barnett Shale consisted of 33% of the revenue for the year ended December 31, 2007. The continued pump and reservoir issues with the Gruman – North Dakota well will also negatively impact our future revenues given the fact that the Gruman well accounted for 43% of the revenues for the year ended December 31, 2007. Therefore, due to the sale of the Barnett interest and the operational issues with the Gruman – North Dakota well we note that our past performance with regard to revenues and cash flow will not be indicative of future expected results. See below for revenue detail by property for the years ended December 31, 2007 and 2006.
| | | 12/31/2007 | | | % of | | | 12/31/2006 | | | % of | |
| | | YTD | | | Total | | | YTD | | | Total | |
| | | | | | | | | | | | | |
| Barnett Shale | | $ | 601,814 | | | | 33 | % | | $ | - | | | | 0 | % |
| Gruman - North Dakota | | | 790,976 | | | | 43 | % | | | 825,800 | | | | 67 | % |
| SW Garwood | | | 220,356 | | | | 12 | % | | | 96,521 | | | | 8 | % |
| Panhandle - Water Flood | | | 12,854 | | | | 1 | % | | | 74,526 | | | | 6 | % |
| Oklahoma | | | 150,240 | | | | 8 | % | | | 152,446 | | | | 12 | % |
| Other | | | 51,424 | | | | 3 | % | | | 83,665 | | | | 7 | % |
| Total | | $ | 1,827,664 | | | | 100 | % | | $ | 1,232,958 | | | | 100 | % |
To further explain the variance in revenue from 2006 to 2007, we have provided the following break-out of production and prices for the two years.
| | | 2007 | | | 2006 | |
| Barrels of Oil | | | 12,842 | | | | 16,502 | |
| Price per Barrel | | $ | 69.55 | | | $ | 59.81 | |
| | | | | | | | | |
| Mcf of Gas | | | 135,061 | | | | 14,283 | |
| Price per Mcf | | $ | 6.19 | | | $ | 8.45 | |
As noted in the above table, the increase in oil prices also played a role in the increase in revenue since 2006. Also a major impact on the increase in revenues was the significant increase in Mcf of gas produced, mainly from our Barnett Shale project and partially from our SW Garwood project. The total effect on revenue from the oil price increase was approximately $161,000.
Lease Operating and Production Tax Expense
Lease operating and production tax expenses for the year ended December 31, 2007 was $731,915 versus $653,265 for the year ended December 31, 2006, respectively. These expenses relate to the costs that are incurred to operate and maintain our wells and related production equipment, including the costs applicable to the operating costs of support equipment and facilities. Although there was a forty eight percent increase in revenue from the year ended December 31, 2006 to the year ended December 31, 2007, the lease operating expenses increased only twelve percent because in November 2005 we added approximately 30 existing wells associated with our Quinduno Field Prospect, Roberts County, Texas that required significant lease operating costs to be incurred in 2006 even though the wells had minimal production. These lease operating expenses incurred in 2006 were not necessary in 2007. The costs expended in 2006 for the existing, but non-productive wells were necessary for the planning of a successful development plan of the waterflood project that will be needed to realize the reserves in the Quinduno Field.
Depletion, Depreciation and Amortization
Costs for depletion, depreciation and amortization for the year ended December 31, 2007, and 2006, were $909,311 and $391,347, respectively. This significant increase is mainly due to a significant increase in the amortizable costs at December 31, 2007 as compared to the same period in 2006 as well as a significant increase in production. Given the fact that depletion is calculated by multiplying the net amortizable costs times the units of production in the related period relative to the total proved reserves, the depletion amount for the year ended December 31, 2007 was significantly higher than the depletion for the same period in 2006.
General and Administrative Expenses
General and administrative expenses for the years ended December 31, 2007 and 2006, were $3,022,739 and $2,766,235, respectively. The difference of $256,504 is mainly related to i) an increase in corporate expenses related to increased costs for outside third party investor relations services; and ii) an increase in legal fees, professional fees attributed to an ongoing lawsuit (as described herein), a special project related to our land department and an increase in expenditures for reserve engineer studies: and iii) an increase in other expenses relating to an increase in accounts receivable bad debt expense. These increases were partially offset by a decrease in personnel costs and travel, meals and entertainment. A summary listing of general and administrative expenses is provided below.
| | | YE December 31 | | | YE December 31, | |
| | | 2007 | | | 2006 | |
| | | | | | | |
| Personnel Costs | | $ | 1,345,281 | | | $ | 1,472,268 | |
| Travel, Meals, and Entertainment | | | 53,609 | | | | 107,832 | |
| Corporate Expenses | | | 311,371 | | | | 234,313 | |
| Accounting, Legal, and Professional Fees | | | 762,684 | | | | 544,627 | |
| Third Party Consultants and Contractors | | | 239,440 | | | | 206,954 | |
| Office Expenses | | | 203,539 | | | | 201,367 | |
| Other | | | 106,815 | | | | (1,126 | ) |
| | | | | | | | | |
| Total General and Administrative | | $ | 3,022,739 | | | $ | 2,766,235 | |
Net Operating Loss
We generated a net operating loss of $(2,836,301) or $(0.07) per share, for the year ended December 31, 2007, compared to a net operating loss of $(2,577,889) or $(0.08) per share, for the year ended December 31, 2006. The $258,412 variance is related mainly to an increase in D,D&A, lease operating expenses and general and administrative expenses, offset partially with an increase in revenues.
Other Income (Expense)
The ($3,955,095) change from $255,964 in Other Income for the year ended December 31, 2006 versus ($3,699,131) in Other Expense for the year ended December 31, 2007 is due to the significant increase in interest expense and amortization of debt discount and change in warrant liability related to 1) the non-recourse financing with Laurus Master Fund Ltd for the Kallina #46-1 well; 2) the $10 million Convertible note with RCH Petro Investors; and 3) the change in liability related to warrants issued to Fortuna Energy with a put option related to the revolving credit facility. The significant difference also relates to $1,000,000 in other income related to the sale of securities in the year ended December 31, 2006 that did not occur in the year ended December 31, 2007.
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 convertible notes 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.
Convertible Securities
On November 9, 2007 we executed, with a group of accredited investors, a series of Note and Warrant Purchase Agreements for the sale of $8,100,000, 8% Senior Secured Convertible Promissory Notes and three year warrants to purchase 1,928,571 shares of our common stock at an exercise price of $1.50 per share for total gross proceeds to us of $8,100,000. Upon closing the transaction, we also issued the note and the warrant, and executed a Pledge and Security Agreement and a Registration Rights Agreement. These convertible notes were repaid in full on July 21, 2008. In exchange for cancelling the note and releasing the collateral the note holders were paid the outstanding principal and accrued interest through July 21, 2008.
On February 1, 2007, we executed a Note and Warrant Purchase Agreement for the sale of a $10,000,000 8% Senior Secured Convertible Promissory Note with RCH Petro Investors, LP (“RCH”) and a four year warrant to purchase 5,000,000 shares of our common stock at an exercise price of $1.40 per share for total gross proceeds to us of $10,000,000. We completed the transaction and received funding on February 7, 2007. Upon closing, we issued the Convertible Note and the Warrant, and executed a Pledge and Security Agreement and a Registration Rights Agreement. This convertible note was repaid in full on July 21, 2008. In exchange for cancelling the note and releasing the collateral, the note holder was paid the outstanding principal and accrued interest through July 21, 2008.
Project Financings
In November 2006, we signed a Securities Purchase Agreement and Secured Term Note with Laurus Master Fund, Ltd to provide financing for the drilling of our Kallina 46 #1 well and payment of the future completion costs for the Kallina 46 #1 well. We formed a subsidiary, Garwood Petrosearch Inc., to hold our interest in the Kallina lease and the Kallina 46 #1 well. Also, as a part of the financing arrangement, Garwood issued Laurus a warrant to acquire, upon payout of the note indebtedness, 45% of Garwood’s outstanding common stock such that upon exercise of the warrant, Garwood would be owned 55% by us and 45% by Laurus.
It was decided in April 2008 that the Kallina 46#1 well was uneconomic and the decision was made that the well needed to be plugged and abandoned. In May 2008 the Company received a full release of all the liens, security interests, rights, claims and benefits of every kind in, on and under the November 2006 Secured Term Note with Laurus Master Fund, Ltd, as well as that same release on all the other collateral documents associated with that financing. The November 2006 financing was specifically recourse to the Kallina 46#1 well and the associated lease acreage only. The debt related to the Laurus financing was extinguished on the financial statements of the Company in May, 2008 as well as any interest that was charged in relation to the Note was reversed in that same period.
As part of this transaction, the Company has conveyed their interest in the Kallina 46#1 well and the associated lease acreage to a third party along with the Company’s interest in the Pintail #1 well, Pintail Flats #1 well and the associated acreage of Pintail and Pintail Flats. Also as a part of this transaction, the Company has transferred operatorship of all the existing and future wells in this SW Garwood Prospect to the third party. In exchange for the conveyance of the wells and acreage and the transfer of operatorship, the Company received nominal cash consideration as well as the third party has assumed the liability of plugging the Kallina 46#1 well.
Revolving Credit Agreement
On October 16, 2006, we amended our existing revolving credit facility with Fortuna Energy, LP. The principal available under the revolving borrowing base remained $10,000,000. Under the terms of the transaction, Fortuna advanced us $780,000 for the purpose of paying amounts due for the Barnett Shale Project. As part of the financing, we provided Fortuna additional collateral. In addition, we agreed to issue to Fortuna 475,000 five year warrants with a strike price of $0.92 per share. The Warrants contain a “put” provision which allows Fortuna to “put” the warrants to the Company at a price of $0.65 per share for two (2) years, which “put” period shall commence 180 days after issuance. Additionally, as part of the transaction, we agreed to issue 100,000 new warrants, which expire 5 years from the date of issue, at a price of $0.92 per share to replace 100,000 warrants previously issued to Fortuna at a price of $2.00 per share, which were previously set to expire on November 1, 2007.
As of April 1, 2008 the revolving credit facility became due and a payment of $1,602,500 was paid in full to Fortuna Energy. As per the revolving credit agreement, as part of being paid back in full, Fortuna Energy returned to the Company all of the overriding royalties issued to Fortuna Energy. The main override related to a 2% override in the Company’s North Dakota, Gruman project.
The 475,000 warrants were put back to the Company in October 2008 for a total payment to Fortuna of $308,750.
Joint Ventures
We continue to strive to develop relationships with institutions 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 STATEMENTS 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 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 above. 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-K are based on information available to us on the date of the Form 10-K. 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-K.
OFF BALANCE SHEET ARRANGEMENTS
From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2008, the off-balance sheet arrangements and transactions that the Company has entered into include two operating lease agreements for office space. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.
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 $7,099,601 at December 31, 2007 and $0 at December 31, 2008. If applicable, 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.
Reserve Estimates. Our estimates of oil and natural gas reserves, by necessity, are projections based on geological and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.
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.
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 to record a loss contingency; therefore, to date no commitments or contingencies have been recorded.
Stock based compensation. Effective January 1, 2006, we adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004) – Share-Based Payment (“SFAS 123(R)”), which requires the measurement and recognition of compensation expense for all share-based payment awards (including stock options) made to employees and directors based on the estimated fair value. Compensation expense for equity-classified awards is measured at the grant date based on the fair value of the award and is recognized as an expense in earnings over the requisite service period using a graded vesting method. Total share-based compensation expense for equity-classified employee awards, was $313,750 during the year ended December 31, 2008. As of December 31, 2008, there is no estimated unrecognized compensation expense from unvested stock options.
We use the Black-Scholes valuation model to determine the fair value of each option award. Expected volatilities are based on the historical volatility of our stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in our stock price and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms. Prior to our adoption of the provisions of SFAS 123(R), we previously accounted for the Plans under Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” (“APB 25”), and related interpretations and disclosure requirements established by SFAS 123 – Accounting for Stock-Based Compensation, as amended by SFAS No. 148 – Accounting for Stock-Based Compensation – Transition and Disclosure.
| FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
The information required by this Item 8 is included in this report beginning on page 32.
| 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.
