UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                              Washington, DC 20549

                                   FORM 10-KSB

[X]  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
     ACT OF 1934

     For the fiscal year ended DECEMBER 31, 2005

[ ]  TRANSITION REPORT PURSUANT TO 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT
     OF 1934

     For the transition period from ________ to ________

                      Commission file number:     000-51488

                         PETROSEARCH ENERGY CORPORATION
        (Exact name of small business issuer as specified in its charter)

                NEVADA                                    20-2033200
   (State or other jurisdiction of            (IRS Employer Identification No.)
    incorporation or organization)

                           675 BERING DRIVE, SUITE 200
                                HOUSTON, TX 77057
                    (Address of principal executive offices)

                                 (713) 961-9337

         Securities Registered Under Section 12(b) Of The Exchange Act:
                           Title Of Each Class     n/a
                Name Of Each Exchange On Which Registered     n/a

          Securities Registered Pursuant to 12(g) of the Exchange Act:
                               Title Of Each Class
                          Common Stock, $0.001Par Value

Check  whether the issuer is not required to file reports pursuant to Section 13
or 15(d) of the Exchange Act ____

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

Check  whether the issuer: (i) filed all reports required to be filed by Section
13  or  15(d) of the Exchange Act during the past 12 months (or for such shorter
period that the registrant was required to file such reports), and (ii) has been
subject to such filing requirements for the past 90 days.   Yes [X]   No [ ]

Check  if there is no disclosure of delinquent filers in response to Item 405 of
Regulation  S-B  contained  herein,  and no disclosure will be contained, to the
best  of  registrant's  knowledge,  in definitive proxy or information statement
incorporated  by  reference  in Part III of this Form 10-KSB or any amendment to
this Form 10-KSB.   [X]

The Issuer's revenues for the year ended December 31, 2005 were $1,701,043.

The  aggregate  market  value  of  Common  Stock  held  by non-affiliates of the
registrant  at  March 15, 2006, based upon the last reported sales prices on the
OTCBB, was $45,847,691.

As of March 15, 2006, there were approximately 31,057,101 shares of Common Stock
outstanding.


                                        1
<PAGE>
<TABLE>
<CAPTION>
                                TABLE OF CONTENTS

PART I                                                         Page
<S>       <C>                                                  <C>
Item 1.   Business                                                1

Item 2.   Properties                                              2

Item 3.   Legal Proceedings                                       8

Item 4.   Submission of Matters to a Vote of Security Holders     8


PART II

Item 5.   Market for Common Equity, Related Stockholder
          Matters and Small Business Issuer Purchases
          Of Equity Securities                                    8

Item 6.   Management's Discussion and Analysis or
          Plan of Operation                                      11

Item 7.   Financial Statements                                   28

Item 8.   Changes in and Disagreements with Accountants
          on Accounting and Financial Disclosure                 28

Item 8A.  Controls and Procedures                                28

Item 8B.  Other Information                                      28

PART III

Item 9.   Directors, Executive Officers, Promoters and
          Control Persons; Compliance with Section 16(a) of
          The Exchange Act                                       29

Item 10.  Executive Compensation                                 32

Item 11.  Security Ownership of Certain Beneficial
          Owners and Management and
          Related Stockholder Matters                            35

Item 12.  Certain Relationships and Related Transactions         37

Item 13.  Exhibits                                               38

Item 14.  Principal Accountant Fees and Services                 38
</TABLE>


                                        2
<PAGE>
                                     PART I
ITEM  1.     BUSINESS

Petrosearch Energy Corporation, a Nevada corporation formed in November 2004, is
an  independent crude oil and natural gas exploration and production company. We
are  the  successor  of  Petrosearch  Corporation, a Texas corporation formed in
August  2003.  All  references  to capitalization and business operations herein
apply  to  our  current  capitalization  and  operating  history,  including our
predecessor,  Petrosearch Texas. We have established production in North Dakota,
Texas  and  Oklahoma,  and  are currently engaged in exploration and development
activities,  including  direct  operator  activities,  through  our  subsidiary,
Petrosearch  Operating  Company,  L.L.C.,  in  North  Dakota,  Texas,  Oklahoma,
Mississippi and Louisiana.

OUR HISTORY

We  are  the  successor  to  the  business  of  Petrosearch Corporation, a Texas
corporation  that  was formed in August 2003 pursuant to a multi-step merger and
holding  company restructure. Under this merger plan, Petrosearch Corporation, a
privately  held  Delaware  corporation formed in April 2002, merged into a Texas
subsidiary  of  Texas  Commercial  Resources,  Inc.,  a publicly traded company.
Simultaneously,  TCRI  created  Petrosearch  Texas  as  a  subsidiary,  and then
consummated  a  holding  company  reorganization  which  resulted  in the parent
company  (TCRI) and the subsidiary (Petrosearch Texas) reversing positions, such
that  TCRI  became  a  subsidiary  of  Petrosearch  Texas.  In  November  2003,
immediately following the merger, we agreed to sell the outstanding stock of the
TCRI  subsidiary  back  to  its  former  shareholders.  Under  the  terms of the
agreement,  Petrosearch  Texas conveyed the capital stock of the TCRI subsidiary
to  a  designated  trustee  and  paid  certain  existing  liabilities of TCRI in
exchange for 1,500,000 shares of TexCom, Inc. a separate Texas corporation, plus
an indemnity related to certain existing TCRI liabilities.

In  November 2004, shareholders of Petrosearch Texas approved a 6.5-to-1 reverse
stock  split  which took effect immediately prior to its merger with the Company
on  December  30,  2004.  The  effect  of the merger, among other things, was to
redomicile  to  Nevada.  Upon  the  completion  of  the  merger, shareholders of
Petrosearch  Texas  were  issued shares of our common stock representing 100% of
the then issued and outstanding common shares.

BUSINESS PLAN

We  were  founded  on  the  belief  that,  despite  the  steady  decline of U.S.
hydrocarbon  reserves  and  production  during  the  past  three  decades,  the
consolidation  and  restructuring  of  the  upstream  portion of the oil and gas
industry (including exploration, drilling and production) had left a significant
number  of valuable oil and gas prospects and projects available for acquisition
and development throughout North America.

We  continue  to  implement  our  business  plan  which  is to find high quality
prospects  and  projects  and  provide  the  capital,  along with the technical,
operational  and  administrative  support  and  management  oversight, needed to
develop the projects. We have increased our SEC PV-10 proved reserves from $13.7
million  as  of  December  31, 2004 to $46.5 million as of December 31, 2005. We
have  also  successfully improved the quality of our portfolio and have acquired
assets  that  have  multiple  year growth potential that allow us to efficiently
control  the  amount  and timing of our capital expenditures. In 2006 we plan to
focus  on  the  development  of  our  high  quality properties which will have a
significant impact on our production, revenues and cash flows.

In  late  2005  and  early  2006 we entered into two agreements, for significant
resource projects that we believe will have a major impact on our future growth.
The  first project includes the purchase on November 15, 2005, of a 100% working
interest in a waterflood project consisting of 1,755 acres in the Quinduno Field
located in Roberts County, Texas.


                                        1
<PAGE>
The  second  project  is covered by agreements with the Harding Company (Dallas,
TX)  which  entered into a strategic Lease Acquisition and Development Agreement
with  ExxonMobil  Corporation  dated  June  29,  2005  (the  "ExxonMobil/Harding
Agreement").  The  ExxonMobil/Harding  Agreement provides for the acquisition by
Harding  of  leases  and  development in an area of mutual interest comprised of
approximately  1.6  million acres in the Barnett Shale trend of five North Texas
counties.  Harding is responsible to serve as operator for a significant portion
of  the  area of mutual interest. ExxonMobil is responsible for the construction
of  the  gathering  and  evacuation  system  which will serve the area of mutual
interest.

The  First  Amended  and  Restated Program Agreement between Harding Company and
Petrosearch  (the  "First  Amended and Restated Program Agreement") provides for
our  acquisition  from  Harding  of a 24.938% before payout and 14% after payout
working  interest in the project. Harding has also extended participation rights
to  two  other  companies under separate agreements. At the time of execution of
the  First Amended and Restated Program Agreement, Harding had not obtained from
Exxon  Mobil  a  consent  to  transfer and waiver of ExxonMobil's a preferential
purchase right set forth in the ExxonMobil/Harding Agreement. At the time of our
execution  of  and  initial funding under the First Amended and Restated Program
Agreement,  Petrosearch  did  not  have  a  direct contractual relationship with
ExxonMobil.  We  believed that all conditions necessary to assign and convey the
working  interest  from  Harding  had  been  met.

We  subsequently learned that ExxonMobil had not waived its right to consent and
its preferential purchase rights.  We further learned that ExxonMobil desired to
explore  possible  alternative  ownership structures beneficial to all concerned
before  providing  a  waiver  of  the preferential rights.  On March 30, 2006 we
entered  into  an  Extension  Agreement  with ExxonMobil, Harding, and two other
parties  that extends the preferential purchase right of ExxonMobil until May 2,
2006  (the  "Extension Agreement").    The purpose of the Extension Agreement is
to  give  all  the  parties involved the ability to explore possible alternative
structures  with the goal to form an integrated venture which would include both
upstream  and  pipeline  assets  and  activities,  which would better align each
party's  interest,  and which would enhance the ability of the venture to assure
that  adequate  pipeline  capacity  would  be  available  to move natural gas to
market.  The  opportunity to participate in an integrated venture which includes
the  gathering  and  evacuation  system was not present in the First Amended and
Restated  Program  Agreement  and  thus, the potential alternative structure has
potential  positive  features.

The Extension Agreement  preserves to the parties all of their respective rights
and  claims  as  they existed prior to the execution of the Extension Agreement.
However,  in  the  event  that  the  parties  cannot  achieve  a mutually agreed
alternative  structure  on  or before May 2, 2006, ExxonMobil could exercise its
preferential purchase right which, if exercised, would prevent our participation
in  the project.  In the event of such a loss of this opportunity to participate
in  the  project, our legal rights are not prejudiced by the Extension Agreement
and  we  expect to pursue all potential remedies available to us relating to the
factual  circumstances  surrounding  these  agreements.

EMPLOYEES AND INDEPENDENT CONTRACTORS

As  of  December  31,  2005,  we  had 12 employees, of which 7 are in management
positions.  None of our employees are represented by a union and we consider our
employee  relations  to  be  good.  Additionally, as of December 31, 2005 we had
independent contractor relationships with one person.

ITEM  2.     PROPERTIES

BARNETT SHALE PROJECT

In  February,  2006,  we  entered  into  a  First  Amended  and Restated Program
Agreement  (the  "First  Amended  and  Restated Program Agreement") with Harding
Company  (Dallas,  Texas)  which  provides  for  our  participation with Harding
Company  and other oil and gas companies in the development of an Area of Mutual
Interest  representing  a  total  of  1.6  million  acres of Barnett Shale lands
located  in  five  North Texas Counties.  The terms of the Program Agreement are
subject to the terms of the existing Lease Acquisition and Development Agreement
dated  June  29, 2005, between Harding Company and ExxonMobil Corporation.    We
completed  funding  for $2.8 million of our $28 million obligation for the first
phase  of  the project on February 6, 2006. Under the First Amended and Restated
Program  Agreement, until our first phase obligation of $28 million is expended,
we  will  pay  34.432%  of the costs of leasing activities, seismic and geologic
costs  and  drilling  and  completion  costs. Our revenue sharing percentage and
operating  cost-bearing  percentage  is  24.938%  until  we  reach  payout  from
production  from all wells in the area of mutual interest; thereafter, our share
of  additional  capital requirements and our working interest will be 14%. As of
March  11,  2006,  significant leasing activity has occurred. The first well was
spudded  on  February  8,  2006 in Tarrant County, Texas, casing was cemented at
9,264  feet  total  depth  on  March  3rd,  and  this  initial  well  is waiting
completion.  The  second  well  in  the project was spudded on March 15, 2006 in
Ellis  County,  Texas.

This project is subject to the pending resolution of all matters relating to the
First  Amended  and  Restated Program Agreement between the Company and Harding,
and  the  contingencies set forth in the Extension Agreement between ExxonMobil,
Harding, the Company and two other parties, as described in the Business section
above.


                                        2
<PAGE>
NORTH TEXAS/PANHANDLE WATER FLOOD PROJECT

In  November,  2005  we  acquired  a 100% working interest in 1,755 acres in the
Quinduno  Field  in  Roberts County, Texas, in the Anadarko Basin. The Company's
working  interest  reduces  to 90% at payout, including the cost of acquisition.
Proved  reserves  are estimated by Ryder Scott to be 2.0 MMbo and 1.1 Bcf of gas
with  an  SEC  PV-10 value of $33.7 million (at December 31, 2005). The purchase
price  (in  November  2005) equated to $3.37 per proved barrel of oil equivalent
(boe)  based  on  a  conversion  factor  of  6 Mcf/bo. As operator, we intend to
extract  the  reserves  through  conventional  water flood technology. The first
phase  of  the  project  began in March 2006 with the drilling of a new well for
production  to  a  depth of 4,495 feet. An unexpected oil saturated dolomite was
found,  and  tested,  approximately  180  feet below the top of the target water
flood  horizon  (Lower  Albany  Dolomite).  The reservoir appears to be normally
pressured  and  does  not  appear to have been produced in the past. The initial
rate  on  pump  is  expected to be approximately 30 bopd with associated gas and
water.  The  well will begin pumping in early April 2006 when surface facilities
and  power are available. As a result of this new zone discovery, the company is
considering  plans  for its development that will not interfere with the planned
water flood development. During 2006, a minimum of 4 old wells will be converted
to injection wells and water injection will begin.

RODNEY ISLAND, TENSAS PARISH, LOUISIANA

In  October  2005,  we took over operations of the Harper Z-1 well on the Rodney
Island prospect from the previous operator after casing was set and cemented. We
are  in  the  process of completing the well that was directionally drilled to a
measured  depth  of  11,701  feet  (vertical  depth  =  9,373  feet)  and logged
approximately 19 feet of oil sand in the Tuscaloosa Massive Sand.

Re-mapping  based  on  the additional data from the Harper Z-1 well indicates as
many  as  2  additional proved locations and 3 other identified locations. Ryder
Scott estimates proved reserves net to our share as of December 31, 2005 to be -
49.4 Mbo and 26 MMcf. We have a 25% working interest before payout in the Harper
Z-1  well  and  18.75%  working interest after payout. We have an 18.75% working
interest in all additional wells.

GRUMAN PROSPECT, STARK COUNTY, NORTH DAKOTA

In  September 2005 we purchased an additional 21.25% working interest, giving us
an  85%  working  interest  in  this Lodgepole Reef oil well. We plan to drill a
9,900  foot  increased  density  well  up  dip  of the Gruman 18-1 well into the
productive reef. Depending on the success of this new well, one of the two wells
is  expected  to  eventually  be  converted to water injection. Proved developed
reserves  in  the prospect to our share of the well as of December 31, 2005, are
309  Mbo  and  82 MMcf of natural gas, as estimated by a third party engineering
firm,  McCartney  Engineering,  LLC.  The  increased density well was spudded on
March 28, 2006.

SW GARWOOD, COLORADO COUNTY, TEXAS

The initial well on this prospect, the Pintail #1, completed in the Upper Wilcox
in  December  2004,  is  expected to pay out by the end of the second quarter of
2006  from  the  first  of 5 potentially productive zones. The well is currently
producing  approximately 500 Mcfd with 8 barrels of condensate. After pay out we
will  back-in  for  33-1/3%  working  interest until payout of all project money
spent  to-date,  including acquisition costs, at which time our working interest
will reduce to 13.33%.

The second well, Pintail Flats #1, was completed and fracture stimulated in May,
2005  in the deepest sand penetrated by the well in the Lower Wilcox. Completion
problems  resulting  from  the  fracture  treatment  have  resulted  in the well
performing below expectations (producing approximately 200 Mcfd) from this zone.
An engineering review of available data is underway to determine the best way to
maximize the production rate from the current zone. The well has an additional 5
potentially productive zones in the Lower Wilcox and 3 in the Upper Wilcox.


                                        3
<PAGE>
Net  proved  reserves  for this project, as estimated by Ryder Scott Company are
1.2  Mbo  and  642  MMcf  of natural gas. Of the 2,402 acres in the prospect, we
have:  20%  working interest in approximately 240 acres; 33.33% working interest
after payout on a well by well basis in 1,018 acres that reduces to 13.33% after
project  payout; 33.33% working interest after payout on a well-by-well basis in
640  acres  that reduces to 18.33% at project payout; and 21.5% working interest
after  payout  on  a  well  by well basis in 444 acres that reduces to 19.25% at
project  payout.  The  cost  of  the  two  existing wells has been funded by our
drilling partner.

BUENA VISTA, JEFFERSON COUNTY, MISSISSIPPI

We  fracture  stimulated  and  tested  approximately  80  feet  of  potentially
productive sands at the base of the Hosston zone without establishing commercial
production  in the Phillips-Burkley #1 well during 2005. The presence of gas was
established  but  production  rates  were  non-commercial. These sands have been
abandoned  and  we  plan  to  test  and  complete  the  well  in  a  portion  of
approximately  280  feet  of potentially productive Hosston sands up-hole, which
appear  to  have  superior  reservoir  properties  compared to the sands already
tested.

The  Phillips-Burkley  #  1,  an exploratory gas well on a leasehold position of
7,481  acres,  has  been funded by our drilling partner. We are the operator and
have  a 50% working interest in the well and acreage. If commercial reserves can
be established, the structure could support in excess of 22 additional wells.

MISSISSIPPI TUSCALOOSA PROJECTS

We  have identified five Tuscaloosa oil prospects in the Mississippi Inland Salt
Basin,  in  Yazoo  County,  comprising  a  maximum  of  2,295 acres and up to 18
potential drilling locations. Eight locations are planned to be drilled in 2007,
ranging  from  6,150  feet  to  7,500  feet  in  depth. Approximately 40% of the
required  acreage  has  been  leased  and seismic data on the prospects is being
reprocessed. We own 100% of the prospects and will operate the project.

CENTRAL TEXAS/GULF COAST PROJECTS

TAIT  PROJECTS - COLORADO COUNTY, TEXAS. This is a natural gas prospect with the
potential  of up to 7 locations on 1,250 net acres. The prospects consist of two
primary  targets  in  the Upper Wilcox at approximately 10,000 feet. All acreage
has  been  leased  and  we  have  acquired  and analyzed 3-D seismic data on the
prospect.  The  initial  well  has  a planned spud date in the second quarter of
2006. Four wells in the project are planned for 2006. We have a 10% non-operated
working interest.

BURLESON  COUNTY,  TEXAS,  PROJECTS  --  A  multi-well  natural gas project that
includes  a  total  of 15 development and step-out locations in the Austin Chalk
and  Georgetown  formations  at  approximately  10,000  feet vertical depth on a
maximum  leasehold  position  of up to 8,400 acres. Horizontal wells are planned
with  total  measured  length  of approximately 13,000 feet. The initial well is
planned to be spudded in the third quarter of 2006 with a second well planned in
the  fourth  quarter of 2006. We will have a 37.5% non-operated working interest
in the project.

