Statements contained herein and the information incorporated by reference herein may be forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). Forward-looking statements can be identified by the use of forward-looking terminology such as, but not limited to, "may," "will," "expect," "anticipate," "estimate," "would be," "believe," or "continue" or the negative or other variations of comparable terminology. We intend such forward-looking statements to be covered by the safe harbor provisions applicable to forward-looking statements contained in Section 21E of the Exchange Act. Such statements (none of which is intended as a guarantee of performance) are subject to certain assumptions, risks and uncertainties, which could cause our actual future results, achievements or transactions to differ materially from those projected or anticipated. Such risks and uncertainties are set forth herein.

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.

OVERVIEW - CORPORATE STRATEGY

We believe we have been successful over the past few years with our plan of solidifying the financial strength of the Company and improving the quality of our oil and gas assets, some of which have been sold resulting in significant gain to the Company. A key element to our current strong financial position was the sale of our Barnett Shale project in the second quarter of this year. This sale of our Barnett Shale project for $36 million left us with a significant cash balance, no long or short term debt and significant oil and gas reserves. The sale was fortuitous in that (i) we sold our Barnett Shale partnership interest near the height of natural gas prices; (ii) we realized approximately $29,000 per net acre in the sale, as opposed to current market values of approximately $5,000 or less per acre today; and (iii) for us to have stayed in the Barnett Shale project we would have needed to raise capital, which was unsuccessfully attempted prior to the sale and in this current market would have been extremely difficult, if not impossible. Therefore, a possible scenario if we had stayed in the partnership may have been that we would have defaulted under the Barnett Shale partnership agreement and as a result we would have been forced to sell our interest for 70% of the market value (pursuant to the partnership agreement), which assuming $5,000 per acre market values would have realized an estimated $12.2 million opposed to the $36 million actually realized.

Our current asset portfolio is primarily made up of a North Texas Panhandle water flood project (the "Water Flood") that has potential for multiple years of growth. The Water Flood is a resource play, which will allow us to re-invest our capital into the project to enhance the rate of return, revenue growth and reserve growth. We have initiated the first phase of the development of the Water Flood with a portion of the proceeds from the sale of the Barnett Shale project, a decision that enables us to spend the least amount of capital needed to measure the level of initial response of the water injection. We will then be able to make decisions on the future development of the project, and gauge the impact of the response on future potential strategic alternatives.

We continue to pursue and evaluate all strategic alternatives available. Given our strong financial position, we believe we will continue to see multiple opportunities to evaluate, and if appropriate, pursue. Also, given the current energy asset and company valuations, and financial market conditions where access to capital, both debt and equity, has become limited, we believe that companies that have cash or access to capital have a decided advantage to avail themselves of attractive value added transactions. We believe this plan of continuing to focus on the development of our Water Flood, as well as continuing to pursue strategic alternatives for the Company will give us the opportunity to create value for the shareholders.

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, sales of oil and gas assets and the use of debt instruments such as convertible notes and revolving credit facilities. We also, more specifically, have sold one of our main projects, the Barnett Shale project, for cash. The proceeds from all these methods have been, and Management believes will continue to be, sufficient to keep the operations funded and the business plan moving forward.

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 Convertible 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. Currently, there is no outstanding debt related to these convertible notes.

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 precluded the Company from incurring indebtedness in excess of fifty percent (50%) of the PV-10 value of the Company's total proved reserves, plus the fair market value of the leases and pipeline assets associated with the Company's Barnett Shale assets. 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. Currently, there is no outstanding debt related to this convertible note.

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 derecognized 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 and the third party has assumed the liability of plugging the Kallina 46#1 well.

Revolving Credit Agreement

As of 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 North Dakota, Gruman project.

As part of the original amended revolving credit agreement terms, we agreed to issue to Fortuna 475,000 warrants with a five year life and a strike price of $0.92 per share. The Warrants contained a "put" provision which allowed Fortuna to "put" the warrants to the Company at a price of $0.65 per warrant for two (2) years, which occurred in October, 2008. Additionally, as part of the transaction, we agreed to issue 100,000 warrants, which expire 5 years from the date of issue, at a price of $0.92 per share.

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.

CURRENT PROJECTS AND CAPITAL REQUIREMENTS

CORE PROPERTIES:

Barnett Shale Project -- In December 2006, through our wholly owned subsidiary, Barnett Petrosearch LLC, 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 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 Petrosearch 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.

The Company has commenced the first phase of the water flood project and began injecting water into the formation in early September 2008. To date, three wells in the first water flood pattern have been converted for water injection in which we are currently injecting approximately 2600 barrels of treated water per day. Additionally, one infill well drilled in the center of the pattern is configured as a producer where we expect to observe the initial response to water flood. We are currently using the total amount of treated water that is available from the water treatment facility constructed on our lease by Complete Production Services Inc. ("CPS"), as described below. CPS is currently in the process of ramping up the capacity of the water treatment facility and the barrels of water injected into the formation will increase as the plant increases capacity.

The Company has prepared a detailed study and development plan which includes entering 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 or injectivity. Three of these wells have been equipped and are now capable of producing and three, as noted above, have been converted for water injection. Further, two previously plugged wells were re-entered but we were unable to complete them for water injection. As of December 31, 2007, 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 adequate water for injection, in November 2006 we executed a water supply agreement with a landowner in the leasehold, which allows us to draw freshwater 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. This permit has since expired but we do not expect any difficulty obtaining a new permit if needed to supplement the treated water being used for injection. 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 freshwater. We also applied to the Texas Railroad Commission ("TRRC") to amend a previously granted saltwater injection permit to include fresh water injection. On January 5, 2007 we received a letter from the TRRC informing us of a protest by CRMWA contesting our application for freshwater injection in the Quinduno Field water flood. However, as of November 7, 2007, CRMWA withdrew their protest and request for hearing as part of an agreement with CRMWA that addresses their concerns with our use of freshwater for enhanced oil recovery. This agreement also prevents CRMWA from protesting future efforts to obtain approval from PGAD to produce the underlying freshwater aquifer.