Evaluation of Disclosure Controls and Procedures
Petrosearch Energy Corporation’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to the issuer’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of December 31, 2008.
Management’s Annual Report on Internal Control over Financial Reporting
Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the Company’s financial position, results of operations and cash flows in conformity with U.S. generally accepted accounting principles. In preparing its consolidated financial statements, the Company includes amounts that are based on estimates and judgments that Management believes are reasonable under the circumstances. The Company’s financial statements have been audited by Ham, Langston & Brezina, L.L.P., an independent registered public accounting firm appointed by the Audit Committee of the Board of Directors. Management has made available to Ham, Langston & Brezina, L.L.P., all of the Company’s financial records and related data, as well as the minutes of the stockholders’ and Directors’ meetings.
Management’s Assessment of Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Petrosearch’s internal control system was designed to provide reasonable assurance to the Company’s Management and Directors regarding the preparation and fair presentation of published financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. This assessment was based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we believe that as of December 31, 2008 the Company’s internal control over financial reporting is effective based on those criteria.
This annual report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to the rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.
Changes in Internal Control over Financial Reporting
There were no changes in the Company’s internal controls over financial reporting during the fourth quarter of 2008 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
None
PART III
| DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE |
The following table sets forth our Directors and executive officers as of December 31, 2008.
| Name | | Age | | Position |
| | | | | |
| Richard D. Dole | | 63 | | Director, Chairman, President and CEO |
| Wayne Beninger | | 55 | | Chief Operating Officer |
| David Collins | | 40 | | Chief Financial Officer |
| Gerald Agranoff | | 62 | | Director |
| Richard Majeres | | 42 | | 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 Chairman and CEO of Double Eagle Petroleum Company (DBLE, NASDAQ Global Select Market). 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 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.
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 1995. 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.
BOARD OF DIRECTORS AND ITS COMMITTEES
During the fiscal year ended December 31, 2008 the Board of Directors held five meetings. Mr. Dole is our only Director who is also an Officer. Our Board of Directors currently has an Audit Committee and a Compensation Committee which are comprised of independent directors Richard Majeres and Gerald Agranoff. We do not have a Nominating Committee. The entire Board of Directors acts as our Nominating Committee.
Audit Committee
Our Audit Committee is made up of our two independent Board members, Mr. Richard Majeres and Mr. Gerald Agranoff. Mr. Majeres is the Chairman of the Audit Committee and is the designated Financial Expert. During the fiscal year ended December 31, 2008 the Audit Committee held four meetings.
Compensation Committee
On March 23, 2007 our Board of Directors approved the formation of a Compensation Committee made up of our two independent Directors, Mr. Gerald Agranoff and Mr. Richard Majeres. Mr. Agranoff was designated the Chairman of the Compensation Committee. During the fiscal year ended December 31, 2008 the Compensation Committee held three meetings.
Security Holders Recommendations to Board of Directors
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 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 filed with the SEC on August 23, 2005.
The following table sets forth certain compensation information for the following individuals for fiscal years ended December 31, 2008 and 2007. No other compensation was paid to our named executive officers other than the compensation set forth below.
Name and Principal Position (a) | | Title | | Year (b) | | Salary ($) (c) | | | Bonus ($) (d) | | | Stock Awards ($) (e) | | | Option Awards ($) (f) | | | Non-Equity Incentive Plan Compensation ($) (g) | | | Nonqualified Deferred Compensation Earnings ($) (h) | | | All other compensation ($) (i) | | | Total ($) (j) | |
| | | Chairman, | | 2008 | | $ | 250,000 | | | $ | 150,000 | | | $ | 100,000 | | | | -0- | | | | -0- | | | | -0- | | | | -0- | | | $ | 500,000 | |
Richard Dole(1) | | CEO and President | | 2007 | | $ | 223,750 | | | $ | 120,000 | | | | -0- | | | | -0- | | | | -0- | | | | -0- | | | | -0- | | | $ | 343,750 | |
| | | | | 2008 | | $ | 215,000 | | | $ | 86,250 | | | $ | 58,750 | | | | -0- | | | | -0- | | | | -0- | | | | -0- | | | $ | 360,000 | |
David Collins (2) | | CFO | | 2007 | | $ | 201,875 | | | $ | 65,000 | | | | -0- | | | | -0- | | | | -0- | | | | -0- | | | | -0- | | | $ | 266,875 | |
| | | | | 2008 | | $ | 250,000 | | | $ | 86,250 | | | $ | 58,750 | | | | -0- | | | | -0- | | | | -0- | | | | -0- | | | $ | 395,000 | |
Wayne Beninger (3) | | COO | | 2007 | | $ | 250,000 | | | $ | 55,000 | | | | -0- | | | | | | | | | | | | | | | | | | | $ | 305,000 | |
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 became an employee of the Company as of January 1, 2005. Mr. Dole renewed his employment agreement with the Company in May 2007 for a term of one year which calls for compensation of $20,833 per month. |
| (2) | 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 renewed his employment agreement with the Company May 1, 2007, for a term of one year which calls for compensation of $17,916 per month. |
| (3) | Mr. Beninger was appointed Chief Operating Officer and became an employee of the Company as of May 1, 2005. Mr. Beninger renewed his employment agreement with the Company May 1, 2007, for a term of one year which calls for compensation of $20,830 per month. |
EMPLOYMENT AGREEMENTS
The employment contracts in existence with officers and key personnel include employment contracts with each of Richard Dole (Chairman, President and CEO), David Collins (Chief Financial Officer) and Wayne Beninger, (Chief Operating Officer). These employment agreements became effective May 1, 2007 and were amended and restated as of September 2, 2008. In determining to amend the executive officers employment agreements, the Board of Directors considered, among other factors, that (i) the substantial reduction in the aforementioned severance obligations (in excess of $1.1 million) would make the company more attractive to a potential strategic partner and (ii) the changes in the employment agreements would ensure an environment that allows the executive officers to objectively evaluate and effect all potential strategic alternatives which may arise.
The amended and restated employment contracts with Messrs. Dole, Collins and Beninger provide for an employment term of two years, expiring on May 1, 2009. Each of the amended and restated employment contracts provides for termination by the Company upon death or disability, with six month severance payments for Messrs Collins and Beninger and 12 month severance for Mr. Dole. Each of the amended and restated employment contracts permits termination by the Company for cause, which includes malfeasance, misuse of funds, insubordination, competing with the Company, 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, under the amended and restated agreements, each executive officer has agreed to a fixed sum payable upon certain triggering events which sum, in the aggregate, is substantially less than the sum payable under the pre-amendment agreements. The triggering events which give rise to each officer’s severance amount are any of the following events: (i) the employment agreement is terminated by the Company without “cause”, (ii) the employee terminates his employment for “good reason”, (iii) the employee’s employment is voluntarily (by the employee) or involuntarily terminated upon a “Change in Control”, or (iv) the agreement expires (on April 30, 2009) without the occurrence of any of the events listed in (i), (ii) or (iii) above. With respect to Mr. Beninger and Mr. Collins, the fixed severance amount is $550,000. With respect to Mr. Dole, the fixed severance amount is $850,000.
Outstanding Equity Awards at Fiscal Year End 2008:
| | | OPTION AWARDS | | STOCK AWARDS |
Name (a) | | Number of Securities Underlying Unexercised Options (#) Exercisable (b) | | Number of Securities Underlying Unexercised Options (#) Unexercisable (c) | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) (d) | | Option Exercise Price ($) (e) | | Option Expiration Date (f) | | Number of Shares or Units of Stock that have not Vested (#) (g) | | Market Value of Shares or Units of Stock that have not Vested ($) (h) | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that have not Vested ($) (i) | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights that have not Vested ($) (j) |
| None | | | | | | | | | | | | | | | | | | |
LONG-TERM INCENTIVE PLANS
We currently have no Long-Term Incentive Plans.
DIRECTOR COMPENSATION
For the year ending December 31, 2008, the Board of Directors approved compensation of $75,000 to independent board members, Gerald Agranoff and Richard Majeres, for their services for 2008. This amount was to be paid at least one-third in stock with the balance in cash; with the cash paid quarterly and the balance paid by the issuance of shares of our restricted common stock.
Name (a) | | Fees Earned or Paid in Cash ($) (b) | | | Stock Awards ($) (c) | | | Option Awards ($) (d) | | | Non-Equity Incentive Plan Compensation ($) (e) | | | Nonqualified Deferred Compensation Earnings ($) (f) | | | All Other Compensation ($) (g) | | | Total ($) (h) | |
| Gerald Agranoff | | $ | 50,000 | | | $ | 25,000 | | | | -0- | | | | -0- | | | | -0- | | | | -0- | | | $ | 75,000 | |
| Richard Majeres | | $ | 37,500 | | | $ | 37,500 | | | | -0- | | | | -0- | | | | -0- | | | | -0- | | | $ | 75,000 | |
| SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
The following table sets forth certain information at March 5, 2009 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 (based upon reports which have been filed and other information known to us), (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 5, 2009 we had 41,310,578 (net of 1,117,973 treasury shares) shares of common stock issued and outstanding.
| Title of class | | Name and address of beneficial owner | | Amount and Nature of Beneficial Ownership | | | Percentage of Common Stock (1) | |
| Common Stock | | Richard D. Dole Chairman, President and CEO 675 Bering Drive, Suite 200 Houston, Texas 77057 | | | 487,016 | (2) | | | 1.15 | % |
| Common Stock | | Wayne Beninger Chief Operating Officer 675 Bering Drive, Suite 200 Houston, Texas 77057 | | | 376,579 | (3) | | | 0.89 | % |
| Common Stock | | David J. Collins Vice President and Chief Financial Officer 675 Bering Drive, Suite 200 Houston, Texas 77057 | | | 769,073 | (4) | | | 1.81 | % |
| Common Stock | | Gerald Agranoff Director 675 Bering Drive, Suite 200 Houston, Texas 77057 | | | 55,893 | (5) | | | 0.13 | % |
| Common Stock | | Richard Majeres Director 675 Bering Drive, Suite 200 Houston, Texas 77057 | | | 178,364 | (6) | | | 0.42 | % |
| | | | | | | | | | | |
| | | All Officers and Directors as a group (total of 5) | | | 1,866,925 | (7) | | | 4.40 | % |
| | | | | | | | | | | |
| Common Stock | | Commonwealth Bank of Australia 48 Martin Place, Level 2 Sydney NSW 2000, Australia | | | 3,850,000 | (8) | | | 9.07 | % |
| Common Stock | | Ironman Energy Master Fund 2211 Norfolk, Suite 611 Houston, Texas 77098 | | | 2,541,459 | (9) | | | 5.99 | % |
| Common Stock | | Wellington Trust Company, NA 75 State Street Boston, MA 02109 | | | 2,455,871 | (10) | | | 5.79 | % |
| Common Stock | | Allen Crosswell 2121 Sage, Suite 290 Houston, TX 77056 | | | 3,000,488 | (11) | | | 7.07 | % |
(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 5, 2009. As of March 5, 2009 there were 41,310,578 (net of 1,117,973 treasury shares) shares of our common stock issued and outstanding.
(2) Includes 487,016 shares of common stock held directly.
(3) Includes 376,579 shares of common stock held directly.
(4) Includes 769,073 shares of common stock held directly.
(5) Includes 55,893 shares of common stock held directly.
(6) Includes 178,364 shares of common stock held directly.
(7) Includes 1,866,925 shares of common stock held directly.
(8) Includes the following: 2,790,000 shares held by First State Investments Global Resources Long Short Fund Limited; and 500,000 shares held by Colonial First State Wholesale Global Resources Long Short Fund; and 401,000 shares held by First State Investments Global Energy Long Short Master Fund; and 159,000 shares held by Colonial First State Wholesale Global Energy Long Short Fund.
(9) Includes 2,425,259 shares owned by Ironman Energy Master Fund and 116,200 shares owned by Ironman PI Fund (QP), LP.
(10) Includes 2,455,871 owned by Wellington Trust Company, NA
(11) Includes 2,421,738 shares owned directly by Allen Crosswell and 578,750 shares held by CHLG Funding.