OIL AND NATURAL GAS RESERVES

Our  estimate of proved reserves is based on the quantities of oil and gas which
geological  and  engineering  data demonstrate, with reasonable certainty, to be
recoverable  in  future  years from known reservoirs under existing economic and
operating  conditions. The accuracy of any reserve estimate is a function of the
quality  of  available  data,  engineering  and  geological  interpretation, and
judgment.  For  example,  we  must  estimate  the  amount  and  timing of future
operations,  development activities and costs, and work-over costs, all of which
may  in  fact  vary considerably from actual results. In addition, as prices and
costs  change  from  year to year, the estimate of proved reserves also changes.
Any  significant  variance  in  these  assumptions  could  materially affect the
estimated quantity and value of our reserves.


                                        4
<PAGE>
Despite  the  inherent  imprecision in these engineering estimates, our reserves
are  used  throughout  our  financial  statements. For example, since we use the
unit-of-production  method  to amortize our oil and gas properties, the quantity
of  reserves  could  significantly  impact  our  depreciation,  depletion  and
amortization  expense and accretion expense. Our oil and gas properties are also
subject  to  a  "ceiling" limitation based in part on the quantity of our proved
reserves. Finally, these reserves are the basis for our supplemental oil and gas
disclosures.

For  the  vast  majority  of  our  reserves,  we  engage  independent  petroleum
engineering  firms to prepare our estimates of proved hydrocarbon liquid and gas
reserves.  These reserve estimates have not previously been filed with any other
Federal authority or agency.

The  following  tables  set forth summary information with respect to our proved
reserves as of December 31, 2005, as estimated by compiling reserve information,
which  was  prepared  by the engineering firms of Ryder Scott Company, McCartney
Engineering,  LLC  and  internally  generated  engineering  estimates  (internal
estimates make up less than 1% of our proved reserve estimates).

<TABLE>
<CAPTION>
                                                     Net Reserves                    Pre-Tax Present
                                                                                     Value of Future
                                                                                      Net Revenues
          Category                 Oil (Bbls)         Gas (Mcf)           BOE(1)
<S>                           <C>               <C>               <C>               <C>
          December 31, 2005
          Proved Developed             330,838           229,747           369,129  $      9,368,196
          Proved Undeveloped         2,014,956         1,614,000         2,283,956  $     37,084,128

          Total Proved               2,345,794         1,843,747         2,642,011  $     46,452,324
          ------------------------------------------------------------------------------------------
</TABLE>

     (1)  Estimated using a conversion ratio of 1.0 Bbl/6.0 Mcf (thousand cubic
          feet).

Reserve  engineering  is  a  subjective  process  of  estimating  underground
accumulations  of  crude oil, condensate and natural gas that cannot be measured
in  an  exact  manner, and the accuracy of any reserve estimate is a function of
the  quality  of available data and of engineering and geological interpretation
and  judgment.  The  quantities  of  oil  and  natural  gas  that are ultimately
recovered,  production  and  operating  costs,  the  amount and timing of future
development  expenditures and future oil and natural gas sales prices may differ
from  those assumed in these estimates. Therefore, the pre-tax 10% Present Value
of  Future  Net  Revenues  amounts  shown  above  should not be construed as the
current  market  value  of  the oil and natural gas reserves attributable to our
properties.

In accordance with the guidelines of the Securities and Exchange Commission, the
engineers'  estimates of future net revenues from our properties and the pre-tax
10%  Present Value of Future Net Revenues thereof are made using oil and natural
gas  sales  prices in effect as of the effective dates of such estimates and are
held  constant  throughout  the  life  of  the  properties,  except  where  such
guidelines  permit  alternate  treatment,  including  the  use  of  fixed  and
determinable contractual price escalations.

PRODUCTIVE WELLS

The  following  table  sets  forth the total number of our active well bores and
working interest (WI) we maintain in each well as of March 15, 2006:

<TABLE>
<CAPTION>
          -----------------------------------------------
                                   NO. OF    WI      WI
                                   WELLS   (OIL)   (GAS)
          -----------------------------------------------
<S>                                <C>     <C>     <C>
          Gruman 18-1                   1     85%     85%
          -----------------------------------------------
          Gordon 1-18                   1     95%     N/A
          -----------------------------------------------
          Maddox (Quinduno)(1)          2    100%    100%
          -----------------------------------------------
          Pintail #1 (2)                1  33.33%  33.33%
          -----------------------------------------------
          REP Pintail Flats(2)          1  33.33%  33.33%
          -----------------------------------------------

          -----------------------------------------------
          TOTAL PRODUCTIVE WELLS        6
          -----------------------------------------------
</TABLE>


                                        5
<PAGE>
          (1)  Project  in  which  the Company's working interest reduces to 90%
               (as  described  in  ITEM  2  -  North Texas/Panhandle Water Flood
               Project).
          (2)  Well  in  which  we  have  a  reversionary back-in interest after
               payout.  (as  described  in ITEM 2 - SW Garwood, Colorado County,
               TX)

Productive  wells  consist  of  producing wells and wells capable of production,
including gas wells awaiting pipeline connections as of March 15, 2006.

ACREAGE

The  following  table  summarizes  our  gross  and net developed and undeveloped
natural gas and oil wells and acreage under lease as of March 15, 2006:

<TABLE>
<CAPTION>
-----------------------------------------------------------
                                   WELLS        ACREAGE
-----------------------------------------------------------
STATE                           GROSS  NET   GROSS    NET
-----------------------------------------------------------
<S>                    <C>      <C>    <C>   <C>     <C>
-----------------------------------------------------------
DEVELOPED ACREAGE:
-----------------------------------------------------------
Texas
  Garwood              Gas          2  .667    1280     426
  Maddox (Quinduno)    19 Oil      20    20    1755    1755
                       1 Gas
-----------------------------------------------------------
North Dakota           Oil (1)      1   .85     280     238
-----------------------------------------------------------
Oklahoma               Oil          1   .95     610     579
-----------------------------------------------------------

-----------------------------------------------------------
UNDEVELOPED ACREAGE:
-----------------------------------------------------------
Louisiana                                     2,000     500
-----------------------------------------------------------
Texas                                         9,347   3,173
-----------------------------------------------------------

-----------------------------------------------------------
Mississippi                                   7,925   4,325
-----------------------------------------------------------
Oklahoma                                      7,366   6,563
-----------------------------------------------------------
Montana                                       2,108   2,108
-----------------------------------------------------------
      TOTAL                        24  22.5  32,671  19,667
-----------------------------------------------------------
</TABLE>

Undeveloped  acreage  is  considered to be those lease acres on which wells have
not  been drilled or completed to the extent that would permit the production of
commercial  quantities  of natural gas or oil, regardless of whether or not such
acreage  contains  proved reserves. As is customary in the oil and gas industry,
we  can  retain  our  interest  in undeveloped acreage by drilling activity that
establishes  commercial  production  sufficient  to  maintain  the  leases or by
payment  of delay rentals during the remaining primary term of such a lease. The
natural  gas and oil leases in which we have an interest are for varying primary
terms;  however,  most of our developed lease acreage is beyond the primary term
and is held so long as natural gas or oil is produced.


                                        6
<PAGE>
OPERATOR ACTIVITIES

We currently operate all of our producing properties, and will generally seek to
become  the  operator of record on properties we drill or acquire in the future.
We  will  have  a  non-operated  interest  in the Barnett Shale project (pending
resolution  of  all  matters  associated  with  Program  Agreement and Extension
Agreement  described  herein)  and  in  one  exploratory  well  being drilled in
Woodward County, Oklahoma.

DRILLING ACTIVITIES

The following table sets forth our drilling activities for the last 3 fiscal
years. Our working interests in the productive wells owned as of December 31,
2005, range from a direct working interest of 95% to after payout working
interest of 33-1/3%. In 2005, we drilled two additional wells not shown on the
table; the Harper Z-1 in Rodney Island, Tensas Parish, Louisiana and the
Phillips-Burkley #1 in Jefferson County, Mississippi. Both of these wells were
in various stages of testing or completion as of March 15, 2006 and commercial
viability had not been established as of that date. Subsequent to December 31,
2005, we have drilled one exploratory well and spudded a second well in Texas,
one development well in Texas, and one exploratory well in Oklahoma Oklahoma and
spudded an increased density well in North Dakota. All three of the new wells
that have we completed drilling are in various stages of testing or completion.

<TABLE>
<CAPTION>
         --------------------------------------------
                              Year Ended December 31,

         --------------------------------------------
                               2005   2004   2003

         --------------------------------------------
<S>                           <C>     <C>    <C>
          Development Wells:
         --------------------------------------------
          Productive           4 (1)      5    -0-
         --------------------------------------------
          Non-Productive       0         -0-   -0-
         --------------------------------------------
                TOTAL          4          5    -0-
         --------------------------------------------

         --------------------------------------------
          Exploratory Wells:
         --------------------------------------------
          Productive           1 (2)      4      3
         --------------------------------------------
          Non-Productive       3         10     -0-
         --------------------------------------------
                TOTAL          4         14      3
         --------------------------------------------

         --------------------------------------------
          Total Wells:
         --------------------------------------------
          Productive           5          9      3
         --------------------------------------------
          Non-Productive       3         10     -0-
         --------------------------------------------

         --------------------------------------------
                TOTAL          8         19      3
         --------------------------------------------
</TABLE>

     (1)  These  four  wells  were  in  the  Blue  Ridge property, which we sold
          effective  July  1,  2005.
     (2)  We  have a 33-1/3% working interest after payout in this well, the REP
          Pintail  Flats.  Our  working  interest  reduces  to 13.33% at project
          payout  as  described  in  ITEM  2 - SW Garwood, Colorado County, TX).


NET PRODUCTION, UNIT PRICES AND COSTS

The  following  table  presents certain information with respect to oil, gas and
condensate  production attributable to interests in all of our fields. Including
the average sales prices received and average production costs during the fiscal
periods ended December 31, 2005 and December 31, 2004


                                        7
<PAGE>
<TABLE>
<CAPTION>
     ----------------------------------------------------------
                                                  2005    2004
     ----------------------------------------------------------
<S>                                              <C>     <C>
     Average sales price per barrel of oil       $50.34  $36.06
     equivalent
     ----------------------------------------------------------
     Lifting costs per barrel of oil equivalent  $11.19  $ 5.90
     ----------------------------------------------------------
</TABLE>

DESCRIPTION OF OFFICE PROPERTIES

We currently have two office locations, one in Houston and one in Dallas, Texas.
The addresses are as follows:

675 Bering Drive, Suite 200                  4925 Greenville Avenue, Suite 670
Houston, TX 77057                            Dallas, Texas 75206

On  August  1,  2005,  we leased our Dallas location, comprised of approximately
2,100  square  feet of office space which is held under a sixty-four month lease
at  a rate of approximately $2,800 per month (with payments which began December
2005).  Effective  July  15,  2005,  our  principle  executive  offices moved to
approximately  3,700  square  feet of office space at 675 Bering Drive, Houston,
Texas.  We  hold this space under a five-year lease agreement at a lease rate of
approximately $5,000 per month. We believe these properties are adequate for our
corporate office needs.

ITEM  3.     LEGAL PROCEEDINGS

We are currently not a party to any material pending legal proceeding.


ITEM  4.     SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

                                     PART II

ITEM  5.     MARKET  FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
             AND SMALL BUSINESS ISSUER PURCHASES OF EQUITY SECURITIES

Our  common  stock  is quoted on the OTCBB under the symbol "PTSG" The following
table  sets  forth  the quarterly high and low of sales prices per share for the
common  stock  for the last two fiscal years. Our fiscal year ended December 31,
2005.

COMMON STOCK PRICE RANGE

<TABLE>
<CAPTION>
---------------------------------------------------
      QUARTER                  HIGH            LOW
---------------------------------------------------
<S>                           <C>             <C>
1st Quarter 2004 (1)          $20.15          $4.42
---------------------------------------------------
2nd Quarter 2004 (1)          $ 6.57          $4.16
---------------------------------------------------
3rd Quarter 2004 (1)          $ 5.79          $2.21
---------------------------------------------------
4th Quarter 2004 (1)          $ 3.90          $1.95
---------------------------------------------------
1st Quarter 2005              $ 2.60          $1.18
---------------------------------------------------
2nd Quarter 2005              $ 2.20          $1.13
---------------------------------------------------
3rd Quarter 2005              $ 1.83          $0.90
---------------------------------------------------
4th Quarter 2005              $ 1.49          $0.72
---------------------------------------------------
</TABLE>


                                        8
<PAGE>
(1)  All  figures  shown  for  fiscal  quarters  prior to first quarter 2005 are
stated using post-reverse split (6.5-to-1) bid price equivalents.

On  March 15, 2006, the last sales price for the common stock as reported on the
OTCBB  was $1.53. On March 15, 2006, there were approximately 2,500 stockholders
of record of the common stock.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for our common stock is:

Corporate Stock Transfer
3200 Cherry Creek South Drive
Suite 430
Denver, CO 80209
DENVER, CO 80209

DIVIDEND POLICY

We  have  not  paid,  and  do  not currently intend to pay cash dividends on our
common  stock  in  the  foreseeable  future. Our current policy is to retain all
earnings,  if any, to provide funds for operation and expansion of our business.
The  declaration  of dividends, if any, will be subject to the discretion of the
Board of Directors, which may consider such factors as our results of operation,
financial condition, capital needs and acquisition strategy, among others.

EQUITY COMPENSATION PLAN INFORMATION
The  following table sets forth all equity compensation plans as of December 31,
2005:

<TABLE>
<CAPTION>
     ------------------------------------------------------------------------------------------------
                                                                                NUMBER OF SECURITIES
                                                                              REMAINING AVAILABLE FOR
                                                                               FUTURE ISSUANCE UNDER
                            NUMBER OF SECURITIES TO      WEIGHTED-AVERAGE       EQUITY COMPENSATION
                            BE ISSUED UPON EXERCISE     EXERCISE PRICE OF         PLANS (EXCLUDING
                            OF OUTSTANDING OPTIONS,    OUTSTANDING OPTIONS,   SECURITIES REFLECTED IN
                              WARRANTS AND RIGHTS      WARRANTS AND RIGHTS          COLUMN (A))

         PLAN CATEGORY                (A)                      (B)                      (C)
     ------------------------------------------------------------------------------------------------
<S>                         <C>                       <C>                     <C>
     Equity compensation              N/A                      N/A                      N/A
     plans approved by
     security holders
     ------------------------------------------------------------------------------------------------
     Equity compensation             8,495,045                $3.57                     N/A
     plans not approved by
     security holders
     ------------------------------------------------------------------------------------------------
            TOTAL                    8,495,045                $3.57                     N/A
     ------------------------------------------------------------------------------------------------
</TABLE>

RECENT SALES OF UNREGISTERED SECURITIES

Set  forth  below  is  information  regarding  the  issuance  and  sales  of our
securities without registration during the last three years. Except as otherwise
noted,  all  sales below were made in reliance on Section 4(2) of the Securities
Act  of 1933, as amended. No advertising or general solicitation was employed in
offering  the securities. In each instance, the offerings and sales were made to
a  limited  number  of  persons,  who were either (i) accredited investors, (ii)
business  associates  of  the  Company  (iii)  employees of the Company, or (iv)
executive  officers  or  directors  of the Company. In addition, the transfer of
such  securities  were  restricted  by  the  Company  in  accordance  with  the
requirements  of  the Act. Furthermore, all of the above-referenced persons were
provided with access to our filings with the Securities and Exchange Commission.


                                        9
<PAGE>
1.  In  February  2006,  we completed a private placement of 1,928,573 shares of
common  stock with nine investors for total gross proceeds of $2,700,000 and net
proceeds  of $2,560,000. We also issued 964,286 common stock warrants related to
the  private  placement at an exercise price of $2.00 and a term of three years.
Arabella Securities served as placement agent for the sale of these shares which
were  placed exclusively to a group of accredited investors. The placement agent
received  a  cash  commission  representing  5% of the gross proceeds and 96,429
warrants  representing  5%  of  the common shares issued at an exercise price of
$2.00 and a term of three years.

2.  In  November 2005, we entered into an asset purchase agreement with Quinduno
Energy, LLC for the purchase of a 100% working interest in 1,755 acres in Robert
County,  Texas.  Pursuant  to  the November agreement we were required to pay on
November  15, 2005, $500,000 in cash and 500,000 shares of our restricted common
stock. Pursuant to the same asset purchase agreement with Quinduno Energy listed
above  we issued on February 27, 2006 $250,000 in cash and 500,000 shares of our
restricted common stock.

3.  In September 2005, we amended and restated our revolving credit agreement as
discussed  herein.  Pursuant  to  this agreement we issued 100,000 of our common
stock  warrants at an exercise price of $2.00. These warrants were issued to the
lender for financing costs associated with the revolving credit agreement. These
warrants  expire  in  November  2007.

4.  In  April  2005,  we  completed the private placement of 8,153,846 shares of
common  stock  with twenty-one investors for total gross proceeds of $10,600,000
and  net  proceeds of $9,900,000. Sterne, Agee & Leach served as placement agent
for  the  sale  of  these  shares  which  were  placed exclusively to a group of
accredited investors primarily consisting of U.S.-based institutional investment
funds. The placement agent received a commission of 6% of the gross proceeds.

5.  In  January  2005,  we  issued  512,821  shares  of  our common stock to one
accredited  investor for $1.95 per share, or $1,000,000. On January 24, 2005, we
agreed  to  sell  512,821 shares of our common stock to two accredited investors
who  are  affiliates of the original accredited investor at a price of $1.95 per
share  for  total  proceeds  of $1,000,000. We issued 412,821 of these shares in
late  January  2005  and 100,000 of these shares in April 2005. Subsequently, in
April  2005,  we issued an aggregate of 512,800 additional shares to these three
investors to effect a price adjustment from $1.95 to $1.30 as required under the
provisions  of  the  share  purchase  agreements. No underwriter or other person
participated in and no commissions were paid on these transactions.

6. In December 2004, immediately prior to our redomicile and merger, Petrosearch
Texas  exchanged  one  new  Petrosearch Texas share in exchange for 6.5 existing
shares of Petrosearch Texas pursuant to a reverse split approved by the majority
of  its  shareholders. Simultaneously, and solely for the purpose of redomicile,
Petrosearch  Texas  merged  into  Petrosearch  Nevada,  a company with identical
articles  of  incorporation,  bylaws,  capitalization  and  board  of  directors
members, resulting in each post reverse share of Petrosearch Texas receiving one
share  of  Petrosearch  Nevada. We relied upon Section 3(a)9 of the Act for this
exchange  to  approximately  192  existing shareholders of Petrosearch Texas. No
underwriter  participated  in,  nor  did  we  pay any commissions or fees to any
underwriter  or  other  person  in  connection  with  any of these transactions.
Additionally,  all of the existing Petrosearch Texas warrants were exchanged for
our  warrants on the same terms, giving effect to the reverse split, pursuant to
Section  3(a)9 of the Act for this exchange. As part of this exchange, we issued
3,696,154  warrants  to  approximately  44  individuals  who had previously been
issued warrants as compensation to directors, executive officers, and subsidiary
presidents,  and as consideration to members of the Advisory Committee for their
services.  No  underwriter  or  other person participated in, nor did we pay any
commissions or fees to any underwriter or other person in connection with any of
these transactions.

7.  In October and December 2003, 2003A Bonds were issued with a total principal
amount  of  $200,000  with  $150,000  issued  in  October  and $50,000 issued in
December, which were due in October and December 2006, respectively. These bonds
have  subsequently been paid. The bonds were issued to four accredited investors
in  a private transaction in reliance on Section 4(2) of the Act. No underwriter
participated in, nor


                                       10
<PAGE>
did  we pay any commissions or fees to any underwriter in connection with any of
these transactions.