In January 2008 we signed an agreement with CPS, an international oilfield service company which provided that CPS, at its sole expense, would 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 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 opened, and 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 our own treated production water from Quinduno. The facility was fully operational September 19, 2008 at which time the company was accepting and injecting a minimum of 2000 barrels of water per day. We are required to pay a scaled management fee to CPS that commenced in September on the basis of the volume of treated and re-injected water derived from our production. We have received TRRC permits to add a sufficient number of wells to the existing permit to meet our obligation to inject the volumes that CPS will make available. Further, we will continue to add the appropriate number of wells to the existing flood permit to continue with the development of the flood. We do not anticipate any difficulty with obtaining future approvals.

SW Garwood, Colorado County, Texas - In May 2008 we conveyed our interest in the three drilled wells and the associated acreage in this SW Garwood prospect to an unaffiliated third party. As a part of that transaction, we also transferred operatorship of all the existing and future wells in this SW Garwood prospect to that 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's assumption of the liability of plugging the Kallina 46 #1 well.

OTHER PROJECT AREAS:

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 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 continues to have pump and motor issues. This along with an unexpected decline in reservoir pressure has severely affected our ability to produce the well during the quarter, the well continues to have operational issues resulting in no production.

Proved developed reserves in the prospect to our share of the well as of December 31, 2007, were 215 Mbo and 68 MMcf of natural gas, as estimated by a third party engineering firm, McCartney Engineering, LLC.

Mississippi Tuscaloosa Prospects -- In June 2008 we agreed to farm-out out acreage in these prospects to an industry partner for co-development. The agreement allowed our industry partner to operate the project and required that they commence drilling of the first well on our acreage prior to October 1, 2008. Under the agreement the Company received a carried interest for 12.5% through casing point of the first well and an option to purchase up to another 12.5% interest in the well at cost. For all future wells, the agreement provides us with the same working interest as we chose on the first well. Prior to October 1 our partner tested the structure on offsetting acreage with a new well. The target zone was found as expected at approximately 6800'; however, the well found only a few feet of oil on water. After testing, this well was determined to be non-commercial and our partner has decided not to continue drilling. While we are considering alternatives for development of our leasehold position, it is likely that we will allow the acreage to expire.

RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the financial statements and accompanying notes and the other financial information appearing elsewhere in this filing.

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 three months ended September 30, 2008 compared to the three months ended September 30, 2007

Revenues

Consolidated oil and gas production revenue for the three months ended September 30, 2008 was $257,659 versus $426,931 for the three months ended September 30, 2007. This represents a forty percent decrease in revenue in the third quarter of 2008 over the third quarter of 2007. This decrease was mainly the result of the decreased production in our Gruman - North Dakota well, which is related to pump and pressure depletion issues with the well. The Gruman well continues to have these mechanical and reservoir issues and is not producing at this time. Also, 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 eighty-three percent of the revenue for the three months ended September 30, 2008. 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 regards to revenues and cash flow will not be indicative of future expected results.

See below for revenue detail by property from the third quarter of 2008 compared to the third quarter of 2007.

                            2008         %of         2007         %of
                           3rd Qtr      Total       3rd Qtr      Total

Barnett Shale             $ 212,191         83 %   $ 179,161         42 %
Gruman - North Dakota             -          0 %     160,963         38 %
SW Garwood                        -          0 %      40,037          9 %
Panhandle - Water Flood       2,468          1 %       1,573          0 %
Oklahoma                     39,335         15 %      36,766          9 %
Other                         3,665          1 %       8,431          2 %
         Total            $ 257,659        100 %   $ 426,931        100 %

To further explain the decrease in revenue from the third quarter of 2007 to the third quarter of 2008, we have provided the following break-out of production and prices for the two periods.

                                    3Q 2008       3Q 2007

Barrels of Oil                          439         2,642
Price per Barrel                  $   99.38     $   73.79

MCF of Gas                           18,866        37,600
Price per MCF                     $   11.29     $    5.94

Total Barrels of Oil Equivalent       3,584         8,927

As noted in the above table, the increase in oil and gas prices offset the fact that the production was down by sixty percent. The total effect on revenue from the price increases was approximately $268,999; however the effect of the decrease in production offset that positive effect by $(438,271) giving a net effect of $(169,272) on revenue from the third quarter of 2007 to the third quarter of 2008.

Lease Operating and Production Tax Expense Lease operating and production tax expenses for the quarters ended September 30, 2008 and 2007 were $160,162 and $146,400, 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. Lease operating expenses remained relatively constant, although revenue decreased by forty percent, due to the fact that although the Gruman well has not been producing, the lease operating costs related to the Gruman well remained constant during the period. Work on the well continues in an attempt to get the well back on line.

Depletion, Depreciation and Amortization

Costs for depletion, depreciation and amortization for the quarters ended September 30, 2008 and 2007, were $86,736 and $222,871, respectively. The decrease is mainly due to a decrease in total barrels of oil equivalent production during the quarter ended September 30, 2008 as compared to the same period in 2007 as well as a decrease in the amortizable base used to calculate depletion, due to the sale of the Barnett Shale project. 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 third quarter of 2008 was significantly lower than the depletion for the same period in 2007.

General and Administrative Expenses

General and administrative expenses for the quarters ended September 30, 2008 . . .