____________________________
| CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
None of the following persons has any direct or indirect material interest in any transaction to which we were or are a party since the beginning of our last fiscal year, 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. |
Director Independence
Two of our Board of Directors, Mr. Gerald Agranoff and Mr. Richard Majeres, are independent Board members
| PRINCIPAL ACCOUNTING FEES AND SERVICES |
The following table sets forth the aggregate fees paid or accrued for professional services rendered by Ham, Langston & Brezina, L.L.P. for the audit of our annual financial statements for fiscal year 2008 and fiscal year 2007 and the aggregate fees paid or accrued for audit-related services and all other services rendered by Ham, Langston & Brezina, L.L.P. for fiscal year 2008 and fiscal year 2007.
| | | 2008 | | | 2007 | |
| | | | | | | |
| Audit fees | | $ | 80,400 | | | $ | 105,700 | |
| Audit-related fees | | | 0 | | | | 0 | |
| Tax fees | | | 4,500 | | | | 17,000 | |
| All other fees | | | 7,017 | | | | 2,275 | |
| | | | | | | | | |
| Total | | $ | 91,917 | | | $ | 124,975 | |
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, L.L.P. was compatible with the maintenance of that firm’s independence in the conduct of its auditing functions.
| EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
Exhibit Number | Description |
| | |
| 3.1 | Articles of Incorporation of Petrosearch Energy Corporation (1) |
| 3.2 | Bylaws of Petrosearch Energy Corporation (1) |
| 3.3 | Articles of Merger (1) |
| 4.1 | Share Purchase Agreement dated January 24, 2005 with CBarney Investments (1) |
| 4.2 | Amended Share Purchase Agreement dated April 19, 2005 with CBarney Investments (1) |
| 4.3 | Share Purchase Agreement dated January 24, 2005 with Mark X (1) |
| 4.4 | Amended Share Purchase Agreement dated April 19, 2005 with Mark X (1) |
| 4.5 | Share Purchase Agreement with Mark 1 dated November 24, 2004 (1) |
| 4.6 | Common Stock Purchase Warrant [Form Of] (1) |
| 4.7 | Subscription and Registration Rights Agreement [Form Of] (1) |
| 10.1 | Revolving Credit Facility dated October 1, 2004 with Fortuna Asset Management (1) |
| 10.2 | Revolving Credit Note dated October 2004 with Fortuna Energy, L.P. (1) |
| 10.3 | Assignment of Overriding Royalty Interest (Fortuna Energy, L.P.) dated October 2004 (1) |
| 10.4 | Pledge Agreement (Fortuna Energy, L.P.) dated October 2004 (1) |
| 10.5 | Master Deed of Trust (Fortuna) dated October 2004 (1) |
| 10.6 | Amended and Restated Revolving Credit Note with Fortuna Energy, LP dated September 29, 2005 (5) |
| 10.7 | Amended and Restated Revolving Credit Agreement with Fortuna Energy, LP dated September 29, 2005 (5) |
| 10.8 | Warrant Agreement (Fortuna Energy, LP dated September 29, 2005 (5) |
| 10.9 | Joint Operating Agreement [Form Of] (1) |
| 10.10 | Employment Agreement dated November 15, 2004 with Richard Dole (1) |
| 10.11 | Employment Agreement dated May 1, 2005 with Wayne Beninger (1) |
| 10.12 | Employment Agreement dated May 1, 2005 with David Collins (1) |
| 10.13 | Gas Purchase, Gathering, Treating and Processing Agreement with Bear Paw Energy, LLC |
| | dated December 1, 2003 (2) |
| 10.14 | Crude Oil Purchase Contract with Plains Marketing, L.P. dated January 25, 2005 (2) |
| 10.15 | Lease Purchase Contract with Eighty Eight Oil, LLC dated November 1, 2003 (2) |
| 10.16 | Asset Purchase Agreement with Quinduno Energy dated October 18, 2005 (6) |
| 10.17 | Agreement with Rock Energy Partners Operating, L.P. and Rock Energy Partners, L.P. dated January 11, 2006 (7) |
| 10.18 | Amended Right of First Refusal Agreement with Rock Energy Partners Operating, L.P. and Rock Energy Partners, L.P. dated January 11, 2006 (7) |
| 10.19 | Subscription Agreement (Form Of) (8) |
| 10.20 | Warrant Agreement (Form Of) (8) |
| 10.21 | Extension Agreement with ExxonMobil Corporation dated March 30, 2006 (9) |
| 10.22 | Second Amended and Restated Program Agreement with Harding Company dated August 29, 2006 (10) |
| 10.23 | Second Amendment to Petrosearch-Garwood Agreement dated September 21, 2006 (11) |
| 10.24 | Option Agreement with Rock Energy Partners dated September 21, 2006 (12) |
| 10.25 | Securities Purchase Agreement dated November 1, 2006, by and between Garwood Petrosearch, Inc. and Laurus Master Fund, Ltd. (12) |
| 10.26 | Secured Term Note dated November 1, 2006, by and between Garwood Petrosearch, Inc. and Laurus Master Fund, Ltd. (12) |
| 10.27 | Stock Pledge Agreement dated November 1, 2006, by and between Petrosearch Energy Corporation and Laurus Master Fund, Ltd. (12) |
| 10.28 | Master Security Agreement dated November 1, 2006, by Garwood Petrosearch, Inc. (12) |
| 10.29 | Deed of Trust dated November 1, 2006 by Garwood Petrosearch, Inc. (12) |
| 10.30 | Common Stock Purchase Warrant dated November 1, 2006, by Garwood Petrosearch, Inc. (12) |
| 10.31 | Partnership Agreement dated December 15, 2006 (DDJET) (13) |
| 10.32 | Note and Warrant Purchase Agreement with RCH Petro Investors, LP dated February 1, 2007 (14) |
| 10.33 | 8% Senior Secured Convertible Note dated February 7, 2007 (RCH Petro Investors, LP) (14) |
| 10.34 | Pledge and Security Agreement dated February 7, 2007 (RCH Petro Investors, LP) (14) |
| 10.35 | Registration Rights Agreement dated February 7, 2007 (RCH Petro Investors, LP) (14) |
| 10.36 | Warrant Agreement dated February 7, 2007 (RCH Petro Investors) (14) |
| 10.37 | Employment Agreement of Richard D. Dole (15) |
| 10.38 | Employment Agreement of Wayne Beninger (15) |
| 10.39 | Employment Agreement of David Collins (15) |
| 10.40 | Note and Warrant Purchase Agreement dated November 9, 2007(16) |
| 10.41 | 8% Senior Secured Convertible Note dated November 9, 2007 (Form of) (16) |
| 10.42 | Pledge and Security Agreement dated November 9, 2007(16) |
| 10.43 | Registration Rights Agreement dated November 9, 2007(16) |
| 10.44 | Warrant Agreement dated November 9, 2007 (Form of) (16) |
| 10.45 | Investment Banking Agreement with Arabella Securities (17) |
| 10.46 | Extension to Employment Agreement – Wayne Beninger(20) |
| 10.47 | Extension to Employment Agreement – David Collins(20) |
| 10.48 | Amended and Restated Employment Agreement of Richard Dole(21) |
| 10.49 | Amended and Restated Employment Agreement of Wayne Beninger(21) |
| 10.50 | Amended and Restated Employment Agreement of David Collins(21) |
| 14.1 | Code of Ethics (4) |
| List of Subsidiaries * |
| Consent of Ryder Scott Company, March 9, 2009 * |
| 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.* |
| 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.* |
| 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.* |
| 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.* |
Footnotes to Exhibits:
| * | Filed herewith. |
| 1 | Previously filed as an exhibit to our Form SB-2 Registration Statement on June 6, 2005 and incorporated herein by reference. |
| 2 | Previously filed as an exhibit to our Form SB-2/A Amendment No. 1 Registration Statement on August 1, 2005 and incorporated herein by reference. |
| 3 | Previously filed as an exhibit to our Form SB-2/A, Amendment No. 2 Registration Statement on August 5, 2005 and incorporated herein by reference. |
| 4 | Previously filed as an exhibit to our Form SB-2/A, Amendment No. 3 Registration Statement on August 23, 2005 and incorporated herein by reference. |
| 5 | Previously filed as an exhibit to our current report on Form 8-K filed October 4, 2005 and incorporated herein by reference. |
| 6 | Previously filed as an exhibit to our current report on Form 8-K filed November 2, 2005 and incorporated herein by reference. |
| 7 | Previously filed as an exhibit to our current report on Form 8-K filed January 18, 2006 and incorporated herein by reference. |
| 8 | Previously filed as an exhibit to our current report on Form 8-K filed February 9, 2006 and incorporated herein by reference. |
| 9 | Previously filed as an exhibit to our current report on Form 8-K filed April 3, 2006 and incorporated herein by reference. |
| 10 | Previously filed as an exhibit to our current report on Form 8-K filed September 5, 2006 and incorporated herein by reference. |
| 11 | Previously filed as an exhibit to our current report on Form 8-K filed September 27, 2006 and incorporated herein by reference. |
| 12 | Previously filed as an exhibit to our current report on Form 8-K filed November 7, 2006 and incorporated herein by reference. |
| 13 | Previously filed as an exhibit to our current report on Form 8-K filed December 20, 2006 and incorporated herein by reference. |
| 14 | Previously filed as an exhibit to our current report on Form 8-K filed February 7, 2007 and incorporated herein by reference. |
| 15 | Previously filed as an exhibit to our Form 8-K filed on June 7, 2007 and incorporated herein by reference. |
| 16 | Previously filed as an exhibit to our current report on Form 8-K filed November 13, 2007 and incorporated herein by reference. |
| 17 | Previously filed as an exhibit to our Form SB-2/A, Amendment No. 2 Registration Statement on July 3, 2007 and incorporated herein by reference |
| 18 | Previously filed as an exhibit to our Form SB-2 Registration Statement on February 1, 2008 and incorporated herein by reference. |
| 19 | Previously filed as an exhibit to our Form S-1/A Registration Statement on April 17, 2008 |
| 20 | Previously filed as an exhibit to our Form S-1/A Registration Statement on May 22, 2008 |
| 21 | Previously filed as an exhibit to our Form 8-K filed on June 30, 2008 |
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 25, 2009.