ITEM  6.     MANAGEMENT'S  DISCUSSION  AND  ANALYSIS  OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

In  2005,  as a new management team, our main focus was on improving the quality
of  our  portfolio of oil and gas assets. We increased our proved PV-10 reserves
from  $13.7  million  at  December  31, 2004 to $46.5 million as of December 31,
2005.  By  high grading our portfolio we have acquired assets that have multiple
year  growth potential that allows us to more efficiently control the amount and
timing of our capital expenditures. In 2005 we have also disposed of assets that
did  not  meet  our  risk/reward  parameters. Our current portfolio is extremely
diversified relative to oil versus gas, big capital needs versus smaller capital
needs,  and  high  risk  exploration  versus lower risk/reward development. This
gives us the ability to make sound decisions as to where our capital should most
appropriately  be deployed. We believe we were successful in 2005 at creating an
extremely  high-graded  portfolio  of  oil  and  gas  assets  and  a  sound
infrastructure, which enables us in 2006 to focus on the development of our high
quality  properties  which  should  have a significant impact on our production,
revenues and cash flows.

RESULTS OF OPERATIONS

The  following  discussion  should  be  read  in  conjunction  with  our audited
consolidated  financial  statements  and  the  related  notes  to  the financial
statements included in this Form 10-KSB.

The  factors  that  most significantly affect our results of operations are: (i)
the  sale  prices  of  crude  oil and natural gas; (ii) the amount of production
sales; and (iii) the amount of lease operating expenses. Sales of production and
level  of  borrowings  are  significantly impacted by our ability to maintain or
increase  production  and  reserves from existing oil and gas properties through
exploration and development activities.

FOR  THE  YEAR  ENDED  DECEMBER 31, 2005 COMPARED TO THE YEAR ENDED DECEMBER 31,
2004

REVENUES

Consolidated  oil  and  gas  production revenues for the year ended December 31,
2005 were $1,701,043 versus $4,718,313 for the year ended December 31, 2004. The
decrease  in revenues from 2004 to 2005 is a result of several factors including
the  sale  of  the Blue Ridge Field in Fort Bend County, Texas in July 2005. The
Blue  Ridge field accounted for 32,500 barrels of oil in 2004 versus only 12,600
barrels in 2005, due primarily to the sale of the asset in mid 2005.

Secondly,  the  decrease in production in 2005 was due to the continued pressure
depletion  and  eventual  temporary shut down in October 2005 of our Gruman 18-1
well  in  Stark  County North Dakota. In mid 2004 the well started to experience
significant  pressure  depletion  which  continued through 2005. The Gruman 18-1
well  produced  98,600 boe in 2004 (86% of that production in the first 6 months
of  2004),  versus  total production of 19,800 boe in 2005. We have attempted to
mitigate  the effects of the pressure depletion with a submersible pump, however
this  pump  was  down from October 27, 2005 through March 9, 2006. We have begun
the  drilling  of  an  increased density well on March 27, 2006 in an attempt to
increase the production of the well significantly.

Our  future  revenue  will  be  principally  dependent  upon  the success of the
development  of our current quality prospects and projects as well as the market
price  for  crude oil and natural gas. We plan to focus capital resources on the
Barnett  Shale  resource  project  (pending resolution of all matters associated
with  Program  Agreement  and  Extension  Agreement  described  herein),  the
development  of  our  proved properties in Texas, Louisiana and North Dakota, as
well as our exploration projects in Texas and Mississippi.

We  have not previously utilized any hedging instruments and have no plans to do
so in the foreseeable future.


                                       11
<PAGE>
LEASE OPERATING AND PRODUCTION TAX EXPENSE

Lease  operating  and  production  tax  expense for the years ended December 31,
2005,  and  December  31,  2004, were $581,313 and $773,723, respectively. These
expenses,  which are primarily outsourced to third party vendors and contractors
relate  to  the  day  to day costs that are incurred to operate and maintain our
wells  and  related  production equipment. The decrease is partly related to the
decrease  in  production from 2004 to 2005 as explained above. However; although
these  expenses have decreased from 2004 to 2005, they have not decreased on the
same proportion as production revenue. This relates to the fact that even though
production  taxes  reduce proportionately to production revenue, lease operating
expenses  will  not necessarily reduce proportionately; lease operating expenses
continue  to be incurred even when production is declining as in the case of our
North Dakota well.

DEPLETION, DEPRECIATION AND AMORTIZATION

Costs  for depletion, depreciation and amortization for the years ended December
31,  2005,  and  December  31, 2004, were $563,252 and $2,219,998, respectively.
Depletion  expense  per  barrel  of oil equivalent was $15.24 and $16.83 for the
years  ended  December  31,  2005  and  2004 respectively. Although there was an
increase  in  properties  subject  to  amortization  of  depletion of $6,359,073
($11,849,520  and  $5,490,447  in December 31, 2005 and 2004 respectively), that
increase  was  offset  by  two  factors  that  would  cause  a decrease in total
depletion:  1)  the significant decrease in production from 2004 to 2005 (35,676
boe  and  131,194  boe  for  the  years  ending  December  31,  2005  and  2004,
respectively),  and  2)  the increase in proved reserves of 2.1 million boe from
2004  to  2005.  Depletion  is  calculated  using  the  percentage  of  units of
production over the total proved reserves. Therefore, being that our total units
produced  decreased  and  our  total  proved  reserves  increased, our depletion
percentage of proved properties subject to amortization of depletion decreased.

GENERAL AND ADMINISTRATIVE EXPENSES

General  and  administrative expenses for the years ended December 31, 2005, and
December  31,  2004,  were  $3,268,088 and $3,239,184 respectively. Although the
general  and  administrative  expenses  for these periods were comparable, there
were  differences in the actual expenses that were incurred. In 2004 the Company
did  not  have  any  employees  and  all  the  personnel  costs  were treated as
consulting  fees. In January 2005 all of the officers and other personnel became
employees.

Also  in  2005  we  reduced  significant areas of the general and administrative
expenses  while  also  increasing the quality and effectiveness of the resources
that  we  spent  our  funds on. These decreases are not directly apparent to the
total  general and administrative expenses due to inclusion of the write-offs in
2005 of bad debts and prepaid credits related to prior period operations.

In  May  2005  we  increased  our  technical  expertise  by  hiring  5 technical
employees, including our COO, Manager of Operations, Manager of Geology, Manager
of  Land  and  Manager  of  Engineering.  We  believe  we achieved a significant
accomplishment  by  increasing our technical expertise and writing off bad debts
and  prepaid  credits  with  our  general  and administrative expenses remaining
constant  from  2004  to 2005. Significant details of general and administrative
expenses listed below:

<TABLE>
<CAPTION>
     --------------------------------------------------------------
                                  2004        2005      DIFFERENCE
     --------------------------------------------------------------
     --------------------------------------------------------------
<S>                            <C>         <C>         <C>
     Third Party Consulting    $2,051,844  $  590,581  $(1,461,263)
     --------------------------------------------------------------
     Employee Costs                   -0-   1,413,398    1,413,398
     --------------------------------------------------------------
     Travel and Entertainment     213,444     138,227      (75,217)
     --------------------------------------------------------------
     Accounting and Legal         491,154     416,114      (75,040)
     --------------------------------------------------------------
     Bad debts and prepaid            -0-     205,443      205,443
     credits
     --------------------------------------------------------------
     --------------------------------------------------------------
</TABLE>


                                       12
<PAGE>
NET LOSS FROM OPERATIONS

We generated a net operating loss of $2,711,610 or $0.11 per share, for the year
ended  December  31,  2005,  compared  to  a net loss of $1,514,592 or $0.09 per
share,  for the year ended December 31, 2004. The $1,197,018 variance is related
mainly  to  the  decrease  in production from our North Dakota well as explained
above and due to the sale of our Blue Ridge Field asset. There was no profit and
loss  effect  of  the sale of the Blue Ridge Field asset because under full cost
accounting no gain or loss is recorded on the sale of an asset.

As explained above, our main focus during 2005 was to improve the quality of our
portfolio  of our oil and gas assets and dispose of assets that did not meet our
risk/reward  parameters.  Our  current  portfolio  is  extremely diversified. We
believe  we  were  successful  in  2005  in  creating  an  extremely high-graded
portfolio of oil and gas assets and a sound infrastructure, which will enable us
to  focus  on  the  development  of our high quality properties in 2006 which we
anticipate,  will  have  a  positive impact on our production, revenues and cash
flows.

LIQUIDITY AND CAPITAL RESOURCES

Since  inception,  we  have  primarily financed our operating and investing cash
flow  needs  through  private offerings of equity securities, sales of crude oil
and  natural  gas,  and  the use of debt instruments such as corporate bonds and
revolving  credit  facilities.  The  proceeds  from, and the utilization of, all
these  methods have been and Management believes will continue to be, sufficient
to  keep  the operations funded and the business plan moving forward. We plan to
continue  to  utilize  these methods to access capital in order to implement our
business  plan,  which  we believe will be an effective vehicle to carry out our
business plan.

FINANCIAL ADVISORS

On  December  21,  2005  we  engaged the Corporate Finance Division of Macquarie
Securities  (USA)  Inc.  as an exclusive financial advisor. Macquarie's services
will  be utilized in connection with debt or equity transactions the Company may
contemplate.

PRIVATE PLACEMENTS

In  April  2005,  we  completed  sales  of  $12.6 million of our common stock in
private offerings. We received net proceeds of approximately $11.9 million which
were  to  be  used  for  general  corporate  purposes, including the drilling of
projects in our prospect inventory.

In  February  2006,  we completed sales of $2.7 million of our common stock in a
private  offering. We received net proceeds of approximately $2.56 million which
are  to  be  used  for  general  corporate  purposes,  including the drilling of
projects in our prospect inventory.

REVOLVING CREDIT AGREEMENT

In  September 2005 we amended and restated our revolving credit agreement to $10
million  which  allowed Fortuna Energy, L.P. to participate in the ownership and
development  of  an  eight  prospect  package  in our inventory. The significant
provisions of the Credit Facility are as follows:

     The  Credit  Facility  matures  on  the 30-month anniversary of the initial
     advance  (which  occurred  on September 29, 2005) and may be prepaid at any
     time.  Repayment  of  each  tranche borrowed shall be interest only for six
     months  and  shall  then  amortize  on  a  30  month  basis  with  all then
     outstanding  tranches  due  and  payable  April  1, 2008. The last date for
     advances shall be October 15, 2007.

     The  proceeds  may  be utilized for past, present or future acquisitions of
     oil  and  gas  leases,  including  associated costs of technical review and
     analysis, drilling, reworking, production, transportation,


                                       13
<PAGE>
     marketing  and  plugging.  The proceeds may also be used to fund all lender
     charges and fees, including legal fees of Fortuna's counsel.

     Subject to the draw limitations and funds availability provisions described
     below,  we  are  required  to utilize the funds from the Credit Facility to
     fund  lease  acquisitions  by  our  Beacon Petrosearch, L.L.C. and Anadarko
     Petrosearch,  L.L.C.  subsidiaries  before  resorting to funds which may be
     available  internally  or  from  third  parties  (other  than  drilling
     co-venturers).

     The  collateral  for the Credit Facility includes a first and prior lien on
     the  oil  and  gas  leases  acquired  with  Fortuna's funds, as well as the
     equipment  on  any  well  drilled with Fortuna's funds. The collateral also
     includes  all  existing  and  future  lease  interests in the eight project
     package  listed  above  and  the  State of Oklahoma, and all existing lease
     interests  in  North  Dakota  (regardless  of  whether  Fortuna's funds are
     utilized  in  North  Dakota) as well as our membership interest (subject to
     the  possible  payment  to  certain  independent professionals of either an
     ownership interest or a share of the net revenues after-payout as discussed
     above  in  the  section  entitled  "Business Model") in Beacon Petrosearch,
     L.L.C. and Anadarko Petrosearch, L.L.C.

     Under  the  Credit  Facility,  Fortuna will receive a 2% overriding royalty
     interest  of  Petroseach's proportionate net revenue interest in the leases
     acquired  or  drilled  using  Fortuna's funds, as well as a like overriding
     royalty  in  current  leases held in Beacon Petrosearch, L.L.C. and certain
     leases held in Anadarko Petrosearch, L.L.C. in Oklahoma. Under the terms of
     the  Credit  Facility, principal is to be repaid in 24 monthly installments
     equal  to  1/30th  of the principal commencing six months after the initial
     advance,  with  the  balance  being  paid  at the maturity of the facility.
     Interest  shall  be repaid under the Credit Facility at Wall Street Journal
     prime +3% per annum payable monthly in arrears.

As  of  March 15, 2006, the principal balance outstanding pursuant to the Credit
Facility was $3,525,000.

It  is  Management's intent to utilize the Credit Facility to acquire new leases
and  develop  existing  leases  with  these  funds,  securing  the debt with the
collateral required under the terms of the Credit Facility.

SALE OF PROPERTY

In  June  2005  we entered into an option agreement to sell all of the assets of
our  TK  Petrosearch  subsidiary  for  a  cash  purchase  price of approximately
$2,140,000.  The  option  agreement  was  exercised  on  August 3, 2005 with the
effective date of the transfer being July 1, 2005. The assets sold accounted for
$1,370,110  of  our  PV-10  proved  reserves  as  of  December  31,  2004,  or
approximately 10% of our total proved reserve value at that date.

PROJECT FINANCING AND RIGHT OF FIRST REFUSAL

On  January  11,  2006,  we  entered into an Agreement with Rock Energy Partners
("Rock")  covering  the  geographic  areas  of  current  operations in Jefferson
County,  Mississippi  and Colorado County, Texas affecting the Company and Rock,
including  agreements  and  stipulations  regarding  future  operations in those
geographic  areas,  the  terms  under  which  future exploration and development
participation  opportunities shall be offered by the Company to Rock, and agreed
procedures  for  conducting  internal  audits and accounting reconciliations. As
part of the transaction with Rock, the parties have executed an Amended Right of
First  Refusal  Agreement (the "Amended ROFR") which replaces the previous Right
of  First  Refusal  Agreement  between the Company and Rock which was entered in
March 2004 (the "ROFR").

The Amended ROFR has more limited applicability to our various projects than the
ROFR. While the original agreement required all of our prospects to be presented
to  Rock  for  consideration by Rock, the Amended ROFR does not require that all
our  prospects  be offered to Rock for participation. The Amended ROFR also does
not  require that we offer to Rock prospects in any specified area, although the
parties have separately stipulated to certain specified areas of mutual interest
in the Mississippi and Colorado County areas


                                       14
<PAGE>
based  upon historical operations in those areas. The Amended ROFR permits us to
decide  which projects will be offered to Rock, so long as the projects actually
presented  are projects in which the Company owns or intends to retain a minimum
of ten percent (10%) of the project interest available to the Company.

Under  the Amended ROFR, Rock's percentage participation is limited to the range
between  ten percent (10%) minimum participation and forty percent (40%) maximum
participation.  The minimum and maximum participation limits are proportional to
the interest available to the Company. The Amended ROFR also calls for a minimum
funding  commitment  required  from  Rock  equal  to $3,000,000 per year for new
projects,  without  the  right  to  carry  over to any subsequent year as credit
expenditures  above  the minimum required commitment for that year. Rock is also
obligated  to  spend  up  to $8,800,000 for the drilling of one new well and one
well  re-entry  to  test the deep Wilcox at the SW Garwood prospect during 2006.
This  obligation  of  Rock's will cover 100% of the capital requirements for the
two projects.

The  Amended  ROFR provides that the Company to retain in each prospect which is
accepted  by  Rock  a  twenty-five  percent  (25%) reversionary interest in each
interest  assigned  to  Rock, with the reversion to take effect upon "payout" or
recoupment of Rock's development costs net to that interest.

DRILLING PARTNERSHIPS

We  continue  to  strive to develop relationships with institutional or high net
worth individuals to participate in our prospects. Management believes this will
reduce  our  capital risk and increase the diversity of the projects in which we
use  our  own  capital.  We  intend  to  establish  these  drilling  partnership
relationships with terms that are standard in the oil and gas industry.

FORWARD LOOKING STATEMENT AND INFORMATION

This  document  contains  "forward-looking statements" within the meaning of the
Private  Securities  Litigation Reform Act of 1995. These statements are subject
to  risks  and  uncertainties  and  are  based on the beliefs and assumptions of
management  and  information currently available to management. The use of words
such  as  "believes," "expects," "anticipates," "intends," "plans," "estimates,"
"should,"  "likely"  or  similar  expressions,  indicates  a  forward-looking
statement.

Forward-looking  statements  are  not  guarantees  of  performance. They involve
risks,  uncertainties and assumptions. Future results may differ materially from
those expressed in the forward-looking statements. Many of the factors that will
determine  these  results  are  beyond  our  ability  to  control  or  predict.
Stockholders  are  cautioned  not  to  put undue reliance on any forward-looking
statements,  which  speak  only to the date made. For those statements, we claim
the  protection  of  the safe harbor for forward-looking statements contained in
the Private Securities Litigation Reform Act of 1995.

Forward-looking  statements  include  statements  concerning  plans, objectives,
goals,  strategies, future events, or performance and underlying assumptions and
other  statements,  which  are  other than statements of historical facts. These
statements are subject to uncertainties and risks including, but not limited to,
product  and  service  demands  and  acceptance, changes in technology, economic
conditions, the impact of competition and pricing, and government regulation and
approvals.  Petrosearch  cautions  that  assumptions, expectations, projections,
intentions,  or  beliefs about future events may, and often do, vary from actual
results and the differences can be material. Some of the key factors which could
cause  actual  results to vary from those Petrosearch expects include changes in
natural  gas  and  oil  prices,  the  timing  of  planned  capital expenditures,
availability  of  acquisitions,  uncertainties in estimating proved reserves and
forecasting  production  results, operational factors affecting the commencement
or  maintenance  of  producing  wells,  the  condition  of  the  capital markets
generally,  as  well  as our ability to access them, and uncertainties regarding
environmental  regulations  or  litigation  and  other  legal  or  regulatory
developments affecting our business.

Our  expectations,  beliefs  and projections are expressed in good faith and are
believed  to  have  a  reasonable  basis,  including  without  limitation,  our
examination of historical operating trends, data contained in our


                                       15
<PAGE>
records  and other data available from third parties. There can be no assurance,
however, that our expectations, beliefs or projections will result, be achieved,
or  be  accomplished. Readers are cautioned not to place undue reliance on these
forward-looking statements, which speak only as of the date hereof. We undertake
no duty to update these forward-looking statements.

CAUTIONARY NOTE TO U.S. INVESTORS

THE  UNITED  STATES  SECURITIES  AND  EXCHANGE  COMMISSION  PERMITS  OIL AND GAS
COMPANIES,  IN THEIR FILINGS WITH THE SEC, TO DISCLOSE ONLY PROVED RESERVES THAT
A COMPANY HAS DEMONSTRATED BY ACTUAL PRODUCTION OR CONCLUSIVE FORMATION TESTS TO
BE  ECONOMICALLY  AND  LEGALLY  PRODUCIBLE UNDER EXISTING ECONOMIC AND OPERATING
CONDITIONS.  WE  USE  CERTAIN  TERMS  HEREIN,  SUCH  AS  "PROBABLE", "POSSIBLE",
"RECOVERABLE",  AND  "RISKED,"  AMONG OTHERS, THAT THE SEC'S GUIDELINES STRICTLY
PROHIBIT  US  FROM  INCLUDING  IN  FILINGS  WITH  THE  SEC. READERS ARE URGED TO
CAREFULLY  REVIEW  AND CONSIDER THE VARIOUS DISCLOSURES MADE BY US WHICH ATTEMPT
TO  ADVISE  INTERESTED  PARTIES  OF  THE ADDITIONAL FACTORS WHICH MAY AFFECT OUR
BUSINESS.