PETROSEARCH ENERGY CORPORATION
By /s/ Richard D. Dole
Richard D. Dole
President and Chief Executive Officer
In accordance with the requirements of the Securities Act of 1933, this Form 10-K 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 25, 2009 |
| Richard D. Dole | and Chairman of the Board | |
| | | |
| | | |
| | | |
| By /s/ David J. Collins | Chief Financial Officer, | March 25, 2009 |
| David J. Collins | Chief Accounting Officer, | |
| | and Principal Financial Officer | |
| | | |
| | | |
| | | |
| By /s/ Gerald Agranoff | Director | March 25, 2009 |
| Gerald Agranoff | | |
| | | |
| | | |
| | | |
| By /s/ Richard Majeres | Director | March 25, 2009 |
| Richard Majeres | | |
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, 2008 and 2007 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the 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, 2008 and 2007, 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 24, 2009
PETROSEARCH ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31, 2008 and December 31, 2007
| ASSETS | | December 31, 2008 | | | December 31, 2007 | |
| | | | | | | |
| Current assets: | | | | | | |
| Cash and cash equivalents | | $ | 12,810,370 | | | $ | 8,033,611 | |
| Accounts receivable: | | | | | | | | |
| Joint owners-billed, net of allowance of $50,148 at December 31, 2008 And $62,179 at December 31, 2007 | | | 146 | | | | 203,671 | |
| Joint owners-unbilled | | | 59 | | | | 3,568 | |
| Oil and gas production sales | | | 33,510 | | | | 319,926 | |
| Prepaid expenses and other current assets | | | 482,970 | | | | 987,155 | |
| Total current assets | | | 13,327,055 | | | | 9,547,931 | |
| | | | | | | | | |
| Property and equipment: | | | | | | | | |
| Oil and gas properties, full cost method of accounting: | | | | | | | | |
| Properties subject to amortization | | | 24,668,141 | | | | 33,235,534 | |
| Properties not subject to amortization | | | - | | | | 7,099,601 | |
| Other property and equipment | | | 153,031 | | | | 153,031 | |
| Total | | | 24,821,172 | | | | 40,488,166 | |
| Less accumulated depreciation, depletion and amortization | | | (19,136,640 | ) | | | (3,266,658 | ) |
| Total property and equipment, net | | | 5,684,532 | | | | 37,221,508 | |
| | | | | | | | | |
| Prepaid oil and gas costs | | | - | | | | 1,432,906 | |
| | | | | | | | | |
| Deferred tax asset | | | 3,454,071 | | | | - | |
| | | | | | | | | |
| Other assets | | | 247,474 | | | | 834,287 | |
| | | | | | | | | |
| Total assets | | $ | 22,713,132 | | | $ | 49,036,632 | |
| | | | | | | | | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | |
| | | | | | | | | |
| Current liabilities: | | | | | | | | |
| Current portion of long-term debt | | $ | - | | | $ | 2,066,087 | |
| Accounts payable | | | 329,810 | | | | 960,020 | |
| Accrued liabilities for Barnett property costs | | | - | | | | 2,379,073 | |
| Accrued liabilities | | | 337,463 | | | | 1,582,689 | |
| Warrants subject to mandatory redemption | | | - | | | | 321,140 | |
| Total current liabilities | | | 667,273 | | | | 7,309,009 | |
| | | | | | | | | |
| Long-term debt, net of current portion – Kallina | | | - | | | | 6,919,890 | |
| Convertible debt | | | - | | | | 13,914,013 | |
| Other long-term obligations | | | 776,870 | | | | 699,914 | |
| Total liabilities | | | 1,444,143 | | | | 28,842,826 | |
| | | | | | | | | |
| 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 authorized; 227,245 shares issued and outstanding at December 31, 2008 and 483,416 shares issued and outstanding at December 31, 2007 | | | 227,245 | | | | 483,416 | |
| Series B convertible preferred stock, 100,000 shares authorized; 43,000 shares issued and outstanding at December 31, 2008 and December 31, 2007 | | | 43,000 | | | | 43,000 | |
| Common stock, par value $0.001 per share, 100,000,000 shares Authorized; 42,425,679 and 40,941,841 shares issued and outstanding at December 31, 2008 and December 31, 2007, respectively | | | 42,426 | | | | 40,941 | |
| Additional paid-in capital | | | 34,447,694 | | | | 33,196,588 | |
| Un-issued common stock | | | - | | | | 288,172 | |
| Accumulated deficit | | | (13,446,688 | ) | | | (13,858,311 | ) |
| Less 214,800 treasury shares, at cost | | | (44,688 | ) | | | - | |
| Total stockholders' equity | | | 21,268,989 | | | | 20,193,806 | |
| | | | | | | | | |
| Total liabilities and stockholders' equity | | $ | 22,713,132 | | | $ | 49,036,632 | |
The accompanying notes are an integral part of these consolidated financial statements
PETROSEARCH ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
for the years ended December 31, 2008 and 2007
| | | Year Ended | |
| | | December 31, | |
| | | 2008 | | | 2007 | |
| | | | | | | |
| Oil and gas production revenues | | $ | 1,400,480 | | | $ | 1,827,664 | |
| | | | | | | | | |
| Operating costs and expenses: | | | | | | | | |
| Lease operating and production taxes | | | 808,172 | | | | 731,915 | |
| Depreciation, depletion and amortization | | | 577,394 | | | | 909,311 | |
| Impairment of oil and gas properties | | | 15,713,886 | | | | - | |
| General and administrative | | | 3,112,047 | | | | 3,022,739 | |
| | | | | | | | | |
| Total costs and expenses | | | 20,211,499 | | | | 4,663,965 | |
| | | | | | | | | |
| Operating loss | | | (18,811,019 | ) | | | (2,836,301 | ) |
| | | | | | | | | |
| Other income / (expense): | | | | | | | | |
| Interest income | | | 179,642 | | | | 230,951 | |
| Interest expense | | | (1,348,940 | ) | | | (1,905,066 | ) |
| Amortization of financing costs and debt discount | | | (1,444,009 | ) | | | (2,021,628 | ) |
| Gain on sale of DDJET interest | | | 21,814,753 | | | | - | |
| Loss on extinguishment of debt | | | (3,445,265 | ) | | | - | |
| Change in value of warrant liability | | | 12,390 | | | | (3,388 | ) |
| | | | | | | | | |
| Total other income / (expense), net | | | 15,768,571 | | | | (3,699,131 | ) |
| | | | | | | | | |
| Loss before provision for income taxes | | | (3,042,448 | ) | | | (6,535,432 | ) |
| | | | | | | | | |
| Deferred tax (expense)/benefit | | | 3,454,071 | | | | - | |
| | | | | | | | | |
| Net income (loss) | | $ | 411,623 | | | $ | (6,535,432 | ) |
| | | | | | | | | |
| Basic and diluted net loss per common share | | $ | 0.01 | | | $ | (0.17 | ) |
| | | | | | | | | |
| Weighted average common shares | | | 41,797,282 | | | | 39,476,379 | |
The accompanying notes are an integral part of these consolidated financial statements
PETROSEARCH ENERGY CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
For the years ended December 31, 2008 and 2007
| | | | | | Series A | | | Series B | | | Additional | | | Unissued | | | | | | Total Stock- | |
| | | Common Stock | | | Preferred Stock | | | Preferred Stock | | | Paid-In | | | Common | | | Accumulated | | | Holders | |
| | | Shares | | | Amount | | | Shares | | | Amount | | | Shares | | | Amount | | | Capital | | | Stock | | | Deficit | | | Equity | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2006 | | | 37,927,070 | | | $ | 37,927 | | | | 483,416 | | | $ | 483,416 | | | | 43,000 | | | $ | 43,000 | | | $ | 23,928,090 | | | $ | 771,429 | | | $ | (7,322,879 | ) | | $ | 17,940,983 | |
| Issuance of common stock committed, net of additional costs of raising capital | | | 771,429 | | | | 771 | | | | | | | | | | | | | | | | | | | | 751,315 | | | | (771,429 | ) | | | | | | | (19,343 | ) |
| Common stock issued for leasehold costs | | | 1,700,000 | | | | 1,700 | | | | | | | | | | | | | | | | | | | | 1,675,300 | | | | | | | | | | | | 1,677,000 | |
| Common stock issued for employee compensation | | | 25,000 | | | | 25 | | | | | | | | | | | | | | | | | | | | 20,725 | | | | | | | | | | | | 20,750 | |
| Common stock issued for services | | | 50,000 | | | | 50 | | | | | | | | | | | | | | | | | | | | 61,926 | | | | | | | | | | | | 61,976 | |
| Common stock issued for interest expense | | | 437,308 | | | | 437 | | | | | | | | | | | | | | | | | | | | 574,460 | | | | | | | | | | | | 574,897 | |
| Common stock issued for board compensation | | | 31,034 | | | | 31 | | | | | | | | | | | | | | | | | | | | 44,969 | | | | | | | | | | | | 45,000 | |
| Common stock committed for interest expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 288,172 | | | | | | | | 288,172 | |
| Issuance of warrants with debt | | | | | | | | | | | | | | | | | | | | | | | | | | | 3,471,835 | | | | | | | | | | | | 3,471,835 | |
| Beneficial conversion feature of convertible debt | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,667,968 | | | | | | | | | | | | 2,667,968 | |
| Net loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (6,535,432 | ) | | | (6,535,432 | ) |
| Balance at December 31, 2007 | | | 40,941,841 | | | $ | 40,941 | | | | 483,416 | | | $ | 483,416 | | | | 43,000 | | | $ | 43,000 | | | $ | 33,196,588 | | | $ | 288,172 | | | $ | (13,858,311 | ) | | $ | 20,193,806 | |
The accompanying notes are an integral part of these consolidated financial statements
PETROSEARCH ENERGY CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
For the years ended December 31, 2008 and 2007
| | | | | | | | | Series A | | | Series B | | | Additional | | | Unissued | | | | | | | | | Total Stock- | |
| | | Common Stock | | | Preferred Stock | | | Preferred Stock | | | Paid-In | | | Common | | | Treasury | | | Accumulated | | | Holders | |
| | | Shares | | | Amount | | | Shares | | | Amount | | | Shares | | �� | Amount | | | Capital | | | Stock | | | Stock | | | Deficit | | | Equity | |
| Balance at December 31, 2007 | | | 40,941,841 | | | $ | 40,941 | | | | 483,416 | | | $ | 483,416 | | | | 43,000 | | | $ | 43,000 | | | $ | 33,196,588 | | | $ | 288,172 | | | $ | - | | | $ | (13,858,311 | ) | | $ | 20,193,806 | |
| Issuance of common stock committed | | | 297,085 | | | | 298 | | | | | | | | | | | | | | | | | | | | 287,874 | | | | (288,172 | ) | | | | | | | | | | | - | |
| Common stock issued for interest expense | | | 501,448 | | | | 501 | | | | | | | | | | | | | | | | | | | | 401,125 | | | | | | | | | | | | | | | | 401,626 | |
| Common stock issued for employee and board compensation | | | 645,893 | | | | 646 | | | | | | | | | | | | | | | | | | | | 313,104 | | | | | | | | | | | | | | | | 313,750 | |
| Conversion of preferred stock to common stock | | | 39,412 | | | | 40 | | | | (256,171 | ) | | | (256,171 | ) | | | | | | | | | | | 256,131 | | | | | | | | | | | | | | | | - | |
| Additional costs of raising capital | | | | | | | | | | | | | | | | | | | | | | | | | | | (7,128 | ) | | | | | | | | | | | | | | | (7,128 | ) |
| Repurchase of common stock | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (44,688 | ) | | | | | | | (44,688 | ) |
| Net income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 411,623 | | | | 411,623 | |
| Balance at December 31, 2008 | | | 42,425,679 | | | $ | 42,426 | | | | 227,245 | | | $ | 227,245 | | | | 43,000 | | | $ | 43,000 | | | $ | 34,447,694 | | | $ | - | | | $ | (44,688 | ) | | $ | (13,446,688 | ) | | $ | 21,268,989 | |
The accompanying notes are an integral part of these consolidated financial statements.
PETROSEARCH ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
For the years ended December 31, 2008 and 2007
| | | 2008 | | | 2007 | |
| Cash flows from operating activities: | | | | | | |
| Net income (loss) | | $ | 411,623 | | | $ | (6,535,432 | ) |
| Adjustments to reconcile net loss to net cash used in operating activities: | | | | | | | | |
| Depletion, depreciation and amortization expense | | | 577,394 | | | | 909,311 | |
| Gain on sale of oil and gas properties | | | (21,814,753 | ) | | | - | |
| Impairment of oil and gas properties | | | 15,713,886 | | | | - | |
| Stock-based compensation and interest expense | | | 715,376 | | | | 990,795 | |
| Amortization of deferred rent | | | (8,995 | ) | | | (5,082 | ) |
| Amortization of debt discount and beneficial conversion feature | | | 1,173,497 | | | | 1,644,124 | |
| Amortization of financing costs | | | 270,512 | | | | 377,504 | |
| Accretion of asset retirement obligation | | | 37,314 | | | | 33,433 | |
| Change in value of warrant liability | | | (12,390 | ) | | | 3,388 | |
| Bad debt expense | | | - | | | | 25,000 | |
| Deferred tax benefit | | | (3,454,071 | ) | | | - | |
| Loss on extinguishment of debt | | | 3,445,104 | | | | - | |
| Changes in operating assets and liabilities: | | | | | | | | |
| Accounts receivable | | | 493,450 | | | | 30,537 | |
| Prepaid expenses and other assets | | | (53,495 | ) | | | (344,140 | ) |
| Accounts payable and accrued liabilities | | | (515,247 | ) | | | 865,391 | |
| Trade note payable | | | - | | | | (409,819 | ) |
| | | | | | | | | |
| Net cash used in operating activities | | | (3,020,795 | ) | | | (2,414,990 | ) |
| | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | |
| Proceeds from sale of Barnett interest | | | 36,000,000 | | | | - | |
| Capital expenditures, including purchases and development of properties | | | (6,931,880 | ) | | | (9,082,326 | ) |
| | | | | | | | | |
| Net cash used provided by (used in) investing activities | | | 29,068,120 | | | | (9,082,326 | ) |
| | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | |
| Additional costs of raising capital | | | (7,128 | ) | | | (19,343 | ) |
| Purchase of treasury stock | | | (44,688 | ) | | | - | |
| Payment of warrant liability | | | (308,750 | ) | | | - | |
| Proceeds from convertible debt | | | - | | | | 18,100,000 | |
| Repayment of notes payable | | | (20,910,000 | ) | | | (2,265,348 | ) |
| | | | | | | | | |
| Net cash (used in) provided by financing activities | | | (21,270,566 | ) | | | 15,815,309 | |
| | | | | | | | | |
| Net increase in cash and cash equivalents | | | 4,776,759 | | | | 4,317,993 | |
| | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 8,033,611 | | | | 3,715,618 | |
| | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 12,810,370 | | | $ | 8,033,611 | |
| | | | | | | | | |
| Supplemental disclosures of cash flow information: | | | | | | | | |
| Interest paid | | $ | 551,217 | | | $ | 399,315 | |
| | | | | | | | | |
| Income taxes paid | | | - | | | | - | |
The accompanying notes are an integral part of these consolidated financial statements.
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 crude oil and natural gas exploration and production company based in Houston, Texas, with a second office in Dallas, Texas. The Company is the successor of Petrosearch Corporation, a Texas corporation formed in August 2003. The Company’s current operations are focused in North Texas with existing production in Texas and Oklahoma. A majority of the Company’s effort since the sale of its Barnett Shale Project in June, 2008 has been to focus on pursuing strategic alternatives for the Company that will create the most value for its shareholders, as well as focusing on the development of the Company’s Texas Panhandle water flood that it operates .
Principles of Consolidation
The consolidated financial statements presented herein include the accounts of the Company and its wholly-owned subsidiaries. In addition, during 2008 and 2007, the consolidated financial statements of the Company include its pro-rata share of the accounts of the DDJET Limited LLP Partnership, in which the company had a 5.54 percent ownership interest until the time of sale in 2008. 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. The Company’s most significant financial estimates are based on remaining proved natural gas and oil reserves. Estimates of proved reserves are key components of the Company’s depletion rate for natural gas and oil properties and its full cost ceiling test limitation. In addition, estimates are used in computing taxes, preparing accruals of operating costs and production revenues, asset retirement obligations and fair value of stock options and the related compensation expense. See Note 14 — Supplemental Oil and Gas Information (Unaudited) for more information relating to estimates of proved reserves. Because there are numerous uncertainties inherent in the estimation process, actual results could differ materially from these estimates.
Business Segments
The Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) 131, “Disclosures about Segments of an Enterprise and Related Information” establishes standards for reporting information about operating segments. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses. Operating segments have separate financial information and this information is regularly evaluated by the chief decision maker for the purpose of allocating resources and assessing performance.
Segment reporting is not applicable for the Company as each of its operating areas has similar economic characteristics and each meets the criteria for aggregation as defined in SFAS 131. All of the Company’s operations involve the exploration, development and production of natural gas and oil, and all of its operations are located in the United States. The Company has a single, company-wide management team that administers all properties as a whole rather than as discrete operating segments. The Company tracks only basic operational data by area, and does not maintain comprehensive financial statement information by area. The Company measures financial performance as a single enterprise and not on an area-by-area basis. Throughout the year, the Company freely allocates capital resources on a project-by-project basis across its entire asset base to maximize profitability without regard to individual areas or segments.
Oil and Gas Properties
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. Development costs capitalized include costs incurred to provide improved recovery systems such as the cost to drill injection wells. In addition, if the materials injected in the reservoir under improved recovery techniques are deemed to be of benefit over the life of the entire project, the costs of the materials are capitalized and amortized along with the wells and related facilities.
Production costs incurred to operate and maintain wells and related equipment and facilities become part of the cost of oil and gas produced and are expensed during the period incurred. Production costs for the Company’s waterflood properties includes a maximum $15,000 monthly operating expense for maintenance of the water treatment facility. In addition, production costs include any other costs to inject nonrecoverable materials into the reservoir under improved recovery techniques when related to current production.
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.
The following table reflects the depletion expense incurred from oil and gas properties during the years ended December 31, 2008 and 2007:
| | | 2008 | | | 2007 | |
| | | | | | | |
| Depletion Expense | | $ | 546,783 | | | $ | 879,171 | |
| Depletion expense per BOE produced | | $ | 23.61 | | | $ | 24.41 | |
At December 31, 2007, unproved oil and gas properties not subject to amortization included $7,099,601 of property acquisition, exploration and development costs that are not being amortized. Unproved leasehold costs at December 31, 2007 consisted of interest in leases located in Mississippi, Oklahoma and Texas. All of the costs were reclassified to the amortizable base in 2008 when they were evaluated and proved reserves were discovered, impairment was indicated or when the lease terms expired. Other unproved costs at December 31, 2007 were written-off to the full cost pool when the properties were sold in 2008.
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, 2008 and 2007 was $30,611 and $30,140, 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 the Company’s 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.
A reconciliation of the Company’s asset retirement obligation liability is as follows:
| | | As of December 31, | |
| | | 2008 | | | 2007 | |
| Beginning asset retirement obligation | | $ | 804,855 | | | $ | 875,077 | |
| Liabilities incurred | | | 11,276 | | | | 5,798 | |
| Liabilities settled | | | (11,276 | ) | | | (5,732 | ) |
| Revisions in estimated cash flows | | | 1,565 | | | | (103,721 | ) |
| Properties sold | | | (79,211 | ) | | | - | |
| Accretion expense | | | 37,314 | | | | 33,433 | |
| Ending asset retirement obligation | | $ | 764,523 | | | $ | 804,855 | |
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 collectability. 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, 2008 and 2007, the Company provided an allowance of $50,148 and $62,179, respectively, 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, which is the case for financial instruments outstanding as of December 31, 2008 and 2007. 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.
As described below under recently issued accounting pronouncements, the Company adopted FAS 157 on January 1, 2008. FAS 157, among other things, defines fair value, establishes a consistent framework for measuring fair value and expands disclosure for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. FAS 157 clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, FAS 157 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:
| | Level 1. | Observable inputs such as quoted prices in active markets for identical assets or liabilities; |
| | Level 2. | Inputs, other than quoted prices included within Level 1, that are observable either directly or indirectly; and |
| | Level 3. | Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions. |
As of December 31, 2008, the Company did not have any assets or liabilities that are measured at fair value on a recurring basis.
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 is fixed or reliably determinable. As of December 31, 2008 and 2007, the Company has included approximately $132,800 and $185,000, respectively, in its asset retirement obligation liability for future restoration costs on drilled properties.
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 federal depository insurance limit. The Company has not experienced any losses on deposits.
Excluding the Company’s revenue from the DDJET Partnership, which is marketed by the operator of the project and comprises 71% of the Company’s 2008 revenue, 24% of its revenue was received from two customers in 2008. Excluding the Company’s revenue from the DDJET Partnership, which comprises 33% of the Company’s 2007 revenue, 59% of its revenue was received from three customers in 2007.
| | | 2008 | | | 2007 | |
| | | | | | | |
| Customer A | | $ | 167,666 | | | $ | 729,896 | |
| Customer B | | | 27,942 | | | | 194,519 | |
| Customer C | | | 164,912 | | | | 161,919 | |
| DDJET | | | 999,248 | | | | 601,790 | |
| Others | | | 40,712 | | | | 139,540 | |
| | | | | | | | | |
| Total | | $ | 1,400,480 | | | $ | 1,827,664 | |
The Company had no other single customer that accounted for 10% or more of revenues in 2008 or 2007. The Company believes there is a sufficient market to support its revenues in the event the Company was to lose some or all of its current customers given the nature of the high demand of its products.
The Company performs ongoing credit evaluations and generally requires no collateral from its customers or other joint interest owners. As of December 31, 2008, 55% and 30% of accounts receivable from oil and gas sales were from two customers. As of December 31, 2008, 82% of accounts receivable from joint interest owners was from one joint interest owner. No other single customer or joint interest owner accounted for more than 10% of accounts receivable revenue or accounts receivable from joint owners.
Revenue Recognition
The Company uses the entitlements method of accounting for the recognition of natural gas and oil revenues. Under this method of accounting, income is recorded based on the Company’s net revenue interest in production or nominated deliveries. The Company recognizes and records sales gross of production taxes when production is delivered to a specified pipeline point, at which time title and risk of loss are transferred to the purchaser. The Company’s arrangements for the sale of natural gas and oil are evidenced by written contracts with determinable market prices based on published indices. The Company continually reviews the creditworthiness of its purchasers in order to reasonably assure the timely collection of its receivables. Historically, the Company has experienced no material losses on receivables.
Earnings (Loss) Per Share
The Company provides basic and dilutive earnings (loss) per common share information for each year presented. The basic net earnings / (loss) per common share is computed by dividing the net earnings (loss) by the weighted average number of common shares outstanding. Diluted net earnings (loss) per common share is computed by dividing the net earnings (loss), adjusted on an “as if converted” basis, by the weighted average number of common shares outstanding plus potential dilutive securities.
Stock Based Compensation
On January 1, 2006, the Company adopted SFAS 123(R), “Share-Based Payment” using the “modified prospective method” as defined by SFAS 123 (R). SFAS 123(R) requires 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 Statement of Operations based on their fair values. Proforma disclosure is no longer an alternative. Accordingly, the Company now recognizes compensation expense for all stock options.
Capitalized Interest
The Company capitalizes interest 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. Interest capitalized in 2008 and 2007 was $2,089 and $102,625, respectively.
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 assessment as to their realization.
Off Balance Sheet Arrangements
From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2008, the off-balance sheet arrangements and transactions that the Company has entered into include two operating lease agreements for office space. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.
Recently Issued Accounting Pronouncements
SFAS No. 157, “Fair Value Measurements.” In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements. However, in some cases, the application of SFAS No. 157 may change the Company’s current practice for measuring and disclosing fair values under other accounting pronouncements that require or permit fair value measurements. For the Company, SFAS No. 157 is effective as of January 1, 2008 and must be applied prospectively except in certain cases. The adoption of SFAS No. 157 did not materially affect the Company’s consolidated results of operations, financial position or cash flows.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” In February 2007, the FASB issued SFAS No. 159, which permits entities to choose to measure certain financial instruments at fair value. For the Company, SFAS No. 159 is effective as of January 1, 2008. The Company has determined it will not elect fair value measurements for financial assets and financial liabilities included in the scope of SFAS No. 159.
EITF 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards.” In June 2007, the FASB Emerging Issues Task Force (EITF) reached a consensus that a realized income tax benefit from dividends or dividend equivalents that are charged to retained earnings and are paid to employees for equity classified nonvested equity shares, nonvested equity share units and outstanding equity share options should be recognized as an increase to additional paid-in capital. The amount recognized in additional paid-in capital for the realized income tax benefit from dividends on those awards should be included in the pool of excess tax benefits available to absorb tax deficiencies on share-based payment awards. EITF 06-11 will be applied prospectively to the income tax benefits that result from dividends on equity-classified employee share-based payment awards that are declared after December 31, 2007. The effect of adopting EITF 06-11 on January 1, 2008 was not material to the Company’s consolidated results of operations, financial position or cash flows.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the noncontrolling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 also requires consolidated net income to be reported, and disclosed on the face of the consolidated statement of operations, at amounts that include the amounts attributable to both the parent and the noncontrolling interest. Additionally, SFAS No. 160 establishes a single method for accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. The Company will apply the requirements of SFAS No. 160 upon its adoption on January 1, 2009 and does not expect it to have a material impact on its financial position and results of operations.