For  a  discussion  of  some additional factors that may cause actual results to
differ materially from those suggested by the forward-looking statements, please
read  carefully  the  information  under  "Risk  Factors"  section  below.  The
identification  in  this  document of factors that may affect future performance
and  the  accuracy of forward-looking statements is meant to be illustrative and
by  no means exhaustive. All forward-looking statements should be evaluated with
the understanding of their inherent uncertainty.

We  operate  in  a  very competitive and rapidly changing environment. New risks
emerge  from  time  to time and it is not possible for our management to predict
all  risks,  nor  can  we  assess the impact of all risks on our business or the
extent  to  which any risk, or combination of risks, may cause actual results to
differ  from  those  contained  in  any  forward-looking  statements.  All
forward-looking statements included in this Form 10-KSB are based on information
available to us on the date of the Form 10-KSB. Except to the extent required by
applicable  laws  or  rules,  we  undertake  no obligation to publicly update or
revise  any  forward-looking  statement, whether as a result of new information,
future  events  or  otherwise.  All  subsequent written and oral forward-looking
statements  attributable  to  us  or  persons acting on our behalf are expressly
qualified  in  their  entirety by the cautionary statements contained throughout
this Form 10-KSB.

                                  RISK FACTORS

An  investment  in  our  Common Stock involves a high degree of risk. You should
carefully  consider the risks described below before deciding to purchase shares
of  our  Common  Stock.  If  any  of the events, contingencies, circumstances or
conditions  described in the risks below actually occur, our business, financial
condition  or results of operations could be seriously harmed. The trading price
of  our  Common  Stock could, in turn, decline and you could lose all or part of
your investment.

RISKS RELATED TO THE COMPANY

OUR  LIMITED  HISTORY  MAKES  AN  EVALUATION  OF  US  AND  OUR  FUTURE EXTREMELY
DIFFICULT, AND PROFITS ARE NOT ASSURED.

We have a limited operating history, having begun commercial drilling operations
in  August  2003.  There  can  be no assurance that we will be profitable in the
future  or  that the shareholders' investments in us will be returned to them in
full,  or  at  all, over time. In view of our limited history in the oil and gas
exploration  business,  an  investor must consider our business and prospects in
light  of  the  risks,  expenses  and  difficulties  frequently  encountered  by
companies in their early stage of development. There can be no assurance that we
will  be  successful  in  undertaking  any or all of the activities required for
successful commercial drilling operations. Our failure to undertake successfully
such activities could materially and adversely affect our


                                       16
<PAGE>
business, prospects, financial condition and results of operations. In addition,
there  can  be  no assurance that our exploration and production activities will
produce  oil and gas in commercially viable quantities, if any at all. There can
be  no  assurance  that  sales  of our oil and gas production will ever generate
significant  revenues,  that we will ever generate additional positive cash flow
from  our operations or that we will be able to achieve or sustain profitability
in any future period.

WE HAVE EXPERIENCED RECENT SUBSTANTIAL OPERATING LOSSES AND MAY INCUR ADDITIONAL
OPERATING LOSSES IN THE FUTURE.

During the twelve month period ended December 31, 2005 we incurred a net loss of
$2,901,031  In the event we are unable to increase our gross margins, reduce our
costs  and/or  generate  sufficient  additional revenues to offset our increased
costs,  we  may  continue  to sustain losses and our business plan and financial
condition will be materially and adversely affected.

THE  TRADING  PRICE  OF  OUR  COMMON  STOCK  ENTAILS  ADDITIONAL  REGULATORY
REQUIREMENTS, WHICH MAY NEGATIVELY AFFECT SUCH TRADING PRICE.

The  trading  price of our common stock is below $5.00 per share. As a result of
this  price  level,  trading  in  our  common  stock  would  be  subject  to the
requirements  of  certain rules promulgated under the Securities Exchange Act of
1934, as amended. These rules require additional disclosure by broker-dealers in
connection  with  any  trades generally involving any non-NASDAQ equity security
that  has  a  market  price  of  less  than  $5.00 per share, subject to certain
exceptions. Such rules require the delivery, before any penny stock transaction,
of  a  disclosure  schedule  explaining  the  penny  stock  market and the risks
associated  therewith,  and  impose  various  sales  practice  requirements  on
broker-dealers who sell penny stocks to persons other than established customers
and  accredited  investors  (generally  institutions).  For  these  types  of
transactions,  the  broker-dealer  must  determine  the suitability of the penny
stock  for  the  purchaser  and  receive  the purchaser's written consent to the
transaction  before  sale. The additional burdens imposed upon broker-dealers by
such  requirements  may discourage broker-dealers from effecting transactions in
our  common  stock.  As  a consequence, the market liquidity of our common stock
could be severely affected or limited by these regulatory requirements.

IN  THE  FUTURE,  WE  WILL  INCUR  SIGNIFICANT  INCREASED  COSTS  AS A RESULT OF
OPERATING  AS  A  PUBLIC  COMPANY, AND OUR MANAGEMENT WILL BE REQUIRED TO DEVOTE
SUBSTANTIAL TIME TO NEW COMPLIANCE INITIATIVES.

Due  to the effectiveness of our registration statement on September 8, 2005, we
have  begun  incurring  significant  legal,  accounting  and other expenses as a
fully-reporting  public company. In addition, the Sarbanes-Oxley Act of 2002, as
well  as new rules subsequently implemented by the SEC, have imposed various new
requirements  on  public  companies,  including  requiring  changes in corporate
governance  practices.  Our management and other personnel will need to devote a
substantial  amount of time to these new compliance initiatives. Moreover, these
rules and regulations will increase our legal and financial compliance costs and
will make some activities more time-consuming and costly. For example, we expect
these  rules and regulations to make it more difficult and more expensive for us
to  obtain  director  and officer liability insurance, and we may be required to
incur substantial costs to maintain the same or similar coverage.

In  addition,  the  Sarbanes-Oxley  Act  requires,  among  other things, that we
maintain  effective  internal  controls  for  financial reporting and disclosure
controls  and  procedures.  In  particular,  commencing  in fiscal 2007, we must
perform  system and process evaluation and testing of our internal controls over
financial  reporting  to  allow management and our independent registered public
accounting  firm  to  report  on the effectiveness of our internal controls over
financial  reporting,  as required by Section 404 of the Sarbanes-Oxley Act. Our
testing,  or  the  subsequent  testing  by  our  independent  registered  public
accounting firm, may reveal deficiencies in our internal controls over financial
reporting that are deemed to be material weaknesses. Our compliance with Section
404  will  require  that  we  incur  substantial  accounting  expense and expend
significant  management  efforts.  We  currently  do  not have an internal audit
group,  and  we will need to hire additional accounting and financial staff with
appropriate  public  company  experience  and  technical  accounting  knowledge.
Moreover, if we are not able to comply with the requirements of Section 404 in a
timely manner, or if we or our


                                       17
<PAGE>
independent  registered  public  accounting  firm identifies deficiencies in our
internal  controls  over  financial  reporting  that  are  deemed to be material
weaknesses, the market price of our stock could decline, and we could be subject
to sanctions or investigations by the SEC or other regulatory authorities, which
would require additional financial and management resources.

OUR  MANAGEMENT  CONTROLS  A  SIGNIFICANT  PERCENTAGE OF OUR CURRENT OUTSTANDING
COMMON STOCK AND THEIR INTERESTS MAY CONFLICT WITH THOSE OF OUR SHAREHOLDERS.

As  of March 15, 2006, our Directors and executive officers and their respective
affiliates  collectively  and  beneficially  owned  approximately  17%  of  our
outstanding  common  stock,  including  all warrants exercisable within 60 days.
This  concentration of voting control gives our Directors and executive officers
and  their  respective  affiliates  substantial influence over any matters which
require  a  shareholder  vote,  including,  without  limitation, the election of
Directors,  even  if  their  interests  may  conflict  with  those  of  other
shareholders.  It  could also have the effect of delaying or preventing a change
in  control of or otherwise discouraging a potential acquirer from attempting to
obtain  control  of  us. This could have a material adverse effect on the market
price  of  our common stock or prevent our shareholders from realizing a premium
over the then prevailing market prices for their shares of common stock.

CUMULATIVE VOTING IS NOT AVAILABLE TO STOCKHOLDERS.

Cumulative  voting  in  the  election  of  Directors  is expressly denied in our
Articles  of  Incorporation. Accordingly, the holder or holders of a majority of
the  outstanding  shares  of  our  common  stock may elect all of our Directors.
Management's  large  percentage  ownership of our outstanding common stock helps
enable them to maintain their positions as such and thus control of our business
and affairs.

WE ARE DEPENDENT ON KEY PERSONNEL.

We depend to a large extent on the services of certain key management personnel,
including  our  executive officers and other key consultants, the loss of any of
which  could  have a material adverse effect on our operations. Specifically, we
rely on Mr. Richard Dole, Chairman, President and CEO, to maintain the strategic
direction  of  the  Company. We also rely on Mr. Wayne Beninger, Chief Operating
Officer,  to  oversee the technical evaluation of projects as well as operations
of  the  Company.  Although  Messrs.  Dole  and  Beninger  currently serve under
employment  agreements,  there  is  no  assurance  that they will continue to be
employed  by  us.  We  do not maintain, nor do we plan to maintain, key-man life
insurance with respect to any of our officers or directors.

WE ARE SUBJECT TO POTENTIAL LIABILITY FROM OPERATIONS.

We  are  subject to potential liability from our operations, such as injuries to
employees  or third parties, which are inherent in the management of oil and gas
programs.  While we intend to obtain and maintain appropriate insurance coverage
for  these  risks, there can be no assurance that our operations will not expose
us  to  liabilities  exceeding  such  insurance  coverage  or to liabilities not
covered by insurance.

OUR  APPROACH  TO TITLE ASSURANCE COULD MATERIALLY ADVERSELY AFFECT OUR BUSINESS
AND OPERATIONS.

We  intend  to  purchase  working and revenue interests in oil and gas leasehold
interests  from  third  parties  or  directly from the mineral fee owners as the
inventory  upon  which we will perform our exploration activities. The existence
of  a material title deficiency can render a lease worthless and can result in a
large  expense  to  us.  Title  insurance covering the mineral leaseholds is not
generally  available  and  in  all instances, we forego the expense of retaining
lawyers to examine the title to the mineral interest to be placed under lease or
already placed under lease until the drilling block is assembled and ready to be
drilled.  We  rely upon the judgment of oil and gas lease brokers or experienced
landmen  who  perform  the  field  work  in examining records in the appropriate
governmental office before attempting to acquire or place under lease a specific
mineral  interest.  This  is customary practice in the oil and gas industry. Our
operating  agreements  require  us  to  obtain  a


                                       18
<PAGE>
preliminary  title  review of the spacing unit within which the proposed oil and
gas  well  is  to  be  drilled prior to drilling in order to ensure there are no
obvious  deficiencies  in  title  to the well. As a result of such examinations,
certain  curative  work  may have to be performed to correct deficiencies in the
marketability  of  the  title,  and such curative work entails expense. The work
might  include  obtaining  affidavits  of  heirship  or  causing an estate to be
administered.  Occasionally,  the  examination made by the title lawyers reveals
that  the  oil  and  gas lease or leases are worthless, having been purchased in
error  from  a  person  who is not the owner of the mineral interest desired. In
such  instances,  the  amount  paid  for  such  oil  and  gas lease or leases is
generally  lost.  In  general,  the  loss  of a lease does not create a material
adverse effect. However, if the defective lease covers acreage which is critical
to  the  success of a particular project, the loss could have a material adverse
effect by making the target area potentially undrillable. Our customary practice
is to obtain a drill site title opinion prior to drilling a well.

WE MAY EXPERIENCE POTENTIAL FLUCTUATIONS IN RESULTS OF OPERATIONS.

Our  future  revenues may be affected by a variety of factors, many of which are
outside our control, including (a) the success of project results; (b) swings in
availability  of  drilling services needed to implement projects and the pricing
of  such  services;  (c)  a  volatile  oil and gas pricing market which may make
certain  projects  that  we undertake uneconomic; (d) the ability to attract new
independent  professionals  with prospects in a timely and effective manner; and
(e)  the  amount and timing of operating costs and capital expenditures relating
to  conducting  our  business  operations and infrastructure. As a result of our
limited  operating  history  and the emerging nature of our business plan, it is
difficult  to  forecast  revenues  or  earnings  accurately, which may fluctuate
significantly from quarter to quarter.

WE MAY BE UNABLE TO ATTRACT AND RETAIN INDEPENDENT PROFESSIONALS.

Our  future success depends in large part on our ability to identify and acquire
the  talents  of  highly  qualified independent professionals and their specific
projects.  If we are unable to engage a sufficient number of such professionals,
we  may  not  be  able  to  expand our business. We have an innovative expansion
concept within a relatively experienced industry. This concept is so non-typical
that  it  may  take longer to build its acceptance than we currently anticipate.
This  could  delay  implementation  of  projects  and subsequent cash flows. Our
concept  may  prove  to be inadequate to attract quality independent oil and gas
professionals.  Furthermore,  our current subsidiaries will bear a great deal of
scrutiny  by  independent professionals before such professionals are willing to
contribute their projects to our subsidiaries. We have not conducted, or engaged
any  other  person  or entity to conduct, any formal marketing surveys regarding
the potential for our proposed business plan.

WE RELY UPON AN EXISTING CREDIT FACILITY

Our  sole  exiting  credit facility has been provided by Fortuna Energy, L.P., a
private  entity.  Since  a  private  entity  is  not governed by typical banking
regulations,  the negotiated terms of the Fortuna Credit Facility are unique and
could,  in  given  circumstances,  be  less  favorable  to  us  than traditional
financing. Certain of these unique terms are as follows:

On  September  29,  2005,  we renewed and extended our existing revolving credit
facility  with  Fortuna  Energy,  LP  ("Fortuna") hereinafter referred to as the
"Credit  Facility".  The  significant  revised  terms of the Credit Facility are
described below.

The principal available under the revolving borrowing base is $10,000,000, which
will  bear  interest  at  Wall  Street Journal Prime plus three percent (3%) and
mature  on  April  1,  2008. Principal cannot be drawn under the Credit Facility
after  October  1,  2007. Each advance of principal under the Credit Facility is
treated  as  a  separate  loan  and  is  repayable  in  six  (6)  interest-only
installments,  followed  by  up  to  twenty  four  (24)  principal  and interest
installments  based  upon  a  30-month amortization. Additionally, Fortuna shall
charge  quarter-annually  a  standby  fee  equal  to  one quarter of one percent
(0.25%)  of the funds available to be drawn. but not requested by us, unless the
limitations  imposed upon advances under the Credit Facility described below are
then applicable. Prepayment is permitted in amounts of $100,000.00 each or more.


                                       19
<PAGE>
The  proceeds  of  each  advance  may  be  utilized  for past, present or future
acquisitions  of  oil  and  gas  leases, including associated costs of technical
review  and analysis, drilling, reworking, production, transportation, marketing
and plugging. The proceeds may also be used to fund all lender charges and fees,
including legal fees of Fortuna's counsel. The funds are expected to be budgeted
for  and  utilized on eight (8) separate target projects in Texas, Louisiana and
Mississippi.  At  the time of these amendments to the Credit Facility, Fortuna's
collateral  included a first and prior lien on our existing Oklahoma oil and gas
leases,  our  interest  in  the Gruman 18-1 well in North Dakota and our limited
liability  company membership interests in each of Anadarko Petrosearch, LLC and
TK  Petrosearch, LLC. Immediately prior to these amendments, we sold our oil and
gas  leases  in  Fort  Bend County, Texas and these were removed from the Credit
Facility.  The  remaining  existing  collateral  remains  unaffected  by  the
amendments.  As amended, the collateral for the Credit Facility further includes
a  first and prior lien on new oil and gas leases acquired with Fortuna's funds,
as  well  as  the equipment on any well drilled with Fortuna's funds. The Credit
Facility  will  be  further secured by a pledge of our limited liability company
membership  interests  in  any  existing  or  newly  created subsidiary which is
utilized  to  hold  oil  and  gas leases acquired with Fortuna's funds. Advances
under  the  Credit  Facility  shall be made available only if at the time of our
request  (1)  our  Proved  Developed  Reserves  at  all  times  equal  or exceed
twenty-five percent (25%) of the outstanding principal and interest indebtedness
and,  (2)  only  if the principal balance under the note following the requested
advance  is  less  than  the  sum  of (i) actual costs of the oil and gas leases
funded  through  the date of the requested draw with Fortuna funds, and (ii) the
sum  of  75%  of our Proved Developed Reserves and 50% of our Proved Undeveloped
Reserves  from  all  properties  as  reflected in the most recent reserve report
prepared  by  an  independent  petroleum engineer with qualifications to provide
such  a report compliant with SEC standards. The terms Proved Developed Reserves
and  Proved  Undeveloped  Reserves are defined in Rule 4-10, Regulation S-X. The
Credit  Facility  further  requires that we update our reserve reports every six
(6)  months  or  earlier  should  the hypothetical price of hydrocarbons used in
preparation  of  the most recent reserve report decline by 15% or more. If there
is  a  deficiency  in  these  minimum  reserve requirements, then we must pledge
additional  collateral  or  pay  down the loan. Correspondingly, we may obtain a
partial  release  of an item of collateral upon request if these minimum reserve
requirements are satisfied after the release.

Under  the  Credit Facility, Fortuna will receive an overriding royalty equal to
2%  of  our  net  revenue interest in each oil and gas lease acquired or drilled
with  the  funds derived from the Credit Facility. Fortuna also received 100,000
warrants  to  purchase  shares of our common stock at an exercise price of $2.00
per share As of March 15, 2006 the outstanding principal balance of the facility
was $3,525,000.

WE PARTICIPATE IN OIL AND GAS LEASES WITH THIRD PARTIES.

We  may own less than 100% of the working interest in certain leases acquired by
us,  and  other  parties will own the remaining portion of the working interest.
Financial  risks  are  inherent  in  any  operation  where the cost of drilling,
equipping,  completing and operating wells is shared by more than one person. We
could  be  held  liable  for the joint activity obligations of the other working
interest  owners  such  as  nonpayment of costs and liabilities arising from the
actions  of  the  working  interest  owners. In the event other working interest
owners  do  not pay their share of such costs, we would likely have to pay those
costs. In such situations, if we were unable to pay those costs, we could become
insolvent.

WE  MAY ISSUE ADDITIONAL SHARES OF COMMON STOCK IN THE FUTURE, WHICH COULD CAUSE
DILUTION TO ALL SHAREHOLDERS.

We  may  seek  to raise additional equity capital in the future. Any issuance of
additional  shares  of  our  common  stock  will dilute the percentage ownership
interest  of  all  shareholders  and  may dilute the book value per share of our
common stock.

WE DERIVE OUR REVENUES FROM A LIMITED NUMBER OF CUSTOMERS.