In December 2007, the FASB issued SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, “Business Combinations” (“SFAS No. 141”), however retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS No. 141(R) requires an acquirer to recognize the assets acquired, liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date, at their fair values as of that date, with specified limited exceptions. Changes subsequent to that date are to be recognized in earnings, not goodwill. Additionally, SFAS No. 141 (R) requires costs incurred in connection with an acquisition be expensed as incurred. Restructuring costs, if any, are to be recognized separately from the acquisition. The acquirer in a business combination achieved in stages must also recognize the identifiable assets and liabilities, as well as the noncontrolling interests in the acquiree, at the full amounts of their fair values. SFAS No. 141(R) is effective for business combinations occurring in fiscal years beginning on or after December 15, 2008. The Company will apply the requirements of SFAS No. 141(R) upon its adoption on January 1, 2009 and does not expect it to have a material impact on its financial position and results of operations.
In February 2008, the FASB issued Staff Position FAS 157-2, Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are measured at fair value on a recurring basis. FSP FAS 157-2 establishes January 1, 2009 as the effective date of SFAS No. 157 with respect to these fair value measurements for the Company. We do not currently expect the application of the fair value framework established by SFAS No. 157 to non-financial assets and liabilities measured on a non-recurring basis to have a material impact on our consolidated financial statements. However, the Company will continue to assess the potential effects of SFAS No. 157 as additional guidance becomes available.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 amends the requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early adoption encouraged. The Company will apply the requirements of SFAS No. 161 upon its adoption on January 1, 2009 and does not expect it to have a material impact on its financial position or results of operations or related disclosures.
In April 2008, the FASB issued Staff Position No. 142-3, “Determination of Useful Life of Intangible Assets” (“FSP FAS 142-3”). FSP FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”), and other U.S. Generally Accepted Accounting Principles. FSP FAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. The guidance for determining the useful life of a recognized intangible asset should be applied prospectively to intangible assets acquired after the effective date. The disclosure requirements should be applied prospectively to all intangible assets recognized as of, and subsequent to, the effective date. The Company will apply the requirements of FSP FAS 142-3 upon its adoption on January 1, 2009 and it currently does not expect the adoption of FSP FAS 142-3 to have a material impact on its financial position and results of operations.
In May 2008, the FASB issued FASB Staff Position No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)”, or FSP No. APB 14-1. FSP No. APB 14-1 clarifies that convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) are not addressed by paragraph 12 of APB Opinion No. 14 “Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants”. Additionally, the FSP specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. FSP No. APB 14-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The implementation of this standard will not have an impact on our consolidated financial position or results of operations.
In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”). SFAS No. 162 identifies the sources of accounting principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (“GAAP”) in the United States (“the GAAP hierarchy). This Statement is effective 60 days following the Security and Exchange Commission’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles”. The Company currently adheres to the GAAP hierarchy as presented in SFAS No. 162, and therefore does not expect its adoption will have a material impact on its consolidated results of operations and financial condition.
In June 2008, the FASB issued Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 applies to the calculation of earnings per share (“EPS”) described in paragraphs 60 and 61 of FASB Statement No. 128, “Earnings per Share” for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. All prior-period EPS data presented shall be adjusted retrospectively to conform to the provisions of this FSP. The Company will apply the requirements of FSP EITF 03-6-1 upon its adoption on January 1, 2009 and it currently does not expect the adoption of FSP EITF 03-6-1 to have a material impact on its financial position and results of operations.
In September 2008, the FASB issued FSP FAS No. 133-1 and FIN 45-4, Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161 (“FSP FAS No. 133-1 and FIN 45-4”). FSP FAS No. 133-1 and FIN 45-4 requires enhanced disclosures about credit derivatives and guarantees. The FSP is effective for financial statements issued for reporting periods ending after November 15, 2008. The adoption of FSP FAS No. 133-1 and FIN 45-4 did not have a material impact on the Company’s consolidated financial statements.
In October 2008, the FASB issued FSP FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active (“FSP FAS 157-3”), to help constituents measure fair value in markets that are not active. FSP FAS 157-3 is consistent with the joint press release the FASB issued with the Securities and Exchange Commission (“SEC”) on September 30, 2008, which provides general clarification guidance on determining fair value under SFAS No. 157 when markets are inactive. FSP FAS 157-3 was effective upon issuance, including prior periods for which financial statements had not been issued. The adoption of FSP 157-3 did not have a material impact on the Company’s consolidated financial statements.
In December 2008, the FASB issued FSP FAS No. 140-4 and FIN 46R-8 Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities (“FSP FAS 140-4 and FIN 46R-8”). FSP FAS 140-4 and FIN 46R-8 require additional disclosures about transfers of financial assets and involvement with variable interest entities. The requirements apply to transferors, sponsors, servicers, primary beneficiaries and holders of significant variable interests in a variable interest entity or qualifying special purpose entity. FSP FAS 140-4 and FIN 46R-8 is effective for financial statements issued for reporting periods ending after December 15, 2008. FSP FAS 140-4 and FIN 46R-8 affect only disclosures and therefore did not have a material impact on the Partnership’s consolidated financial statements.
On December 31, 2008, the Securities and Exchange Commission (SEC) adopted major revisions to its rules governing oil and gas company reporting requirements. These include provisions that permit the use of new technologies to determine proved reserves and that allow companies to disclose their probable and possible reserves to investors. The current rules limit disclosure to only proved reserves. The new disclosure requirements also require companies to report the independence and qualifications of the person primarily responsible for the preparation or audit of reserve estimates, and to file reports when a third party is relied upon to prepare or audit reserves estimates. The new rules also require that oil and gas reserves be reported and the full-cost ceiling value calculated using an average price based upon the prior 12-month period. The new oil and gas reporting requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, with early adoption not permitted. We are in the process of assessing the impact of these new requirements on our financial position, results of operations and financial disclosures.
| 2. | Sale of Barnett Shale Interest |
In December 2006, through the Company’s wholly owned subsidiary, Barnett Petrosearch LLC, (“Barnett Petrosearch”) the Company joined in the formation of a partnership, DDJET Limited LLP (“DDJET”), for the development of a natural gas integrated venture to explore and develop assets in the Barnett Shale. The Company owned a 5.54% interest in DDJET along with partners Metroplex Barnett Shale LLC, a wholly owned subsidiary of Exxon Mobil Corporation, and Cinco County Barnett Shale LLC, a privately held Dallas-based company (“Cinco”).
On February 11, 2008 the Company executed an authorization for the general partner of the Partnership to immediately commence a sales marketing program to interested potential purchasing parties in order to fully assess the current market value of the Partnership. On June 25, 2008 the Company executed a binding agreement for the sale of its limited partnership interest in DDJET to Cinco for a cash purchase price of $36,000,000. On June 26, 2008 Cinco paid to Barnett Petrosearch the required $1,800,000 non-refundable deposit to be applied to the purchase price and fulfilled all the other necessary requirements to bind both Cinco and Petrosearch to the sale. On July 18, 2008 the Company received the balance of the proceeds of the sale in the amount of $30,729,008. These proceeds were net of the $1,800,000 down payment previously received from Cinco and $3,470,992 of costs previously owed by the Company which were assumed by Cinco pursuant to the June 25, 2008 agreement.
Because the Company utilizes the Full Cost Accounting method to account for its oil and gas assets, in order to record a gain on the sale transaction the sale must have significantly altered the relationship between capitalized costs and proved reserves. Being that the amortization rate per barrel of oil equivalent decreased by greater than 50% from before the sale as opposed to after the sale, the Company deemed the alteration of the relationship between capitalized costs and proved reserves to be significant. The reason there was such an alteration was due to the fact that a significant portion of the Barnett Shale’s capital costs was related to undeveloped acreage that did not have any proved reserves associated with it; as opposed to the Company’s other assets whose capital costs are more directly related to proved reserves. As a result, a gain of $21,814,753 has been generated by the sale of the Company’s interest in DDJET.
| 3. | Agreements Pertaining to Oil and Gas Properties |
North Texas/Panhandle Water Flood Project
Effective November 15, 2005, the Company entered into an agreement to purchase a 100% working interest in 1755 acres of leases in the Quinduno Field located in Roberts County, Texas from Quinduno Energy, L.L.C, (“Quinduno”). Subsequently on November 15, 2007, the parties agreed to change the amount of shares and stock owed under the first agreement. The agreement and subsequent agreement provided for the payment of the purchase price of $1,850,000 cash and 2,700,000 shares of unregistered common shares of the Company valued at $2,767,000. All cash and stock due under the agreements were paid as of December 31, 2007, other than $300,000 which was paid in January 2008. 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.
At any time after completion of the first phase of the project, which was completed as of December 31, 2007, 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, 2008 and 2007:
| | | 2008 | | | 2007 | |
| Prepaid expenses | | $ | 180,055 | | | $ | 172,093 | |
| Prepaid bonds | | | 302,915 | | | | 292,332 | |
| Current portion of financing costs | | | - | | | | 498,668 | |
| Other receivables | | | - | | | | 24,062 | |
| | | $ | 482,970 | | | $ | 987,155 | |
| 5. | Accrued Liabilities and Other Long-Term Obligations |
Accrued liabilities consist of the following at December 31, 2008 and 2007:
| | | 2008 | | | 2007 | |
| | | | | | | |
| Revenue payable and operated prepayment liability | | $ | 29,426 | | | $ | 52,141 | |
| Accrued interest payable | | | - | | | | 914,367 | |
| Accrued liabilities for capital additions | | | 100,061 | | | | 38,530 | |
| Financing costs payable | | | - | | | | 251,125 | |
| Accrued liability for professional fees | | | 119,302 | | | | 142,599 | |
| Current portion of asset retirement obligation | | | - | | | | 128,023 | |
| Other accrued expenses | | | 88,674 | | | | 55,904 | |
| | | | | | | | | |
| | | $ | 337,463 | | | $ | 1,582,689 | |
Other long-term obligations consist of $764,523 for asset retirement obligations and $12,347 for non-current deferred rent obligations as of December 31, 2008. Other long-term obligations consist of $676,832 for asset retirement obligations and $23,082 for non-current deferred rent obligations as of December 31, 2007.
At December 31, 2008 no debt remained outstanding.
Convertible Securities
In July, 2008, the Company extinguished all of its convertible debt outstanding and related interest by repaying the principal balance of $18,775,000 and accrued and unpaid interest of $87,734. Total cash payments made were $18,862,734. At the time of the extinguishment, the unamortized debt discount of $3,795,272 and the unamortized financing costs of $747,160 totaled $4,542,432, which was recorded as loss on extinguishment of debt in the third quarter of 2008.
Project Financing
In November 2006, the Company signed a Securities Purchase Agreement and Secured Term Note with Laurus Master Fund, Ltd to provide financing for the drilling of its Kallina 46 #1 well and payment of the future completion costs for the Kallina 46 #1 well. The November 2006 financing was specifically recourse to the Kallina 46 #1 well and the associated lease acreage only.
In April 2008, it was determined that the Kallina 46 #1 well was uneconomic and the decision was made that the well needed to be plugged and abandoned. In May 2008 the Company received a full release of all the liens, security interests, rights, claims and benefits of every kind in, on and under the November 2006 Secured Term Note with Laurus Master Fund, Ltd, as well as that same release on all the other collateral documents associated with that financing. As part of this transaction, the Company conveyed their interest in the Kallina 46#1 well and the associated lease acreage to a third party.
As a result of the legal release described above, the debt related to the Laurus financing has been extinguished on the financial statements of the Company in May, 2008. In addition, the accrued interest, unamortized debt discount, and unamortized financing costs have also been written-off as well as the net book value of the Kallina well.
The gain on extinguishment of this debt was accounted for according to APB 26, “Early Extinguishment of Debt”. A difference between the reacquisition price and the net carrying amount of the extinguished debt was recognized as a gain in the amount of $1,097,328 in the accompanying statements of operations for 2008.