                                       20
<PAGE>
During  the fiscal year ending December 31, 2005, we derived all of our revenues
from  a  limited  number  of customers (purchasers of oil and gas). Our revenues
from  these  customers were comprised of the following percentages: Eighty Eight
Oil,  LLC-  51.8%;  Gulfmark  Energy,  Inc.- 32.5%; Bear Paw Energy, LLC - 4.1%;
Plains  Marketing  - 10.1%; and others 1.5%. The loss of any particular customer
could  have  a  material adverse impact on our financial condition if we are not
able to find another purchaser of comparable quantities of oil and gas.

EXPANSION OF OUR EXPLORATION PROGRAM WILL REQUIRE CAPITAL FROM OUTSIDE SOURCES.

We do not currently have the financial resources to explore and drill all of our
currently  identified  prospects.  Absent raising additional capital or entering
into  joint  venture agreements, we will not be able to increase our exploration
and  drilling operations at the projected rate. This could limit the size of our
business.  There is no assurance that capital will be available in the future to
us  or that capital will be available under terms acceptable to us. We will need
to  raise  additional money, either through the sale of equity securities (which
could dilute the existing stockholders' interest), through the entering of joint
venture  agreements  (which, while limiting our risk, could reduce our ownership
interest  in  particular  assets),  or from borrowings from third parties (which
could  result  in  additional assets being pledged as collateral and which would
increase our debt service requirements).

Additional capital could be obtained from a combination of funding sources, many
of  which  could  have  a  material  adverse  effect on our business, results of
operations  and  financial  condition.  These potential funding sources, and the
potential adverse effects attributable thereto, include:

     -    cash flow from operating activities, which is sensitive to prices we
          receive for oil and natural gas and the success of current and future
          operations;

     -    borrowings from financial institutions, which may subject us to
          certain restrictive covenants, including covenants restricting our
          ability to raise additional capital or pay dividends;

     -    debt offerings, which would increase our leverage and add to our need
          for cash to service such debt (which could result in additional assets
          being pledged as collateral and which could increase our debt service
          requirements);

     -    additional offerings of equity securities, which would cause dilution
          of our common stock;

     -    sales of prospects generated by the exploration program, which would
          reduce future revenues from that program;

     -    additional sales of interests in our projects, which could reduce
          future revenues; and

     -    arrangement of a business development loan from, or prepayment of
          terminal use fees by, prospective sellers or purchasers of oil and
          gas.

Our ability to raise additional capital will depend on the results of operations
and  the  status  of  various  capital  and  industry  markets  at the time such
additional  capital  is sought. Accordingly, capital may not become available to
us  from  any  particular  source  or at all. Even if additional capital becomes
available, it may not be on terms acceptable to us. Failure to obtain additional
financing  on  acceptable  terms  may  have  a  material  adverse  effect on our
business, results of operations and financial condition.

WE DEPEND ON INDUSTRY VENDORS AND MAY NOT BE ABLE TO OBTAIN ADEQUATE SERVICES.

We  are  and  will  continue to be largely dependent on industry vendors for the
success  of  our  oil  and  gas  exploration projects. These contracted services
include, but are not limited to, accounting, drilling,


                                       21
<PAGE>
completion,  workovers  (remedial  down  hole  work  on  a  well)  and reentries
(entering  an  existing well and changing the direction and/or depth of a well),
geological  evaluations,  engineering,  leasehold  acquisitoin  (landmen),
operations, legal, investor relations/public relations, and prospect generation.
We could be harmed if we fail to attract quality industry vendors to participate
in the drilling of prospects which we identify or if our industry vendors do not
perform satisfactorily. We often have, and will continue to have, little control
over factors that would influence the performance of our vendors.

WE RELY ON THIRD PARTIES FOR PRODUCTION SERVICES AND PROCESSING FACILITIES.

The  marketability  of our production depends upon the proximity of our reserves
to,  and the capacity of, facilities and third party services, including oil and
natural  gas  gathering systems, pipelines, trucking or terminal facilities, and
processing  facilities.  The unavailability or lack of capacity of such services
and  facilities  could  result in the shut-in of producing wells or the delay or
discontinuance  of  development  plans  for  properties.  A  shut-in or delay or
discontinuance  could  materially  adversely  affect our financial condition. In
addition,  federal  and  state  regulation of oil and natural gas production and
transportation affect our ability to produce and market oil and natural gas on a
profitable basis.

WE MAY NOT OPERATE ALL PROJECTS.

We  may not operate all properties in which we have an interest; as a result, we
may  have  limited  ability  to  exercise  influence over, and control the risks
associated  with, operations of these properties. The failure of a well operator
to  adequately  perform  operations,  an  operator's  breach  of  the applicable
agreements or an operator's failure to act in ways that are in our best interest
could  reduce  our  production  and  revenues.  The  success  and  timing of our
development  activities on properties operated by others therefore depend upon a
number of factors outside of our control, including the operator's:

     -    timing and amount of capital expenditures;

     -    expertise and financial resources;

     -    inclusion of other participants in drilling wells; and

     -    use of technology.

OUR  DIRECTORS  AND  OFFICERS  HAVE  LIMITED  LIABILITY  AND  HAVE  RIGHTS  TO
INDEMNIFICATION.

Our  Articles  of  Incorporation  and  Bylaws provide, as permitted by governing
Nevada law, that our Directors and officers shall not be personally liable to us
or  any of our stockholders for monetary damages for breach of fiduciary duty as
a  Director  or  officer,  with certain exceptions. The Articles further provide
that  we  will  indemnify  our  Directors  and  officers  against  expenses  and
liabilities  they  incur  to  defend, settle, or satisfy any civil litigation or
criminal  action  brought  against them on account of their being or having been
its  Directors  or  officers  unless,  in such action, they are adjudged to have
acted with gross negligence or willful misconduct.

The  inclusion  of  these  provisions  in  the  Articles  may have the effect of
reducing the likelihood of derivative litigation against Directors and officers,
and  may  discourage or deter stockholders or management from bringing a lawsuit
against  Directors  and  officers  for breach of their duty of care, even though
such  an  action,  if  successful,  might  otherwise  have  benefited us and our
stockholders.

The  Articles provide for the indemnification of our officers and Directors, and
the  advancement  to  them  of  expenses  in connection with any proceedings and
claims,  to  the  fullest  extent  permitted by Nevada law. The Articles include
related  provisions  meant  to  facilitate  the  indemnitee's  receipt  of  such
benefits.  These  provisions cover, among other things: (i) specification of the
method  of  determining  entitlement  to  indemnification  and  the selection of
independent  counsel  that  will  in  some  cases  make such determination, (ii)
specification  of  certain  time  periods  by  which  certain  payments  or
determinations  must  be  made  and  actions  must  be  taken,  and  (iii)  the
establishment of certain presumptions in favor of an indemnitee.


                                       22
<PAGE>
Insofar  as indemnification for liabilities arising under the Securities Act may
be  permitted to our directors, officers and controlling persons pursuant to the
foregoing provisions, we have been advised that in the opinion of the Securities
and  Exchange  Commission,  such  indemnification  is  against  public policy as
expressed in the Securities Act and is therefore unenforceable.

                    GENERAL RISKS OF THE OIL AND GAS BUSINESS

INVESTMENT IN THE OIL AND GAS BUSINESS IS RISKY.

Oil  and  gas exploration and development is an inherently speculative activity.
There  is  no  certain  method  to  determine  whether or not a given lease will
produce  oil  or gas or yield oil or gas in sufficient quantities and quality to
result  in commercial production. There is always the risk that development of a
lease  may  result  in  dry  holes or in the discovery of oil or gas that is not
commercially  feasible  to produce. There is no guarantee that a producing asset
will continue to produce. Because of the high degree of risk involved, there can
be  no  assurance that we will recover any portion of our investment or that our
investment in leases will be profitable.

WE ARE SUBJECT TO DRILLING AND OPERATIONAL HAZARDS.

The oil and gas business involves a variety of operating risks, including:

          -    blowouts, cratering and explosions;

          -    mechanical and equipment problems;

          -    uncontrolled flows of oil and gas or well fluids;

          -    fires;

          -    marine hazards with respect to offshore operations;

          -    formations with abnormal pressures;

          -    pollution and other environmental risks; and

          -    natural disasters.

Any  of  these  events could result in loss of human life, significant damage to
property,  environmental pollution, impairment of our operations and substantial
losses.  Locating  pipelines  near populated areas, including residential areas,
commercial business centers and industrial sites, could increase these risks. In
accordance  with customary industry practice, we will maintain insurance against
some,  but  not  all,  of these risks and losses. The occurrence of any of these
events  not  fully  covered by insurance could have a material adverse effect on
our financial position and results of operations.

WE HAVE COMPETITION FROM OTHER COMPANIES.

A  large number of companies and individuals engage in drilling for gas and oil,
and  there  is  competition  for the most desirable prospects. We will encounter
intense  competition  from other companies and other entities in the sale of our
gas  and  oil  production.  We  could  be  competing  with  numerous gas and oil
companies  which  may  have financial resources significantly greater than ours.
Further,  the quantities of gas and oil to be delivered by us may be affected by
factors beyond our control, such as the inability of the wells to deliver at the
necessary  quality  and  pressure,  premature exhaustion of reserves, changes in
governmental regulations affecting allowable production and priority allocations
and price limitations imposed by federal and state regulatory agencies.


                                       23
<PAGE>
WE MAY BE UNABLE TO ACQUIRE OIL AND GAS LEASES.

To  engage  in  oil and gas exploration, we must first acquire rights to conduct
exploration  and  recovery  activities  on  identified  prospects. We may not be
successful  in  acquiring  "farm-outs"  (agreements  whereby  the owner of lease
interests grants to a third party the right to earn an assignment of an interest
in  the lease, typically by drilling one or more wells), permits, lease options,
leases  or  other  rights  to  explore  for  or  recover  oil  and gas. The U.S.
Department  of  the  Interior  and  the  states in which we and our subsidiaries
conduct  operations  award  oil  and  gas leases on a competitive bidding basis.
Non-governmental owners of the onshore mineral interests within the area covered
by our exploration program are not obligated to lease their mineral rights to us
except  where  we  have already obtained lease options. In addition, other major
and  independent  oil  and  gas companies with financial resources significantly
greater  than ours may bid against us for the purchase of oil and gas leases. If
we  or  our  subsidiaries  are  unsuccessful in acquiring these leases, permits,
options and other interests, our prospect inventory for exploration and drilling
could  be  significantly  reduced,  and  our business, results of operations and
financial condition could be substantially harmed.

THE UNAVAILABILITY OR HIGH COST OF DRILLING RIGS, EQUIPMENT, SUPPLIES, PERSONNEL
AND OILFIELD SERVICES COULD MATERIALLY ADVERSELY IMPACT US.

Drilling  activity  in  the area of our proposed initial activities is extremely
high. Increased drilling activity in these areas could decrease the availability
of  rigs  and  our access to oilfield services. Either shortages or increases in
the  cost  of  drilling  rigs,  equipment,  supplies or personnel could delay or
adversely  affect our operations. There can be no assurance that we will be able
to  obtain  the  necessary  equipment  or services may not be available to us at
economical prices.

OIL AND GAS PRICES ARE VOLATILE.

Our  revenues,  cash flow, operating results, financial condition and ability to
borrow  funds  or  obtain  additional capital depend substantially on the prices
that  we  receive for oil and gas production. Declines in oil and gas prices may
materially  adversely  affect  our  financial  condition,  liquidity, ability to
obtain financing and operating results. Lower oil and gas prices also may reduce
the  amount  of  oil  and gas that we can produce economically. High oil and gas
prices  could preclude acceptance of our business model. Depressed prices in the
future would have a negative effect on our future financial results.

Historically,  oil  and  gas  prices and markets have been volatile, with prices
fluctuating  widely,  and they are likely to continue to be volatile. Prices for
oil  and  gas  are  subject to wide fluctuations in response to relatively minor
changes  in supply of and demand, market uncertainty and a variety of additional
factors that are beyond our control. These factors include:

          -    the domestic and foreign supply of oil;

          -    the level of consumer product demand;

          -    weather conditions;

          -    political conditions in oil producing regions, including the
               Middle East;

          -    the ability of the members of the Organization of Petroleum
               Exporting Countries to agree to and maintain oil price and
               production controls;

          -    the price of foreign imports;

          -    actions of governmental authorities;

          -    domestic and foreign governmental regulations;


                                       24
<PAGE>
          -    the price, availability and acceptance of alternative fuels; and

          -    overall economic conditions.

These  factors  and the volatile nature of the energy markets make it impossible
to  predict  with  any  certainty  future  oil  and gas prices. Our inability to
respond  appropriately to changes in these factors could negatively affect their
profitability.

WE MAY HAVE WRITEDOWNS OF OUR ASSETS DUE TO PRICE VOLATILITY.

SEC  accounting rules require us to review the carrying value of our oil and gas
properties  on  a  quarterly  basis for possible write-down or impairment. Under
these  rules,  capitalized  costs  of  proved  reserves may not exceed a ceiling
calculated  at  the  present  value  of estimated future net revenues from those
proved  reserves.  Capital  costs  in  excess of the ceiling must be permanently
written  down.  A decline in oil and natural gas prices could cause a write down
which would negatively affect our net income.

ESTIMATES  OF OIL AND GAS RESERVES ARE UNCERTAIN AND MAY VARY SUBSTANTIALLY FROM
ACTUAL PRODUCTION.

There  are  numerous  uncertainties  inherent in estimating quantities of proved
reserves  and  in  projecting  future  rates  of  production  and  timing  of
expenditures,  including  many  factors  beyond  our  control.  Our  oil and gas
reserves set forth in this Form 10-KSB represent the estimated quantities of oil
and  gas  based on reports prepared by third party reserve engineers. There is a
reasonable  certainty  of  recovering  the proved reserves as disclosed in those
reports.  Information  relating to our proved oil and gas reserves is based upon
engineering  data  which  demonstrates,  with  reasonable  certainty,  to  be
recoverable  in  future  years from known reservoirs under existing economic and
operating  conditions. Reserve engineering is a subjective process of estimating
underground  accumulations  of oil and natural gas that cannot be measured in an
exact  manner. The accuracy of any reserve estimate is a function of the quality
of  available  geological,  geophysical,  engineering  and  economic  data,  the
precision  of  the engineering and judgment. As a result, estimates of different
engineers  often  vary. The estimates of reserves, future cash flows and present
value  are  based  on various assumptions, including those prescribed by the SEC
relating to oil and natural gas prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds, and are inherently imprecise.

You  should  not assume that the present values referred to herein represent the
current  market  value  of  our  estimated  oil  and  natural  gas  reserves. In
accordance  with  requirements  of  the SEC, the estimates of present values are
based  on prices and costs as of the date of the estimates. Actual future prices
and  costs may be materially higher or lower than the prices and costs as of the
date of the estimate.

Quantities  of  proved  reserves  are  estimated  based  on economic conditions,
including oil and natural gas prices in existence at the date of assessment. Our
reserves and future cash flows may be subject to revisions based upon changes in
economic  conditions,  including  oil  and natural gas prices, as well as due to
production  results,  results  of  future development, operating and development
costs  and  other  factors.  Downward  revisions  of  our reserves could have an
adverse affect on our financial condition, operating results and cash flows.

WE ARE SUBJECT TO GOVERNMENTAL REGULATIONS.

Gas  and oil operations in the United States are subject to extensive government
regulation  and  to  interruption  or termination by governmental authorities on
account  of  ecological  and  other considerations. The Environmental Protection
Agency  of  the United States and the various state departments of environmental
affairs  closely  regulate  gas  and  oil  production  effects on air, water and
surface  resources. Furthermore, proposals concerning regulation and taxation of
the  gas  and  oil  industry are constantly before Congress. It is impossible to
predict  future  proposals  that  might  be enacted into law and the effect they
might  have  on  us.  Thus,  restrictions  on  gas  and  oil activities, such as
production  restrictions,  price  controls,  tax  increases  and  pollution  and
environmental controls may have a material adverse effect on us.


                                       25
<PAGE>
THE  OIL  AND  GAS  INDUSTRY  IS  SUBJECT  TO  HAZARDS  RELATED TO POLLUTION AND
ENVIRONMENTAL ISSUES.

Hazards  in the drilling and/or the operation of gas and oil properties, such as
accidental  leakage  or  spillage,  are  sometimes encountered. Such hazards may
cause  substantial  liabilities  to  third parties or governmental entities, the
payment of which could reduce distributions or result in the loss of our leases.
Although  it  is  anticipated  that  insurance  will  be obtained by third-party
operators  for  our  benefit,  we  may be subject to liability for pollution and
other damages due to environmental events which cannot be insured against due to
prohibitive  premium  costs,  or  for  other  reasons.  Environmental regulatory
matters  also could increase substantially the cost of doing business, may cause
delays  in  producing  oil  and gas or require the modification of operations in
certain areas.

Our  operations  are  subject  to  numerous  stringent  and  complex  laws  and
regulations  at  the  federal, state and local levels governing the discharge of
materials  into  the  environment  or  otherwise  relating  to  environmental
protection.  Failure to comply with these laws and regulations may result in the
assessment  of  administrative,  civil and criminal penalties, the imposition of
remedial  requirements,  and  the  imposition  of  injunctions  to  force future
compliance.

The  Oil Pollution Act of 1990 and its implementing regulations impose a variety
of  requirements  related  to  the  prevention  of oil spills, and liability for
damages  resulting  from  such  spills  in  United States waters. OPA 90 imposes
strict  joint and several liability on responsible parties for oil removal costs
and a variety of public and private damages, including natural resource damages.
While  liability  limits  apply  in  some  circumstances,  a  party  cannot take
advantage  of  liability  limits  if the spill was caused by gross negligence or
willful  misconduct or resulted from violation of a federal safety, construction
or  operation  regulation.  If  a  party fails to report a spill or to cooperate
fully  in a cleanup, liability limits likewise do not apply. Even if applicable,
the  liability  limits  for offshore facilities require the responsible party to
pay  all  removal  costs,  plus  up to $75 million in other damages. For onshore
facilities,  the  total  liability limit is $350 million. OPA 90 also requires a
responsible  party  at  an  offshore  facility  to submit proof of its financial
ability  to  cover  environmental  cleanup  and  restoration costs that could be
incurred in connection with an oil spill.

The  Comprehensive Environmental Response, Compensation, and Liability Act, also
known  as the "Superfund" law, and analogous state laws impose strict, joint and
several  liability  on  certain  classes  of persons that are considered to have
contributed  to  the  release  of  a "hazardous substance" into the environment.
These  parties  include  the  owner  or  operator  of the site where the release
occurred,  and  those  that  disposed  or arranged for the disposal of hazardous
substances found at the site. Responsible parties under CERCLA may be subject to
joint  and  several liability for remediation costs at the site, and may also be
liable  for  natural  resource  damages.  Additionally,  it  is not uncommon for
neighboring  landowners and other third parties to file tort claims for personal
injury  and  property  damage  allegedly caused by hazardous substances released
into the environment.

State statutes and regulations require permits for drilling operations, drilling
bonds  and reports concerning operations. In addition, there are state statutes,
rules  and regulations governing conservation matters, including the unitization
or  pooling  of  oil  and  gas  properties,  establishment  of  maximum rates of
production  from  oil and gas wells and the spacing, plugging and abandonment of
such  wells.  Such  statutes and regulations may limit the rate at which oil and
gas  could otherwise be produced from our properties and may restrict the number
of wells that may be drilled on a particular lease or in a particular field.

WE MAY EXPERIENCE RAPID INCREASES IN OUR OPERATING COSTS.