Revolving Credit Agreement
On April 1, 2008 the total outstanding balance of the revolving credit facility became due and a payment of $1,602,500 was paid in full to Fortuna Energy, which closed out the revolving credit facility as of that date. Pursuant to the revolving credit agreement, and as part of being paid back in full, Fortuna Energy returned to the Company all of the overriding royalties related to the Company’s assets that were issued to Fortuna Energy. The most significant override relates to a 2% override of the Company’s net interest in the Company’s North Dakota, Gruman project.
Through December 31, 2008, the Company has incurred more losses than income since its inception and, therefore, has not been subject to federal income taxes. As of December 31, 2008, the Company had net operating loss (“NOL”) carryforwards for income tax purposes of approximately $4.8 million which expire in various tax years through 2027. 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, 2008 and 2007 are as follows:
| | | 2008 | | | 2007 | |
| | | | | | | |
| Deferred tax assets: | | | | | | |
| Net operating loss carry-forward | | $ | 1,667,494 | | | $ | 7,460,112 | |
| Percentage depletion carryforward | | | 521,309 | | | | - | |
| Book/tax basis difference in property, plant and equipment | | | 1,247,645 | | | | - | |
| Allowance for doubtful accounts | | | 13,013 | | | | 21,140 | |
| Contribution carryover | | | 4,611 | | | | 4,480 | |
| | | | | | | | | |
| Total deferred tax assets | | | 3,454,072 | | | | 7,485,732 | |
| | | | | | | | | |
| Less valuation allowance | | | - | | | | (1,768,021 | ) |
| | | | | | | | | |
| Net deferred tax asset | | | 3,454,072 | | | | 5,717,711 | |
| | | | | | | | | |
| Deferred tax liabilities: | | | | | | | | |
| Book/tax basis difference in oil and Gas properties | | | - | | | | (5,709,685 | ) |
| Book/tax basis difference in property and equipment | | | - | | | | (8,026 | ) |
| | | | | | | | | |
| Total deferred tax liability | | | - | | | | (5,717,711 | ) |
| | | | | | | | | |
| Net deferred tax | | $ | 3,454,072 | | | $ | - | |
In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which the use of such net operating losses are allowed. As of December 31, 2008, the Company has determined that it is more likely than not that all of the deferred tax assets will be utilized.
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 35% for 2008 and 34% for 2007 were applied to pre-tax income and loss for the years ended December 31, 2008 and 2007 is as follows:
| | | 2008 | | | 2007 | |
| | | Amount | | | % | | | Amount | | | % | |
| | | | | | | | | | | | | |
| Expense (Benefit) for income tax at federal statutory rate | | $ | (1,064,857 | ) | | | (35.0 | )% | | $ | (2,222,047 | ) | | | (34.0 | )% |
| Non-deductible expenses and other | | | (621,193 | ) | | | (20.4 | ) | | | 2,870,081 | | | | 44.0 | |
| Change in valuation allowance | | | (1,768,021 | ) | | | (58.1 | ) | | | (648,034 | ) | | | (10.0 | ) |
| | | $ | (3,454,071 | ) | | | (113.50 | ) % | | $ | - | | | | - | % |
The Company adopted the provisions of FASB Interpretation No. 48 — Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 (“FIN 48”) on January 1, 2007. The adoption of FIN 48 did not have a material effect on the Company’s financial position, results of operations or cash flows. The Company has not recorded any liabilities as of December 31, 2008 related to the adoption of FIN 48. Subsequent to adoption, there have been no changes to the Company’s assessment of uncertain tax positions.
The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2008, the Company made no provision for interest or penalties related to uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various states. There are currently no federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue service for tax years before 2004 and for state and local tax authorities for years before 2003. The Company’s tax years of 2004 and forward are subject to examination by federal and state taxing authorities.
| 8. | 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 $202,658 of which $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, 2008 and 2007 was $99,989 and $100,312, respectively.
Contract Related to Operations
With regards to the North Texas/Panhandle Water Flood Project, in January, 2008, the Company signed an agreement with Complete Production Services Inc. (“CPS”), an international oilfield service company which provided that CPS, at its sole expense, design and construct a water treatment facility no later than 90 days from the effective date of the agreement that would be capable of treating all of the project’s production water up to a maximum of 10,000 bbls per day and likewise treat and provide to the project a minimum of 5,000 bbls per day of production water from third party sources. The Company, in turn, committed to be capable of injecting not less than 2,000 bbls of treated water per day derived from third party production water within 30 days after the facility opened, and have further committed to be capable of injecting not less than 5,000 bbls of treated water per day derived from third party production water within 180 days after the facility opened, in addition to re-injecting its own treated production water from the oil and gas lease it operates. The Company is required to pay a scaled management fee to CPS commencing on the date the facility opened on the basis of the volume of treated and re-injected water derived from the Company’s production. The Company is currently applying to regulatory agencies to add more wells to the existing flood permit, as required under the agreement, to ensure its ability to inject the volumes that CPS will make available. At present, the Company is in several negotiations with potential industry venture partners to allow for the commencement of the flood to begin as soon as possible.
Unused Letters of Credit
The Company has unused letters of credit supporting its drilling bonds in the total amount of $130,000 which expire at various times in 2009 and 2010.
Legal Proceedings
On April 11, 2007, the Company was served with a lawsuit filed against it titled Cause No. 2007-16502; D. John Ogren, R. Bradford Perry and Chester Smitherman v. Petrosearch Corporation; 133rd Judicial District Court, Harris County, Texas. The plaintiffs were three (3) Series A Preferred shareholders who derived their original shares from Texas Commercial Resources, Inc. (“TCRI”) and became Series A Preferred shareholders of Petrosearch Energy Corporation as a result of the prior mergers. The plaintiffs had alleged that Petrosearch Corporation (and TCRI, its predecessor) failed to pay accrued, cumulative dividends and refused to allow conversion of their Series A Preferred Stock into common stock. The plaintiffs had alleged breach of contract, fraud and violation of Section 33 of the Texas Securities Act and have requested the award of actual and exemplary damages, interest and attorneys’ fees. The lawsuit likewise requested the Court to compel the payment of accrued dividends and the examination of the Company’s books and records. The lawsuit was settled in September 2008 and the settlement was paid 100% by the Company's insurance policy. The payment of the settlement is not an admission of liability, as the Company denies all allegations of wrongdoing contained in the lawsuit.
The Company currently is not a party to any other material pending legal proceedings.
Employment Agreements
The employment contracts in existence with officers and key personnel include employment contracts with each of Richard Dole (Chairman, President and CEO), David Collins (Chief Financial Officer) and Wayne Beninger, (Chief Operating Officer). The current terms of the employment agreements follow:
The employment contracts with Messrs. Collins, Beninger, and Dole provide for an employment term of two years beginning on May 1, 2007 and automatically expire at the end of the term. Each of the employment contracts provides for termination by the Company upon death or disability, with six month severance payments for Messrs Collins and Beninger and 12 month severance for Mr. Dole. Each of the employment contracts permits termination by the Company for cause without severance payments. The agreements may be voluntarily terminated by the employee at any time, with no severance payment.
Each executive officer will receive a fixed severance payment in the event of a triggering event. The triggering events which give rise to severance amounts are any of the following events: (i) the employment agreement is terminated by the Company without “cause”, (ii) the employee terminates his employment for “good reason”, (iii) the employee’s employment is voluntarily (by the employee) or involuntarily terminated upon a “Change in Control”, or (iv) the agreement expires (on April 30, 2009) without the occurrence of any of the events listed in (i), (ii) or (iii) above. With respect to Mr. Beninger and Mr. Collins, the fixed severance amount is $550,000. With respect to Mr. Dole, the fixed severance amount is $850,000.
For purposes of each agreement, a change in control is defined as an 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).
The Company has the authority to issue up to 120,000,000 shares of stock, consisting of 100,000,000 shares of common stock, par value $.001 per share, and 20,000,000 shares of preferred stock, par value $1.00 per share.
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 of December 31, 2008 and 2007, the Company has 1,000,000 shares of Series A 8% Convertible Preferred Stock (“Series A Preferred”) authorized and 227,245 and 483,416 shares outstanding, respectively. 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. 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. As of December 31, 2008, no dividends have been declared and approximately $115,895 of dividends were in arrears related to the Series A Preferred if the Company decided to declare dividends.
As of December 31, 2008 and 2007, the Company has 100,000 shares authorized and 43,000 shares issued and outstanding of Series B Convertible Preferred Stock (“Series B Preferred”). 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 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.
Stock Warrants
The Company has periodically issued 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. Warrants have also been issued as part of capital financing transactions. The issuances 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. The Company issues shares of authorized common stock upon the exercise of the warrant.
In December 2004, the FASB issued SFAS 123(R), which is a revision of SFAS 123. SFAS 123(R) requires all share-based payments to employees, including grants of employee stock warrants, to be recognized as stock-based compensation expense in the Company’s Consolidated Statements of Operations based on their fair values. For purposes of determining compensation expense associated with stock warrants, the fair value of the Company’s stock was determined based upon the Black-Scholes option pricing model.
No warrants were issued during 2008. For warrants granted to employees or directors during 2007, the fair value of such warrants was estimated at the date of grant using a Black-Scholes option-pricing model with the following assumptions:
| | 2007 |
| Dividend yield | -0- |
| | |
| Expected volatility | 88% - 105% |
| | |
| Risk free interest | 4.52% |
| | |
| Expected lives | 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 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 stock warrants.
The Company issued the following warrants in 2007:
Pursuant to convertible debt issued in February of 2007, the Company issued 5,225,000 four year warrants to purchase common stock of the Company with an exercise price of $1.40. The fair value assigned to the warrants of $2,667,968 was recorded as a debt discount. The warrant holder has certain registration rights with regards to the warrant.
Pursuant to convertible debt issued in November of 2007, the Company issued 1,982,145 three year warrants to purchase common stock of the Company with an exercise price of $1.50. The fair value assigned to the warrants of $803,867 was recorded as a debt discount. The warrant holder has certain registration rights with regards to the warrant.
Pursuant to a private placement done in February, 2006, the Company issued 964,285 three year warrants, which were subsequently modified to four year warrants in 2007, to purchase shares of the Company’s common stock with an exercise price of $2.00 per share to the accredited investors. In addition, the Company issued 96,429 warrants to purchase shares of the Company’s common stock to the placement agency. The warrants issued to the placement agent are exercisable for four years, as modified in 2007, and have an exercise price of $2.00 per share. The shares of common stock underlying the warrants have piggyback registration rights. The fair value of the warrants of $674,084 was offset in equity as a cost of raising capital. The fair value of the modification was also offset in equity as a cost of raising capital.
In connection with the modification of the Revolving Credit Agreement with Fortuna (as described in Note 6 above), the Company modified the terms of 100,000 warrants held by Fortuna by extending the expiration date from November 1, 2007 to October 15, 2011, and by lowering the exercise price from $2.00 to $0.92 per share. The difference in value between the new and revised warrants of $37,302 was based on the Black-Scholes Option Pricing Model and was recorded as additional debt discount with an offset to additional paid in capital. In addition to the modification of warrants, the Company granted Fortuna 475,000 warrants at an exercise price of $0.92 for a term of five years. The warrants are “puttable” back to Fortuna for a period of two years, commencing 180 days from issuance, at a price of $0.65 per share. In addition, there are piggyback registration rights for the warrants upon the Company’s next registration of any securities. In compliance with FAS 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”, the fair value of the warrants of $301,198 was recorded as a liability in the accompanying financial statements and was marked-to-market as of December 31, 2007 to $321,140 rather than additional paid in capital. The warrants were valued by a third party using the Black-Scholes Option Pricing Formula with a put option floor. During 2008, the Company paid $308,750 to Fortuna to redeem the instrument when they exercised the put feature..