The  gas  and  oil  industry  historically has experienced periods of rapid cost
increases  from  time  to  time.  Increases  in  the  cost  of  exploration  and
development  would  affect  our  ability  to  acquire  equipment  and  supplies.
Increased  drilling  activity  could lead to shortages of equipment and material
which  would  make timely drilling and completion of wells impossible. The costs
of  producing oil and gas and conducting field operations may also be subject to
rapid  cost changes that are not in our control. There is no assurance that over
the  life  of  any  project there will not be fluctuating or increasing costs in
doing business.


                                       26
<PAGE>
TERRORIST  ATTACKS  AND  CONTINUED  HOSTILITIES  IN  THE  MIDDLE  EAST  OR OTHER
SUSTAINED MILITARY CAMPAIGNS MAY ADVERSELY IMPACT THE INDUSTRY AND US.

The  terrorist  attacks  that  took  place in the United States on September 11,
2001,  were  unprecedented  events that have created many economic and political
uncertainties,  some  of which may materially adversely impact us. The long-term
impact  that  terrorist  attacks and the threat of terrorist attacks may have on
the  oil  and  gas  business  is not known at this time. Uncertainty surrounding
continued  hostilities  in the Middle East or other sustained military campaigns
may  adversely  impact  us  in  unpredictable  ways.

CRITICAL ACCOUNTING POLICIES

Our discussion and analysis of our financial condition and results of operations
are based upon financial statements, which have been prepared in accordance with
accounting  principles  generally  accepted  in  the United States, or GAAP. The
preparation  of  these  financial  statements  requires us to make estimates and
judgments  that affect the reported amounts of assets, liabilities, revenues and
expenses.  We  analyze  our  estimates,  including  those related to oil and gas
properties,  income  taxes,  commitments  and  contingencies  and  stock  based
compensation,  and base our estimates on historical experience and various other
assumptions  that  we  believe  to be reasonable under the circumstances. Actual
results  may  differ  from  these  estimates.  We believe the following critical
accounting  policies  are subject to significant judgments and estimates used in
the preparation of our financial statements:

Oil  and Gas properties. The Company uses the full cost method of accounting for
oil  and  gas  operations. Accordingly, all costs, including nonproductive costs
and  certain  overhead  costs  associated  with  acquisition,  exploration  and
development  of  oil  and gas properties, are capitalized. Net capitalized costs
are  limited  to  the future net revenues, after income taxes, discounted at 10%
per  year,  from proven oil and gas reserves plus the cost of the properties not
subject  to amortization. Such capitalized costs, including the estimated future
development  costs  and remediation costs, if any, are depleted by an equivalent
units-of-production method, converting gas units (MCF) to oil units (barrels) at
the  ratio  of  six  MCF  of  gas  to  one  barrel  of oil. Also, with full cost
accounting,  no  gain  or  loss  is  recognized upon the disposal of oil and gas
properties,  unless  such  dispositions  significantly  alter  the  relationship
between  capitalized  costs  and  proven  oil  and  gas  reserves.  Oil  and gas
properties  not  subject  to  amortization  consist  of  the cost of undeveloped
leaseholds and other geological and exploration costs, and totaled $3,513,597 at
December  31,  2005.  These  costs  are  reviewed periodically by management for
impairment,  with  the  impairment provision included in the cost of the oil and
gas  properties subject to amortization. Factors considered by management in its
impairment  assessment  include  drilling results, re-evaluations of properties,
terms  of  oil  and  gas  leases  not held by production and available funds for
exploration and development.

Income  taxes. The Company uses the asset and liability method of accounting for
income taxes, under which deferred tax assets and liabilities are recognized for
the  future  tax consequences of (1) temporary differences between the financial
statement carrying amounts and the tax bases of existing assets and liabilities,
and  (2) operating loss and tax credit carryforwards. Deferred income tax assets
and  liabilities  are based on enacted tax rates applicable to the future period
when  those  temporary  differences are expected to be recovered or settled. The
effect  of  a  change  in  tax  rates  on deferred tax assets and liabilities is
recognized  in income during the period the rate change is enacted. Deferred tax
assets  are  recognized  in  the year in which realization becomes determinable.
Periodically,  management performs a forecast of its taxable income to determine
whether it is more likely than not that a valuation allowance is needed, looking
at  both  positive  and negative factors. A valuation allowance for our deferred
tax  assets  is  established, if in management's opinion, it is more likely than
not,  that  some portion will not be realized. At December 31, 2005, a valuation
allowance of $1,628,636 has been provided for deferred tax assets.

Commitments  and  contingencies. Liabilities for loss contingencies arising from
claims,  assessments,  litigation  or  other  sources  are  recorded  when it is
probable  that  a  liability  has been incurred and the amount can be reasonably
estimated.  Management  does  not  see  any circumstances that would require the
Company


                                       27
<PAGE>
to record a loss contingency; therefore, to date no commitments or contingencies
have been recorded.

Stock  Based  Compensation  Through  December  31,  2005  we  have accounted for
stock-based  awards  to employees in accordance with Accounting Principles Board
Opinion ("APB") No. 25, Accounting for Stock Issued to Employees". Under APB 25,
compensation expense is only recorded for employees if the exercise price of the
Company's  stock option is less than the market value of the underlying stock on
the  date  of  grant.  Therefore,  through  December  31,  2005, the Company has
followed  a  policy  to  only grant to employees, stock options with an exercise
price  greater  than the market value of the underlying stock. We have accounted
for  stock-based  awards  to  non-employees  in accordance with the Statement of
Financial  Accounting  Standards  ("SFAS")  No. 123, "Accounting for Stock-Based
Compensation".  SFAS  No. 123 requires that compensation expense be recorded for
stock  options  awarded to non-employees valued at the fair value on the date of
the  award.  Management  estimates the fair value of the stock options using the
Black-Scholes  option-pricing  model  and  in  the calculation, makes subjective
assumptions  for  the  applicable  interest rates, stock volatility and dividend
yield.  In  all  cases,  the calculated compensation is recognized as an expense
over  the  period  that the employee performs the related services. Compensation
expense of $-0- was recorded in the year ending December 31, 2005.

In  December  2004,  the  FASB  issued SFAS No. 123 (revised 2004), "Share-Based
Payment",  that  will  require, starting in fiscal year 2006, compensation costs
related  to  share-based  payment  transactions  to  be  recognized in financial
statements.  With limited exceptions, the amount of compensation cost associated
with all stock option grants will be measured based on the grant-date fair value
of  the equity instruments. Compensation cost will be recognized over the period
that  an  employee  provides  service  in  exchange  for the award. The standard
replaces SFAS No. 123, "Accounting for Stock-Based Compensation", and supersedes
APB  Opinion No. 25, "Accounting for Stock Issued to Employees". It is effective
for  small  business  issuers  for  the first interim or annual reporting period
beginning  after  December  15,  2005,  meaning  that the Company will apply the
guidance  to  all  employee  awards  of share-based payment granted, modified or
settled in the first quarter of 2006.

ITEM  7.     FINANCIAL STATEMENTS

The  information required by this Item 7 is included in this report beginning on
page F-1

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

There  have  been  no changes in or disagreements with accountants on accounting
and financial disclosure.

ITEM  8A.     CONTROLS AND PROCEDURES

Richard  D.  Dole,  our Chief Executive Officer, and David J. Collins, our Chief
Financial  Officer,  have  concluded that our disclosure controls and procedures
are appropriate and effective. They have evaluated these controls and procedures
as  of  December  31,  2005.  There  were no significant changes in our internal
controls  or  in  other  factors  that could significantly affect these controls
subsequent  to  the  date  of their evaluation, including any corrective actions
with regard to significant deficiencies and material weaknesses.

ITEM  8B.     OTHER INFORMATION

None


                                       28
<PAGE>
                                    PART III

ITEM  9.     DIRECTORS,  EXECUTIVE  OFFICERS,  PROMOTERS  AND  CONTROL  PERSONS;
             COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT

DIRECTORS AND EXECUTIVE OFFICERS

The  following  table  sets  forth  our  Directors  and executive officers as of
December  31,  2005.

<TABLE>
<CAPTION>
     -----------------------------------------------------------
           NAME       AGE                POSITION
           ----       ---                --------
     -----------------------------------------------------------
<S>                   <C>  <C>
     -----------------------------------------------------------
     Richard D. Dole   60  Director, Chairman, President and CEO
     -----------------------------------------------------------
     Wayne Beninger.   52  Chief Operating Officer
     -----------------------------------------------------------
     David Collins     37  Chief Financial Officer
     -----------------------------------------------------------
     Eric D. Brown     41  Vice President of Finance
     -----------------------------------------------------------
     Gerald Agranoff   59  Director
     -----------------------------------------------------------
     Richard Majeres   39  Director
     -----------------------------------------------------------
</TABLE>

RICHARD D. DOLE, DIRECTOR, CHAIRMAN OF THE BOARD, PRESIDENT AND CEO
Mr.  Dole  joined  us  as  a Director in July 2004, and assumed the positions of
Chairman, President and CEO in December 2004. Mr. Dole previously served as Vice
President  and  Chief  Financial  Officer for Burlington Resources International
from  1998  to  2000.  Since  that  time  he  has  been active in consulting and
financial  services.  He  was  a co-founder of Benefits Access Solutions, LLC, a
company  formed  to  provide financial services and benefit options to employees
and  members  of  corporate  organizations.  He was also co-founder and managing
partner  of Innovation Growth Partners, LLC, a firm that provided management and
consulting  services  to  early  stage  companies. Mr. Dole's extensive industry
experience  includes  being  National  Partner-in-Charge  of  Business  Process
Solutions  at  KPMG.  Prior  to  that  he  was  with  Coopers  &  Lybrand  (now
PriceWaterhouse  Coopers)  where  he  served  as Assurance and Business Advisory
Partner for nearly 20 years and also served in numerous senior management roles,
including  National  Chairman  for  the  Energy  and  Natural Resources Industry
practices  for  over  15  years  and  as  the Vice Chairman for the U.S. Process
Management  business  unit.  From  August 2003 to July 2004, Mr. Dole was also a
member  of the Board of Directors of Westport Resources Corporation (NYSE: WRC),
a  member of its audit committee and a designated financial expert. He currently
serves as a director of Double Eagle Petroleum Company (DBLE, NASDAQ, small cap)
and  chairs the audit committee and is the designated financial expert. Mr. Dole
graduated from Colorado State University.

WAYNE BENINGER, CHIEF OPERATING OFFICER
Mr.  Beninger  joined  us  as  Chief Operating Officer in May 2005. Prior to May
2005,  Mr.  Beninger served as President of Southwest Oil & Gas Management, Inc.
("SOGMI")  which  he  founded in 1997 to provide oil and gas property evaluation
services,  geologic  prospect  review,  contract  operating  services, technical
support  for  initial  public  offerings  and  strategic  planning solutions for
domestic  and  international projects. Prior to Mr Beninger joining the Company,
SOGMI  provided  a significant amount of our engineering and geological services
for  all  projects.  From  1995 to 1997, Mr. Beninger was the Vice President for
Strategic  Planning  with WRT Energy Corporation. From 1982 to 1995 he was first
employed  by,  and  then  was  a  partner  in,  The Scotia Group, a domestic and
international  consulting  firm  where  he  provided  petroleum  engineering and
geological  services  for  companies  and  projects  in  the  majority of active
petroleum  basins  in  both the U.S. and overseas. He has been active in the oil
and  gas  industry  since 1976. Mr. Beninger holds undergraduate degrees in both
petroleum engineering and geology from the University of Southern California and
has  a  number  of  industry  publications  to his credit. He is a member of the
Society of Petroleum Engineers, Pi


                                       29
<PAGE>
Epsilon  Tau (petroleum engineering honorary fraternity) and Sigma Gamma Epsilon
(geologic honorary fraternity).

DAVID COLLINS, VICE PRESIDENT, CHIEF FINANCIAL OFFICER
Mr.  Collins  joined  Petrosearch  Corporation as a Vice President and the Chief
Financial  Officer  in  October 2003. Previously, he served as the Controller of
Kazi  Management  VI,  LLC, a diversified investment and management organization
actively  involved  in energy, retail food chains, aquaculture and biotechnology
from  February  2002  to October 2003. At Kazi Management VI, he was responsible
for  the  financial  operations of multiple accounting offices across the United
States,  as  well  as fourteen international and domestic Companies. Mr. Collins
was  also  the  Chief  Financial  Officer  of  ZK  Petroleum, an independent oil
producer  in  South  Texas.  Prior  to  Kazi  Management  VI,  he  served  as an
independent  analyst  for  The March Group in St. Thomas, U.S.V.I. from February
2001  to  January  2002.  Mr.  Collins  previously  held  the  position of Chief
Financial Officer of Federation Logistics, LLC in the New York metropolitan area
from  November  1994  to  January  2001.  Mr.  Collins  graduated from Villanova
University  in  1990  with  a  Bachelor's  degree  in  Accountancy.  He became a
Certified  Public  Accountant  and  began  his  career in the Financial Services
Division  of  Ernst and Young in New York City. At Ernst and Young, he performed
audits of Fortune 500 Companies.

ERIC D. BROWN, VICE PRESIDENT OF FINANCE
Mr.  Brown  joined us in March 2004 as a consultant and became Vice President of
Finance on January 1, 2005. Previously, he served as vice president and national
sales  manager  of  GE  Capital Public Finance Inc., a subsidiary of the General
Electric  Company. While at General Electric, beginning in March 1997, Mr. Brown
was  responsible  for  strategic  direction, creation of new financing vehicles,
deal  structuring, implementation and management of the corporate finance arm of
GE  Capital  Public  Finance.  Before  joining  General  Electric,  he served as
Managing  Director of the Massachusetts Industrial Finance Agency and previously
worked  for various financial institutions in New York City doing structured and
corporate  finance. Mr. Brown holds degrees in Economics and French from Bowdoin
College  in  Brunswick, Maine. Subsequent to the year end Mr. Brown tendered his
resignation effective April 1, 2006, to pursue other activities.

GERALD N. AGRANOFF, DIRECTOR
Gerald  N.  Agranoff  joined us as a Director in May 2004. Mr. Agranoff has been
counsel  to the firm of Kupferman & Kupferman, L.L.P. in New York since 2004 and
has  been  a  general  partner of SES Family Investment and Trading Partnership,
L.P.,  an  investment partnership since 2004. Mr Agranoff has also been a member
of  Inveraray  Capital  Management  L.L.C., the investment manager of Highlander
Fund  B.V.  and  Highlander Partners (USA) L.P since 2002. He is also a director
and  the  chair of the audit committee of Triple Crown Media Inc (symbol, TCMI).
Active  in  Wall  Street  financial  transactions  for  over  two  decades,  his
specialties  include  taxation,  investments  and  corporate  finance. From 1975
through  1981,  Mr.  Agranoff was engaged exclusively in the private practice of
law in New York and was an adjunct-instructor at New York University's Institute
of Federal Taxation. Previously, he served as attorney-advisor to a Judge of the
United  States  Tax  Court.  He holds an L.L.M. degree in Taxation from New York
University and J.D. and B.S. Degrees from Wayne State University.

RICHARD MAJERES, DIRECTOR
Richard  Majeres  joined  us  as  a  Director in May 2004. In December 2000, Mr.
Majeres  was  one of the founding partners of the Houston public accounting firm
Ubernosky  &  Majeres,  PC,  which  currently  operates as Ubernosky, Passmore &
Majeres,  LLP,  offering  tax,  audit,  accounting  and  management  consulting
services.  Mr.  Majeres has served as a partner of this firm since its inception
in  December 2000. From January 1999 to November 2000, Mr. Majeres was a partner
at Cox & Lord, PC. Mr. Majeres graduated from Bemidji State University, Bemidji,
Minnesota  in  1989  with a bachelor's degree in accounting. Upon graduation, he
served  as  a field auditor with the Federal Energy Regulatory Commission of the
Department  of Energy. Mr. Majeres became a certified public accountant in 1992.
He has extensive experience with oil and gas entities, including exploration and
development  partnerships  and  corporations and currently focuses a majority of
his efforts on the Firm's audit practice.


                                       30
<PAGE>
COMMITTEES OF THE BOARD OF DIRECTORS

We  held  two  in  person and four telephonic meetings of the Board of Directors
during  the fiscal year ended December 31, 2005, and the Board of Directors took
action at Board meetings or by unanimous written consent eight times during that
period.  Mr. Dole is our only Director who is also an Officer. We currently have
an  audit  committee  of  the  Board of Directors made up of Richard Majeres and
Gerald Agranoff. The Board of Directors is in the process of evaluating the need
for other appropriate committees for our future growth.

We  do  not currently have a process for security holders to send communications
to  the  Board of Directors. However, we welcome comments and questions from our
shareholders.  Shareholders  can  direct  communications  to our Chief Executive
Officer, Richard D. Dole, at our executive offices, 675 Bering Drive, Suite 200,
Houston, Texas 77057. While we appreciate all comments from shareholders, we may
not be able to individually respond to all communications. We attempt to address
shareholder  questions  and  concerns  in our press releases and documents filed
with the SEC so that all shareholders have access to information about us at the
same  time.  Mr.  Dole collects and evaluates all shareholder communications. If
the  communication  is  directed  to  the  Board  of Directors generally or to a
specific  director,  Mr.  Dole  will  disseminate  the  communications  to  the
appropriate  party  at  the  next  scheduled  Board of Directors meeting. If the
communication  requires  a  more  urgent  response,  Mr.  Dole  will direct that
communication to the appropriate executive officer. All communications addressed
to our directors and executive officers will be reviewed by those parties unless
the communication is clearly frivolous.

Our  Bylaws  provide  that  nominations  of persons for election to the Board of
Directors  of  the corporation may be made at a meeting of stockholders by or at
the direction of the Board of Directors or by any stockholder of the corporation
entitled  to  vote in the election of directors at the meeting who complies with
the following notice procedures, as set forth in the Bylaws:

     Nominations  of  persons for election to the Board of Directors may be made
     at  a  meeting of the shareholders at which directors are to be elected (a)
     by or at the direction of the Board of Directors, or (b) by any shareholder
     of  the Company who is a shareholder of record at the time of the giving of
     such shareholders notice provided for in Paragraph 3.3 (of the Bylaws), who
     shall  be entitled to vote at such meeting in the election of directors and
     who  complies  with the requirements of Paragraph 3.3 (of the Bylaws). Such
     nominations,  other  than those made by or at the direction of the Board of
     Directors  shall  be  preceded  by  timely advance notice in writing to the
     Secretary.  To  be timely, a shareholder's notice shall be delivered to, or
     mailed  and received at, the principal executive offices of the Company (1)
     with  respect  to  an  election  to  be  held  at the annual meeting of the
     shareholders  of  the  Company, not later than the close of business on the
     90th  day  prior  to  the  first anniversary of the preceding year's annual
     meeting;  provided,  however,  in  the  event  that  the date of the annual
     meeting  is  more  than  30  days  before  or  more than 60 days after such
     anniversary  date,  notice  by  the  shareholder  to  be  timely must be so
     delivered not later than the close of business on the later of the 90th day
     prior  to  such  annual  meeting or the 10th day following the day on which
     public  announcement  of  the  date  of  such  meeting is first made by the
     Company;  and  (2)  with  respect  to  an  election to be held at a special
     meeting  of  shareholders  of the Company for the election of directors not
     later than the close of business on the 10th day following the day on which
     notice of the date of the special meeting was mailed to shareholders of the
     Company  as  provided in Paragraph 2.4 (of the Bylaws) or public disclosure
     of  the  date  of the special meeting was made, whichever first occurs. Any
     such  shareholder's  notice to the Secretary shall set forth (x) as to each
     person  whom  the  shareholder  proposes  to  nominate  for  election  or
     re-election  as  a  director,  (i)  the  name,  age,  business  address and
     residence  address  of  such  person;  (ii)  the  principal  occupation  or
     employment  of  such  person;  (iii)  the number of shares of each class of
     capital  stock of the Company's beneficially owned by such person; (iv) the
     written  consent  of  such  person  to  having such person's name placed in
     nomination  at  the  meeting and to serve as a director if elected; (v) any
     other  information relating to such person that is required to be disclosed
     in  solicitations  of  proxies  for  election of directors, or is otherwise
     required, pursuant to Regulation 14A under the Exchange Act, and (vi) as to
     the


                                       31
<PAGE>
     shareholder  giving the notice, (i) the name and address, as they appear on
     the  Company's  books of such shareholder, and (ii) the number of shares of
     each class of voting stock of the Company which are then beneficially owned
     by  such  shareholder. The presiding officer of the meeting of shareholders
     shall  determine  whether the requirements of Paragraph 3.3 (of the Bylaws)
     have been met with respect to any nomination or intended nomination. If the
     presiding officer determines that any nomination was not made in accordance
     with the requirements of Paragraph 3.3 (of the Bylaws), he shall so declare
     at  the  meeting  and  the  defective  nomination  shall  be  disregarded.
     Notwithstanding  the foregoing provisions , a shareholder shall also comply
     with  all  applicable  requirements  of  the Exchange Act and the rules and
     regulations  thereunder  with respect to the matters set forth in Paragraph
     3.3  of  the Bylaws. For (purposes of the notice provisions of the Bylaws),
     public  disclosure  shall  be deemed to first be given to shareholders when
     disclosure  of  such date of the meeting of shareholders is first made in a
     press  release reported by the Dow Jones News Services, Associated Press or
     comparable  national  news  service, or in a document publicly filed by the
     Company  with  the  Securities and Exchange Commission pursuant to Sections
     13, 14 or 15(d) of the Exchange Act.

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

Section  16(a) of the Securities Exchange Act of 1934 requires our directors and
executive  officers,  and  persons who own beneficially more than ten percent of
our common stock, to file reports of ownership and changes of ownership with the
Securities and Exchange Commission. Based solely on the reports we have received
and  on  written representations from certain reporting persons, we believe that
the  directors,  executive  officers,  and  greater  than ten percent beneficial
owners have complied with all applicable filing requirements.

CODE OF ETHICS

Effective  August  19, 2005, the Board of Directors adopted a Code of Ethics for
our  directors,  officers  and employees. A copy of our Code of Ethics was filed
with our Form SB-2 registration statement on June 6, 2005.

ITEM  10.  EXECUTIVE COMPENSATION

The  following  table  sets  forth  certain  compensation  information  for  the
following  individuals  for the three most recently completed fiscal years ended
December  31,  2005.  No  other  compensation  was  paid  to our named executive
officers other than the compensation set forth below. The compensation reflected
in this section has been awarded by us and our predecessor, Petrosearch Texas.

<TABLE>
<CAPTION>
 ------------------------------------------------------------------------------------------------------------
                                             SUMMARY COMPENSATION TABLE

-------------------------------------------------------------------------------------------------------------
                                 ANNUAL COMPENSATION          LONG TERM COMPENSATION
-------------------------------------------------------------------------------------------------------------
                                                                      AWARDS           PAYOUTS
                                                              ---------------------------------
                                                     OTHER                  OPTIONS/
                                                     ANNUAL   RESTRICTED      SARS       LTIP     ALL OTHER
                                                     COMP-       STOCK      WARRANTS   PAYOUTS      COMP-
NAME              TITLE    YEAR   SALARY    BONUS   ENSATION    AWARDED       (#)        ($)      ENSATION
-------------------------------------------------------------------------------------------------------------
<S>             <C>        <C>   <C>       <C>      <C>       <C>          <C>         <C>       <C>
Richard         Chairman,  2005  $180,000      -0-       -0-          -0-         -0-       -0-         -0-
Dole(1)         CEO and    2004  $ 90,000      -0-       -0-          -0-   3,930,046       -0-         -0-
                President  2003       -0-      -0-       -0-          -0-      15,385       -0-         -0-
-------------------------------------------------------------------------------------------------------------


                                       32
<PAGE>
Bradley         Former     2005       -0-      -0-       -0-          -0-         -0-       -0-         -0-
Simmons (2)     Director,  2004  $180,000  $50,000       -0-          -0-         -0-       -0-  $ 110,000(3)
                CEO and    2003  $320,370      -0-       -0-          -0-     730,769       -0-         -0-
                President
-------------------------------------------------------------------------------------------------------------
Wayne           Chief      2005   135,417   25,000       -0-          -0-     365,000       -0-         -0-
Beninger (4)    Operating  2004       -0-      -0-       -0-          -0-         -0-       -0-         -0-
                Officer    2003       -0-      -0-       -0-          -0-         -0-       -0-         -0-
-------------------------------------------------------------------------------------------------------------
David Collins   Chief      2005  $180,000      -0-       -0-          -0-      50,000       -0-         -0-
(5)             Financial  2004  $165,000  $25,000       -0-  $    15,000         -0-       -0-         -0-
                Officer    2003       -0-      -0-       -0-  $    45,000     323,077       -0-         -0-
-------------------------------------------------------------------------------------------------------------
Eric Brown (6)  V.P.,      2005  $180,000      -0-       -0-          -0-     500,000       -0-         -0-
                Finance    2004  $105,000      -0-       -0-          -0-      53,846       -0-         -0-
                           2003       -0-      -0-       -0-          -0-         -0-       -0-         -0-
-------------------------------------------------------------------------------------------------------------
</TABLE>

Notes to Summary Compensation Table:

     (1)  Mr.  Dole  was  appointed  as a Director in July 2004. On December 30,
          2004,  Mr.  Dole  assumed  the  roles  of  Chairman  of  our  Board of
          Directors, President and Chief Executive Officer Mr. Dole entered into
          an  employment  agreement with the Company in November 2004 for a term
          of  2  years  which  called for compensation of $15,000 per month. Mr.
          Dole became an employee of the Company as of January 1, 2005.

     (2)  Mr.  Simmons  served  as  a  Director  and Chief Executive Officer and
          President  until  his  resignation  on  December 30, 2004. Mr. Simmons
          entered  into a consulting agreement with the Company in December 2004
          for  a  term  of  one year which calls for compensation of $15,000 per
          month.  In  September 2005 the Company and Mr. Simmons mutually agreed
          to terminate his consulting agreement.

     (3)  During  2004,  the Board of Directors approved advances to Mr. Simmons
          which  were  to be evaluated at year-end as possible compensation. The
          Board  of Directors authorized a portion of the advances as a year-end
          performance  bonus for 2004; the remaining balance of the advances was
          converted  to  a  non-interest bearing receivable to the Company as of
          December  31, 2004. The outstanding balance of the loan as of December
          31, 2005 was -0-.

     (4)  Mr.  Beninger  was appointed Chief Operating Officer in May, 2005. Mr.
          Beninger  became  an employee and entered into an employment agreement
          with the Company on May 1, 2005, for a term of 2 years which calls for
          compensation  of  $20,830  per  month  and a $50,000 annual bonus each
          year.

     (5)  Mr.  Collins was appointed Chief Financial Officer in September, 2004.
          Mr.  Collins  became an employee of the Company as of January 1, 2005.
          Mr.  Collins entered into an employment agreement with the Company May
          1, 2005, for a term of 2 years which calls for compensation of $15,000
          per month.

     (6)  Mr.  Brown  was  appointed  Vice  President of Finance on December 30,
          2004.  Mr.  Brown  became  an employee of the Company as of January 1,
          2005.  Mr. Brown entered into an employment agreement with the Company
          May  1,  2005,  for  a term of 2 years which calls for compensation of
          $15,000  per  month. Subsequent to the year end Mr. Brown tendered his
          resignation effective April 1, 2006.


DIRECTOR COMPENSATION

In  May  2004,  as  director  compensation,  Messrs.  Agranoff  and Majeres each
received  61,538  warrants  to  purchase  shares of our common stock at a strike
price  of  $6.50  per  share which will expire on May 20, 2007. Additionally, in
December 2004, Mr. Agranoff was paid $4,500 for consulting services to us.


                                       33
<PAGE>
From  January  1, 2005 until December 31, 2005, Mr. Agranoff received $4,500 per
month  for  consulting  services  provided  to  us  including  consultation,
participation and review of our restructuring, the private placement transaction
and  the  SB-2  Registration Statement. These services are no longer provided by
Mr. Agranoff.

On  March  25,  2005,  the  Board  of Directors approved compensation to each of
Gerald  Agranoff,  Richard  Majeres  and Don Henrich (our former Director) in an
amount  of  (i)  $25,000,  which  was  payable  $5,000  in  cash  and $20,000 in
restricted  stock,  and  (ii)  50,000 warrants to purchase our common stock at a
strike price of $1.95 per share.

EMPLOYMENT AGREEMENTS

The  employment  contracts  in existence with officers and key personnel include
the  above  referenced  November 15, 2004, contract with Richard Dole (Chairman,
President  and  CEO),  and employment contracts with each of David Collins (Vice
President  and Chief Financial Officer), Eric Brown (Vice President of Finance),
and Wayne Beninger, our Chief Operating Officer, each dated as of May 1, 2005.

The  employment contracts with Messrs. Dole, Collins, Brown and Beninger provide
for  an  employment term of two years. Each of the employment contracts provides
for  termination  by  the  Company  upon  death  or  disability,  with six month
severance  payments. Each of the employment contracts permits termination by the
Company for cause, which includes malfeasance, misuse of funds, insubordination,
a  material  uncured  breach  or  conviction  for  a  felony  or  crime of moral
turpitude.  The  agreements may be voluntarily terminated by the employee at any
time,  with  no  severance  payment.  Additionally, the respective employees may
elect  to  terminate  their employment contract and receive severance pay upon a
material  uncured  breach by the Company or a change in control, if within forty
five  days  of the change in control the employee is not offered a position with
the  identical  salary  for  a  period equal to the then remaining term plus one
year. For purposes of each agreement, a change in control is defined as a change
in  the majority of the Board of Director positions accompanying the acquisition
of  voting  securities  by  a third party (other than directly from the Company)
equivalent  to  forty percent of the voting control of the Company (other than a
subsidiary  or  employee  benefit  plan),  or  accompanying a sale of all of the
assets  or  a  merger  (other than involving a subsidiary). Upon termination for
cause,  the  employee  is  not  entitled to severance pay. A termination without
cause  while  a  contract  is  pending,  other  than due to a change in control,
entitles  the  employees  other than Mr. Dole to compensation through the end of
the  contract  term plus an additional three months. A termination without cause
of Mr. Dole or non-renewal of Mr. Dole's agreement gives rise to a severance pay
obligation  equal  to twelve months. Upon a termination coupled with a change in
control  where  the  particular  employee  is  not  offered  a  position for the
identical  salary,  and  in  the  case  of  Messrs.  Dole and Beninger, the same
position,  the  employee is entitled to severance compensation equal to the face
period  of  the  employment  contract then pending at termination (e.g. a 1-year
contract would give rise to twelve months severance pay).

<TABLE>
<CAPTION>
                       OPTION/SAR/WARRANT GRANTS IN LAST FISCAL YEAR
                       ---------------------------------------------

                                    (Individual Grants)
                                    -------------------

-------------------------------------------------------------------------------------------
                     Number of        Percent of Total
                     Securities        Options/SARs/
                     Underlying      Warrants Granted    Exercise of Base
     Name         Warrants/Options/    to Employees in      Price ($/Sh)     Expiration Date
                  SARS Granted (#)    Fiscal Year (%)
-------------------------------------------------------------------------------------------
<S>              <C>                 <C>                <C>                 <C>
Richard Dole                    -0-                -0-                N/A              N/A
-------------------------------------------------------------------------------------------
Wayne Beninger              365,000              36.0%  $             1.95       11/15/2008
-------------------------------------------------------------------------------------------
David Collins                50,000               4.9%  $             1.95       11/15/2008
-------------------------------------------------------------------------------------------
Eric Brown                  500,000              49.3%  $             1.95       11/15/2008
-------------------------------------------------------------------------------------------
Richard Majeres              50,000               4.9%  $             1.95       11/15/2008
-------------------------------------------------------------------------------------------
Gerald Agranoff              50,000               4.9%  $             1.95       11/15/2008
-------------------------------------------------------------------------------------------
</TABLE>


                                       34
<PAGE>
<TABLE>
<CAPTION>
                          AGGREGATED OPTION/SAR/WARRANT EXERCISES IN
                         LAST FISCAL YEAR AND FY-END OPTION/SAR VALUES
                         ---------------------------------------------

----------------------------------------------------------------------------------------------
                                                           Number of            Value of
                                                          Unexercised      Unexercised In-The-
                                                           Underlying             Money
                 Shares Acquired                         Options/SARs/        Options/SARs/
      Name       on Exercise (#)   Value Realized ($)  Warrants at FY end  Warrants at FY end
                                                              (#);                ($);
                                                          Exercisable/        Exercisable/
                                                         Unexercisable        Unexercisable
----------------------------------------------------------------------------------------------
<S>              <C>               <C>                 <C>                 <C>
Richard Dole                  -0-                 -0-       2,995,430/-0-              -0-/-0-
----------------------------------------------------------------------------------------------
Wayne Beninger                -0-                 -0-         399,616/-0-              -0-/-0-
----------------------------------------------------------------------------------------------
David Collins                 -0-                 -0-         373,077/-0-              -0-/-0-
----------------------------------------------------------------------------------------------
Eric Brown                    -0-                 -0-         553,847/-0-              -0-/-0-
----------------------------------------------------------------------------------------------
Richard Majeres               -0-                 -0-         111,538/-0-              -0-/-0-
----------------------------------------------------------------------------------------------
Gerald Agranoff               -0-                 -0-         111,538/-0-              -0-/-0-
----------------------------------------------------------------------------------------------
</TABLE>

There  were  no  stock  options, SAR's or warrants exercised by any of our named
executive officers during our most recent fiscal year ended December 31, 2005.

Other than those awards listed above, we have no long-term incentive plans.

ITEM  11.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER

The  following  table  sets  forth  certain  information  at March 15, 2006 with
respect to the beneficial ownership of shares of common stock by (i) each person
known  to  us  who  owns  beneficially more than 5% of the outstanding shares of
common  stock,  (ii) each of our Directors, (iii) each of our Executive Officers
and  (iv)  all  of  our  Executive  Officers  and  Directors  as a group. Unless
otherwise  indicated, each stockholder has sole voting and investment power with
respect  to  the shares shown. As of March 15, 2006, we had 31,057,101 shares of
common stock issued and outstanding.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------
TITLE OF CLASS      NAME AND ADDRESS OF       NUMBER OF SHARES    PERCENTAGE OF
                      BENEFICIAL OWNER         OF COMMON STOCK   COMMON STOCK (1)
---------------------------------------------------------------------------------
<S>             <C>                           <C>                <C>
Common Stock    Richard D. Dole                    3,060,815(2)             8.99%
                Chairman, President and CEO
                675 Bering Drive, Suite 200
                Houston, Texas  77057
---------------------------------------------------------------------------------
Common Stock    Wayne Beninger                      647,308 (3)             2.06%
                Chief Operating Officer
                675 Bering Drive, Suite 200
                Houston, Texas  77057
---------------------------------------------------------------------------------
Common Stock    David J. Collins                     913,263(4)             2.91%
                Vice President and Chief
                Financial Officer
                675 Bering Drive, Suite 200
                Houston, Texas  77057


                                       35
<PAGE>
---------------------------------------------------------------------------------
Common Stock    Eric D. Brown                        696,360(5)             2.20%
                Vice President of Finance
                675 Bering Drive, Suite 200
                Houston, Texas  77057
---------------------------------------------------------------------------------
Common Stock    Gerald Agranoff                     121,795 (6)             0.39%
                Director
                675 Bering Drive, Suite 200
                Houston, Texas  77057
---------------------------------------------------------------------------------
Common Stock    Richard Majeres                     196,795 (7)             0.63%
                Director
                675 Bering Drive, Suite 200
                Houston, Texas  77057
---------------------------------------------------------------------------------
---------------------------------------------------------------------------------
                ALL OFFICERS AND DIRECTORS           5,636,336             17.18%
                AS A GROUP (TOTAL OF  6)
---------------------------------------------------------------------------------
---------------------------------------------------------------------------------
Common Stock    GLG Partners, LP                  1,795,098 (8)             5.78%
                1 Curzon Street
                London, XO W1J 5HB
---------------------------------------------------------------------------------
Common Stock    North Sound Capital, LLC          2,770,000 (9)             8.92%
                20 Horseneck Lane
                Greenwich, CT 06830
---------------------------------------------------------------------------------
Common Stock    Charles L Barney                 1,538,464 (10)             4.95%
                90 Echo Lane, Suite 364
                Houston, TX 77024
---------------------------------------------------------------------------------
</TABLE>


(1)   Under Rule 13d-3 promulgated under the Exchange Act, a beneficial owner of
a  security  includes  any  person  who,  directly  or  indirectly,  through any
contract,  arrangement, understanding, relationship, or otherwise has or shares:
(i)  voting  power, which includes the power to vote, or to direct the voting of
shares; and (ii) investment power, which includes the power to dispose or direct
the disposition of shares. Certain shares may be deemed to be beneficially owned
by more than one person (if, for example, persons share the power to vote or the
power  to  dispose  of  the  shares).  In  addition,  shares  are  deemed  to be
beneficially owned by a person if the person has the right to acquire the shares
(for example, upon exercise of an option) within 60 days of the date as of which
the  information  is  provided.  In  computing  the  percentage ownership of any
person,  the  amount  of  shares  is  deemed  to  include  the  amount of shares
beneficially  owned  by  such  person  (and only such person) by reason of these
acquisition  rights.  As  a  result, the percentage of outstanding shares of any
person  as  shown in this table does not necessarily reflect the person's actual
ownership  or  voting power with respect to the number of shares of common stock
actually  outstanding  on  March  15,  2006.  As  of  March  15, 2006 there were
31,057,101 shares of our common stock issued and outstanding.

(2)   Includes  65,385 shares of common stock held directly and 2,995,430 shares
issuable  upon  the exercise of warrants to purchase additional shares of common
stock. Excludes 950,000 warrants issued to Mr. Dole that have been gifted to his
children, to which Mr. Dole disavows beneficial ownership.

(3)   Includes  247,692  shares of common stock held directly and 399,616 shares
issuable directly upon the exercise of warrants to purchase additional shares of
common stock.

(4)   Includes  413,263  shares  held  indirectly through DC Financial Services,
LLC,  126,923 shares held directly and 373,077 shares issuable directly upon the
exercise of warrants to purchase additional shares of common stock.

(5)   Includes  139,743  shares  held  indirectly  through Famco of Maryland LP,
2,770  held  directly, and 553,847 shares issuable directly upon the exercise of
warrants to purchase additional shares of common stock.


                                       36
<PAGE>
(6)   Includes  10,257 shares held directly and 111,538 shares issuable upon the
exercise of warrants to purchase additional shares of common stock.