A summary of the Company’s stock warrant activity and related information for the years ended December 31, 2008 and 2007 follows:
| | | Number of Shares Under Warrant | | | Exercise Price | | | Weighted Average Exercise Price | | | Weighted Average Grant Date Fair Value ($/share) | | Total Intrinsic Value Warrant Exercises (1) | |
| | | | | | | | | | | | (2) | | | |
| | | | | | | | | | | | | | | | |
| Warrants outstanding at December 31, 2006 | | | 14,147,690 | | | $ | 0.92-$9.75 | | | $ | 1.88 | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Issued | | | 7,207,145 | | | $ | 1.40-$1.50 | | | $ | 1.43 | | | $ | 0.48 | | | |
| Cancelled | | | (1,050,007 | ) | | $ | 4.88-$9.75 | | | $ | 7.93 | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Warrants outstanding at December 31, 2007 | | | 20,304,828 | | | $ | .092-$2.00 | | | $ | 1.41 | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Exercise of put by warrant holder | | | (475,000 | ) | | $ | 0.92 | | | $ | 0.92 | | | | | | | |
| Cancelled | | | (5,021,969 | ) | | $ | 0.98-$1.95 | | | $ | 1.93 | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Warrants outstanding at December 31, 2008 | | | 14,807,859 | | | $ | 0.92-$2.00 | | | $ | 1.24 | | | | | | | |
All outstanding stock warrants are exercisable at December 31, 2008. A summary of outstanding stock warrants at December 31, 2008 follows:
| Number of Common Stock Equivalents | | Expiration Date | | Remaining Contracted Life (Years) | | Weighted Average Remaining Contractual Term (Years) | | Exercise Price | | Weighted Average Exercise Price | | Aggregate Intrinsic Value (1) |
| 1,060,714 | | February 2010 | | | 1.08 | | | | $ | 2.00 | | $ | 2.00 | | |
| 1,982,145 | | November 2010 | | | 1.88 | | | | $ | 1.50 | | $ | 1.50 | | |
| 5,225,000 | | January 2011 | | | 2.00 | | | | $ | 1.40 | | $ | 1.40 | | |
| 100,000 | | October 2011 | | | 2.79 | | | | $ | .92 | | $ | .92 | | |
| 6,440,000 | | December 2011 | | | 2.92 | | | | $ | .92 | | $ | .92 | | |
| 14,807,859 | | | | | | | 2.32 | | | | | | | | $0 |
| (1) | The intrinsic value of a warrant is the amount by which the current market value of the underlying stock exceeds the exercise price of the warrant, or the market price at the end of the period less the exercise price. |
| (2) | The weighted average grant date fair value was determined by using the Black Scholes Option Pricing Model as described above. |
The following table provides a detail of stock-based compensation incurred during the years ended December 31, 2008, and 2007:
| | | 2008 | | | 2007 | |
| Restricted stock – Interest Expense | | $ | 401,626 | | | $ | 574,897 | |
| Restricted stock – General and Administrative | | | 313,750 | | | | 127,726 | |
| Restricted stock – Property Costs | | | - | | | | 1,677,000 | |
| Committed restricted stock | | | - | | | | 288,172 | |
| Total stock-based compensation | | | 715,376 | | | | 2,667,795 | |
| Less capitalized property costs | | | - | | | | (1,677,000 | ) |
| Stock compensation expense, net of amounts capitalized | | $ | 715,376 | | | $ | 990,795 | |
The above table excludes common stock issued for cash, warrants issued in financing arrangements, debt discounts recorded in equity, and common stock issued for exercise of warrants.
Treasury Stock – Stock Repurchase Plan
In July 2008 the Board of Directors approved a stock repurchase plan in which the Company is authorized to repurchase up to $5 million of market value or 10 million shares of its common stock in open market purchases or in privately negotiated transactions. The purchases are to be at the discretion of senior management and will be dependent upon market conditions. The Repurchase Plan does not require any minimum purchase and can be suspended or terminated by the Board of Directors at any time.
In October and November of 2008, the Company purchased 214,800 shares of its common stock at an average share price of approximately $0.21 to be classified as treasury stock. In February 2009 the Company purchased 903,173 shares of its common stock at an average price of $0.18. As of March 5, 2009 the company has purchased in total, 1,117,973 shares of common stock at an average price of $.186.
| 10. | Related Party Transactions |
During the years ended December 31, 2008 and 2007, the Company did not engage in any transactions with related parties.
Following is a reconciliation of the numerators and denominators of the basic and diluted EPS computations for 2008 and 2007:
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | |
| Basic EPS: | | | | | | |
| Net income (loss) | | $ | 411,623 | | | $ | (6,535,432 | ) |
| Less: Preferred stock dividends (1) | | | (18,180 | ) | | | (38,673 | ) |
| Net income (loss) available to common stockholders | | $ | 393,443 | | | $ | (6,574,105 | ) |
| | | | | | | | | |
| Weighted average shares of common stock | | | 41,797,282 | | | | 39,476,379 | |
| | | | | | | | | |
| Basic net income (loss) per share | | $ | 0.01 | | | $ | (0.17 | ) |
| | | | | | | | | |
| Diluted EPS: | | | | | | | | |
| Income (loss) available to common stockholders | | $ | 393,443 | | | $ | (6,574,105 | ) |
| Plus assumed conversions | | | 18,180 | | | | 38,673 | |
| Net income (loss) used for diluted EPS | | $ | 411,623 | | | $ | (6,535,432 | ) |
| | | | | | | | | |
| Weighted average shares of common stock | | | 41,797,282 | | | | 39,476,379 | |
| Plus effect of dilutive securities: | | | | | | | | |
| Convertible preferred stock | | | 74,547 | | | | - | |
| Weighted average shares used for Diluted EPS | | | 41,871,829 | | | | 39,476,379 | |
| | | | | | | | | |
| Diluted net income (loss) per share | | $ | 0.01 | | | $ | (0.17 | ) |
(1) Dividends are undeclared
For the year ended December 31, 2007, 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 1,596,234 common shares and convertible preferred stock convertible into 94,218 common shares.
| 12. | Non-Cash Investing and Financing Activities |
During the years ended December 31, 2008 and 2007, the Company engaged in various non-cash financing and investing activities as follows:
| | | 2008 | | | 2007 | |
| | | | | | | |
| Decrease in prepaid drilling for property costs | | $ | 1,432,906 | | | $ | 960,674 | |
| | | | | | | | | |
| Issuance of common stock for acquisition of property | | $ | - | | | $ | 1,677,000 | |
| | | | | | | | | |
| Increase in accounts payable and accrued liabilities for property costs and prepaid drilling | | $ | - | | | $ | 2,417,603 | |
| | | | | | | | | |
| Change in property costs associated with asset retirement obligation | | $ | 77,646 | | | $ | 103,655 | |
| | | | | | | | | |
| Issuance of warrants with debt | | $ | - | | | $ | 3,471,835 | |
| | | | | | | | | |
| Beneficial conversion feature on convertible debt | | $ | - | | | $ | 2,667,968 | |
| | | | | | | | | |
| Issuance of notes payable for financing costs | | $ | - | | | $ | 675,000 | |
| | | | | | | | | |
| Reclass of financing costs to debt discount | | $ | - | | | $ | 306,088 | |
| 13. | Impairment and Sale of Oil and Gas Properties |
At December 31, 2008, the net capitalized costs of crude oil and natural gas properties included in the amortization base exceeded the present value of the estimated reserves. As such, a write-down of $15,713,886 was expensed in the accompanying statement of operations to record this impairment in 2008. No impairment was recorded for 2007 because the net capitalized costs of crude oil and natural gas properties did not exceed the present value of the estimated reserves at December 31, 2007.
| 14. | 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.
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, 2008. 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.
| | | Oil | | | Gas | |
| Quantity of Oil and Gas Reserves | | (Bbls) | | | (Mcf) | |
| | | | | | | |
| Total proved reserves at December 31, 2006 | | | 1,757,641 | | | | 1,309,409 | |
| | | | | | | | | |
| Extensions and discoveries | | | - | | | | 1,978,298 | |
| Production | | | (13,506 | ) | | | (135,061 | ) |
| Revisions to previous estimate | | | (12,720 | ) | | | (460,436 | ) |
| Sale of property | | | (19,091 | ) | | | (9,000 | ) |
| | | | | | | | | |
| Total proved reserves at December 31, 2007 | | | 1,712,324 | | | | 2,683,210 | |
| | | | | | | | | |
| Sale of oil and gas properties | | | - | | | | (1,770,002 | ) |
| Production | | | (3,790 | ) | | | (116,189 | ) |
| Revisions to previous estimate | | | (173,415 | ) | | | (31,019 | ) |
| | | | | | | | | |
| Total proved reserves at December 31, 2008 | | | 1,535,119 | | | | 766,000 | |
| | | | | | | | | |
| Proved developed reserves: | | | | | | | | |
| | | | | | | | | |
| December 31, 2008 | | | 13,077 | | | | 0 | |
| | | | | | | | | |
| December 31, 2007 | | | 257,660 | | | | 993,730 | |
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, 2008 and 2007:
| | | 2008 | | | 2007 | |
| | | | | | | |
| Unevaluated properties, not subject to amortization | | $ | - | | | $ | 7,099,601 | |
| Properties subject to amortization | | | 24,668,141 | | | | 33,235,534 | |
| | | | | | | | | |
| Total capitalized costs | | | 24,668,141 | | | | 40,335,135 | |
| | | | | | | | | |
| Less accumulated depletion, depreciation and amortization | | | (19,025,561 | ) | | | (3,186,191 | ) |
| | | | | | | | | |
| Net capitalized costs | | $ | 5,642,580 | | | $ | 37,148,944 | |
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, 2008 and 2007:
| | | 2008 | | | 2007 | |
| | | | | | | |
| Acquisition costs | | $ | 1,817,837 | | | $ | 4,132,070 | |
| | | | | | | | | |
| Exploration costs | | $ | 1,489,159 | | | $ | 6,208,979 | |
| | | | | | | | | |
| Development costs | | $ | 2,571,487 | | | $ | 222,278 | |
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, 2008 and 2007:
| | | 2008 | | | 2007 | |
| | | | | | | |
| Future cash inflows | | $ | 59,994,406 | | | $ | 168,883,862 | |
| Future development and production costs | | | (41,435,442 | ) | | | (59,067,028 | ) |
| | | | | | | | | |
| Future net cash inflows before income taxes | | | 18,558,964 | | | | 109,816,834 | |
| Future income taxes | | | (1,318,360 | ) | | | (29,877,612 | ) |
| | | | | | | | | |
| Future net cash flows | | | 17,240,604 | | | | 79,939,222 | |
| 10% discount factor | | | (12,401,545 | ) | | | (39,550,071 | ) |
| | | | | | | | | |
| Standardized measure of discounted future net cash inflow | | $ | 4,839,059 | | | $ | 40,389,151 | |
The following are the principal sources of change in the standardized measure of discounted future net cash flows during 2008:
| Beginning of year | | $ | 40,389,151 | |
| Sales of oil and gas produced, net of production costs | | | (592,308 | ) |
| Net changes in prices and production costs | | | (42,737,734 | ) |
| Sale of property | | | (2,196,201 | ) |
| Development costs incurred during the period | | | 2,527,992 | |
| Revisions of estimated development costs | | | (1,781,392 | ) |
| Revisions of previous quantity estimates | | | (7,603,637 | ) |
| Accretion of discount | | | 4,038,915 | |
| Net change in income taxes | | | 12,794,273 | |
| | | $ | 4,839,059 | |
Total standardized measure of discounted future net cash inflow decreased to $4,839,059 as of December 31, 2008 from $40,389,151 as of December 31, 2007. The primary reason for the decrease in discounted future cash flows is the decrease in oil and gas prices as of December 31, 2008 as compared to December 31, 2007.
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.
In February of 2009, the Company executed an agreement to terminate a contract for professional services. The total payment of $250,000 was paid in February of 2009 and relieves the Company of all future obligations under the engagement agreement with this third party.
In February of 2009, the Company entered into an agreement with a warrant holder which provides for the following: 1) purchase by the Company of 903,173 shares of common stock held by the warrant holder, 2) purchase by the Company of 5,000,000 warrants of the warrant holder, and 3) settlement of any and all liquidated damages under the registration rights of the warrants. The total amount paid by the Company to the warrant holder as part of this agreement is $285,000 which was paid in February of 2009.
Excluding the warrants mentioned above, subsequent to year end the Company canceled 8,930,479 warrants for an average price of less than $0.01 per warrant.
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