(7)   Includes  85,257  shares  held  directly by Mr. Majeres and 111,538 shares
issuable  upon  the exercise of warrants to purchase additional shares of common
stock.

(8)   Includes  1,421,200  shares  held  by GLG North American Opportunity Fund;
322,308  shares  held  by  GLG North American Equity Fund; 13,000 shares held by
CITI  GLG  North  American Fund Limited; and 38,590 shares held by Lyxor/GLG Pan
European Equity Fund Limited.

(9)   Includes  775,600  shares  held  by  North  Sound  Institutional  Fund and
1,994,400 shares held by North Sound International Fund.

(10)   Includes  1,076,926 shares held by C Barney Investments, Ltd. and 461,538
shares held by Mark X Energy Company.

_____________________________

We are not aware of any arrangements that could result in a change of control.

The  disclosure required by Item 201(d) of Regulation S-B is set forth in ITEM 5
herein.

ITEM  12.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Except  as  described  below,  none  of  the following persons has any direct or
indirect  material  interest  in any transaction to which we were or are a party
during the past two years, or in any proposed transaction to which we propose to
be a party:

(A)  any of our directors or executive officers;

(B)  any nominee for election as one of our directors;

(C)  any  person who is known by us to beneficially own, directly or indirectly,
     shares  carrying  more  than 5% of the voting rights attached to our common
     stock; or

(D)  any  member  of  the immediate family (including spouse, parents, children,
     siblings  and  in-laws)  of any of the foregoing persons named in paragraph
     (A), (B) or (C) above.

Mr.  Wayne  Beninger, who became our Chief Operating Officer on May 16, 2005, is
the  owner  of  Southwest  Oil  &  Gas  Management  ("SOGMI") which has provided
engineering  and  geological  consulting  services  for our projects. During the
fiscal  year  ended  December 31, 2004, we paid SOGMI approximately $600,000 for
such  services.  When Mr. Beninger became our employee, the agreement with SOGMI
was  terminated. From January 1, 2005, until the agreement was terminated on May
15,  2005,  we  paid SOGMI approximately $365,529 for engineering and geological
consulting  services.  We  believe  the  prices  and  bids  for  engineering and
geological  consulting  services  previously paid to SOGMI have been competitive
with  those quoted for similar services by unrelated third parties. Mr. Beninger
has  an  option to purchase for $1.00 a 5% interest (after payout to the company
and  our  drilling  partner)  in our subsidiary that holds the Jefferson County,
Mississippi project.

One of our former Directors, Mr. Don Henrich, is a principal officer of Maverick
Drilling  Co.,  Inc.,  a  company  which  is  owned  by  his wife, with which we
contracted  for drilling services in Fort Bend County, Texas. Additionally, Mrs.
Henrich  owned a 15-30% working interest in our Fort Bend County Prospect, which
was sold in July, 2005. During the fiscal year ending December 31, 2005, we paid
Maverick Drilling


                                       37
<PAGE>
Company  approximately  $316,000.  We  believe  Maverick's  prices  and bids for
drilling  services  have been competitive with those quoted for similar services
by  unrelated  third  parties.


ITEM  13.     EXHIBITS

     Exhibit 10.1 - First Amended and Restated Program Agreement, dated February
6,  2006.

     Exhibit 10.2 - Extension  Agreement,  dated  March  30,  2006

     Exhibit  23.1  -  Consent  of Independent Engineers - McCartney Engineering
LLC,  dated  March  29,  2006

     Exhibit  23.2 - Consent of Independent Engineers Ryder Scott Company, dated
March  29,  2006

     Exhibit  31.1  -  Certification  of  Chief Executive Officer of Petrosearch
Energy  Corporation  required  by  Rule  13a-14(1)  or  Rule  15d - 14(a) of the
Securities  Exchange  Act  of  1934,  as  adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.

     Exhibit  31.2  -  Certification  of  Chief Financial Officer of Petrosearch
Energy  Corporation   required  by  Rule  13a-14(1)  or  Rule  15d-14(a)  of the
Securities  Exchange  Act  of  1934,  as  adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.

     Exhibit  32.1  -  Certification  of  Chief Executive Officer of Petrosearch
Energy Corporation pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and
Section 1350 of 18 U.S.C. 63.

     Exhibit  32.2  -  Certification  of  Chief Financial Officer of Petrosearch
Energy  Corporation  pursuant  to  Section 906 of the Sarbanes-Oxley Act of 2002
and Section 1350 of 18 U.S.C. 63.


ITEM  14.  PRINCIPAL ACCOUNTING FEES AND SERVICES

     The  following  table  sets  forth  the  aggregate fees paid or accrued for
professional  services  rendered by Ham, Langston & Brezina for the audit of our
annual  financial  statements  for fiscal year 2005 and fiscal year 2004 and the
aggregate fees paid or accrued for audit-related services and all other services
rendered by Ham, Langston & Brezina for fiscal year 2005 and fiscal year 2004.

<TABLE>
<CAPTION>
                             2005          2004
                         ------------  ------------
<S>                      <C>           <C>
     Audit fees          $     48,000  $     62,500
     Audit-related fees        23,000        26,500
     Tax fees                   9,805         4,850
     All other fees            27,309        11,664
                         ------------  ------------

     Total               $    108,114  $    105,514
                         ============  ============
</TABLE>

     The  category of "Audit fees" includes fees for our annual audit, quarterly
reviews  and  services  rendered  in connection with regulatory filings with the
SEC, such as the issuance of comfort letters and consents.

     The category of "Audit-related fees" includes employee benefit plan audits,
internal control reviews and accounting consultation.

     The  category  of  "Tax  fees"  includes  consultation related to corporate
development activities.

All  above  audit  services,  audit-related  services  and  tax  services  were
pre-approved  by the Audit Committee, which concluded that the provision of such
services  by Ham, Langston & Brezina was compatible with the maintenance of that
firm's independence in the conduct of its auditing functions.


                                       38
<PAGE>
                                   SIGNATURES

In  accordance with the requirements of Section 13 of 15(d) of the Exchange Act,
the  Registrant  has  caused  this  report  to  be  signed  on its behalf by the
undersigned, thereunto duly authorized, on March 31, 2006.

PETROSEARCH ENERGY CORPORATION

By  /s/ Richard D. Dole
    ----------------------
Richard D. Dole
President and Chief Executive Officer

By  /s/ David Collins
    -------------------
David Collins
Chief Financial Officer and
Principal Accounting Officer


In  accordance  with  the  requirements of the Securities Act of 1933, this Form
10-KSB  has  been  signed  below by or on behalf of the following persons in the
capacities and on the dates stated.

<TABLE>
<CAPTION>
Signature                              Title                               Date
<S>                      <C>                                 <C>
By /s/ Richard D. Dole   President, Chief Executive Officer  March 31, 2006
-----------------------  and Chairman of the Board
Richard D. Dole

By /s/ David J. Collins  Chief Financial Officer             March 31, 2006
-----------------------  and Principal Accounting Officer
David J. Collins

By /s/  Gerald Agranoff  Director                            March 31, 2006
-----------------------
Gerald Agranoff

By /s/ Richard Majeres   Director                            March 31, 2006
-----------------------
Richard Majeres
</TABLE>


                                       39
<PAGE>
             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
             -------------------------------------------------------



To the Board of Directors and Stockholders
Petrosearch Energy Corporation


We  have  audited  the  accompanying  consolidated balance sheets of Petrosearch
Energy  Corporation  and  subsidiaries  as of December 31, 2005 and 2004 and the
related  consolidated  statements  of  operations, stockholders' equity and cash
flows  for the years then ended. These consolidated financial statements are the
responsibility  of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.

We  conducted  our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements  are free of material misstatement. An audit includes examining, on a
test  basis,  evidence  supporting  the amounts and disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made  by  management,  as well as evaluating the overall
financial  statement  presentation.  We  believe  that  our  audits  provide  a
reasonable basis for our opinion.

In  our opinion, the consolidated financial statements referred to above present
fairly,  in  all  material  respects,  the  consolidated  financial  position of
Petrosearch  Energy  Corporation  and  subsidiaries  as of December 31, 2005 and
2004,  and  the  results  of their operations and their cash flows for the years
then  ended,  in conformity with accounting principles generally accepted in the
United States of America.



                                     /s/ Ham, Langston & Brezina, L.L.P.



Houston, Texas

March 29, 2006


                                      F-1
<PAGE>
<TABLE>
<CAPTION>
                                   PETROSEARCH ENERGY CORPORATION
                                    CONSOLIDATED BALANCE SHEETS
                                     DECEMBER 31, 2005 AND 2004

    ASSETS                                                                   2005          2004
    ------                                                               ------------  ------------
<S>                                                                      <C>           <C>
Current assets:
  Cash                                                                   $ 4,052,844   $ 1,100,568
  Accounts receivable:
    Joint owners-billed, net of allowance of $83,073 at                    1,342,386       935,622
    December 31, 2005
    Joint owners-unbilled                                                      1,958       624,541
    Oil and gas production sales                                               9,345       264,623
  Prepaid expenses and other current assets                                  517,482       389,048
                                                                         ------------  ------------

      Total current assets                                                 5,924,015     3,314,402
                                                                         ------------  ------------

Property and equipment:
  Oil and gas properties, full cost method of accounting:
    Properties subject to amortization                                    11,849,520     5,490,447
    Properties not subject to amortization                                 3,513,597     3,548,812
  Other property and equipment                                               147,047        69,136
                                                                         ------------  ------------

    Total                                                                 15,510,164     9,108,395

  Less accumulated depreciation, depletion and amortization               (1,966,000)   (2,164,936)
                                                                         ------------  ------------

    Total property and equipment, net                                     13,544,164     6,943,459

Prepaid oil and gas costs                                                     81,603        82,280

Other assets                                                                  66,462        65,901
                                                                         ------------  ------------

    Total assets                                                         $19,616,244   $10,406,042
                                                                         ============  ============

LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------

Current liabilities:
  Current portion of long-term debt                                      $   908,168   $ 2,890,000
  Accounts payable                                                           561,546       847,332
  Accrued liabilities                                                        750,036     1,338,641
                                                                         ------------  ------------

    Total current liabilities                                              2,219,750     5,075,973
                                                                         ------------  ------------
Long-term debt, net of current portion                                     2,537,251             -
Other long-term obligations                                                  670,456             -
Stockholders' equity:
  Preferred stock, par value $1.00 per share, 20,000,000 shares
  authorized:
    Series A  8% convertible preferred stock, 1,000,000 shares               483,416       483,416
    authorized; 483,416 shares issued and outstanding
    Series B convertible preferred stock, 100,000 shares authorized;          43,000        43,000
    43,000 shares issued and outstanding
  Common stock, par value $0.001 per share, 100,000,000 shares                28,497        18,792
  Authorized; 28,497,761 and 18,792,120 shares issued and
  outstanding at December 31, 2005 and 2004, respectively
  Additional paid-in capital                                              18,089,828     6,884,784
  Unissued common stock                                                      545,000             -
  Accumulated deficit                                                     (5,000,954)   (2,099,923)
                                                                         ------------  ------------

    Total stockholders' equity                                            14,188,787     5,330,069
                                                                         ------------  ------------

    Total liabilities and stockholders' equity                           $19,616,244   $10,406,042
                                                                         ============  ============
</TABLE>

    The accompanying notes are an integral part of these consolidated financial
                                   statements.


                                      F-2
<PAGE>
<TABLE>
<CAPTION>
                         PETROSEARCH ENERGY CORPORATION
                      CONSOLIDATED STATEMENTS OF OPERATIONS
                 FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004

                                                  2005          2004
                                              ------------  ------------
<S>                                           <C>           <C>
Oil and gas production revenues               $ 1,701,043   $ 4,718,313
                                              ------------  ------------

Operating costs and expenses:
  Lease operating and production taxes            581,313       773,723
  Depreciation, depletion and amortization        563,252     2,219,998
  General and administrative                    3,268,088     3,239,184
                                              ------------  ------------

    Total costs and expenses                    4,412,653     6,232,905
                                              ------------  ------------

Operating loss                                 (2,711,610)   (1,514,592)
                                              ------------  ------------

Other income (expense):
  Interest income                                  51,031         7,754
  Interest expense                               (240,452)      (64,282)
                                              ------------  ------------

    Total other income (expense)                 (189,421)      (56,528)
                                              ------------  ------------

      Net loss                                $(2,901,031)  $(1,571,120)
                                              ============  ============

Basic and diluted net loss per common share   $     (0.11)  $     (0.09)
                                              ============  ============

Weighted average common shares                 25,409,348    17,576,294
                                              ============  ============
</TABLE>

    The accompanying notes are an integral part of these consolidated financial
                                   statements.


                                      F-3
<PAGE>
<TABLE>
<CAPTION>
                                                  PETROSEARCH ENERGY CORPORATION
                                          CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
                                          FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004


                                              SERIES A               SERIES B              SERIES C              SERIES D
                   COMMON      STOCK       PREFERRED STOCK        PREFERRED STOCK      PREFERRED STOCK         PREFERRED STOCK
                   SHARES      AMOUNT     SHARES      AMOUNT      SHARES    AMOUNT     SHARES     AMOUNT      SHARES     AMOUNT
                 -----------  --------  ----------  -----------  --------  --------  ----------  ---------  ----------  ---------
<S>              <C>          <C>       <C>         <C>          <C>       <C>       <C>         <C>        <C>         <C>
Balance at
December 31,     16,836,861   $16,837   1,000,000   $1,000,000     43,000  $ 43,000     75,000   $ 75,000      37,500   $ 37,500
2003

Common stock
issued for
cashless             85,537        86           -            -          -         -          -          -           -          -
exercise of
warrants

Common stock
issued for        1,374,338     1,374           -            -          -         -          -          -           -          -
cash

Common stock
issued for           12,308        12           -            -          -         -          -          -           -          -
property costs

Common stock
issued for           16,923        17           -            -          -         -          -          -           -          -
services

Issuance of
committed stock     535,349       535           -            -          -         -          -          -           -          -

Collection of
subscription              -         -           -            -          -         -          -          -           -          -
receivable

Reduction of
subscription
receivable in             -         -           -            -          -         -          -          -           -          -
lieu of
compensation

Exchange of
Series A
preferred stock      79,474        79    (516,584)    (516,584)         -         -          -          -           -          -
for common
stock

Exchange of
Series C
preferred stock      34,615        35           -            -          -         -    (75,000)   (75,000)          -          -
for common
stock

Exchange of
Series D
preferred stock      23,077        23           -            -          -         -          -          -     (37,500)   (37,500)
for common
stock

Cancellation of
common stock
for payment of     (206,362)     (206)          -            -          -         -          -          -           -          -
receivables

Issuance of
warrants for              -         -           -            -          -         -          -          -           -          -
services

Net loss                  -         -           -            -          -         -          -          -           -          -
                 -----------  --------  ----------  -----------  --------  --------  ----------  ---------  ----------  ---------

Balance at
December 31      18,792,120   $18,792     483,416   $  483,416     43,000  $ 43,000          -   $      -           -   $      -
2004             ===========  ========  ==========  ===========  ========  ========  ==========  =========  ==========  =========



                                                                                TOTAL
                  ADDITIONAL     UNISSUED         STOCK                         STOCK
                   PAID-IN        COMMON      SUBSCRIPTIONS    ACCUMULATED     HOLDERS
                   CAPITAL        STOCK        RECEIVABLE        DEFICIT        EQUITY
                 ------------  ------------  ---------------  -------------  ------------
<S>              <C>           <C>           <C>              <C>            <C>
Balance at
December 31,     $ 1,695,830   $ 2,618,076   $     (329,410)  $   (528,803)  $ 4,628,030
2003

Common stock
issued for
cashless                 (86)            -                -              -             -
exercise of
warrants

Common stock
issued for         1,852,106             -                -              -     1,853,480
cash

Common stock
issued for            51,908             -                -              -        51,920
property costs

Common stock
issued for            80,463             -                -              -        80,480
services

Issuance of
committed stock    2,617,541    (2,618,076)               -              -             -

Collection of
subscription               -             -           35,000              -        35,000
receivable

Reduction of
subscription
receivable in              -             -           45,000              -        45,000
lieu of
compensation

Exchange of
Series A
preferred stock      516,505             -                -              -             -
for common
stock

Exchange of
Series C
preferred stock       74,965             -                -              -             -
for common
stock

Exchange of
Series D
preferred stock       37,477             -                -              -             -
for common
stock

Cancellation of
common stock
for payment of      (321,804)            -          249,410              -       (72,600)
receivables

Issuance of
warrants for         279,879             -                -              -       279,879
services

Net loss                   -             -                -     (1,571,120)   (1,571,120)
                 ------------  ------------  ---------------  -------------  ------------

Balance at
December 31      $ 6,884,784   $         -   $            -   $ (2,099,923)  $ 5,330,069
2004             ============  ============  ===============  =============  ============
</TABLE>

    The accompanying notes are an integral part of these consolidated financial
                                   statements.


                                      F-4
<PAGE>
<TABLE>
<CAPTION>
                                             PETROSEARCH ENERGY CORPORATION
                                     CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
                                     FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004

                                            SERIES A          SERIES B          SERIES C              SERIES D
                       COMMON STOCK      PREFERRED STOCK   PREFERRED STOCK   PREFERRED STOCK      PREFERRED STOCK
                     SHARES     AMOUNT   SHARES   AMOUNT   SHARES  AMOUNT    SHARES    AMOUNT     SHARES    AMOUNT
                 ------------  -------  -------  --------  ------  -------  --------  ---------  --------  --------
<S>              <C>           <C>      <C>      <C>       <C>     <C>      <C>       <C>        <C>       <C>
Balance at
December 31,      18,792,1200  $18,792  483,416  $483,416  43,000  $43,000         -  $       -         -  $      -
2004

Common Stock
issued for cash     9,174,873    9,174        -         -       -        -         -          -         -         -

Common stock
issued and
committed for         500,000      500        -         -       -        -         -          -         -         -
oil and gas
properties

Compensation
awarded to
Board of               30,768       31        -         -       -        -         -          -         -         -
Directors

Issuances of
warrants with               -        -        -         -       -        -         -          -         -         -
debt

Cancellation of
warrants                    -        -        -         -       -        -         -          -         -         -

Net loss                    -        -        -         -       -        -         -          -         -         -
                 ------------  -------  -------  --------  ------  -------  --------  ---------  --------  --------

                   28,497.761  $28,497  483,416  $483,416  43,000  $43,000         -  $       -         -  $      -
                 ============  =======  =======  ========  ======  =======  ========  =========  ========  ========


                      ADDITIONAL     UNISSUED        STOCK                        STOCK
                       PAID-IN       COMMON      SUBSCRIPTIONS   ACCUMULATED     HOLDERS
                       CAPITAL        STOCK        RECEIVABLE      DEFICIT       EQUITY
                     ------------  ------------  -------------  -------------  -----------
<S>                  <C>           <C>           <C>            <C>            <C>
Balance at
December 31,         $ 6,884,784   $          -  $           -  $ (2,099,923)  $5,330,069
2004

Common Stock
issued for cash       10,600,545              -              -             -   10,609,719

Common stock
issued and
committed for            544,500        545,000              -             -    1,090,000
oil and gas
properties

Compensation
awarded to
Board of                  59,969              -              -             -       60,000
Directors

Issuances of
warrants with             88,422              -              -             -       88,422
debt

Cancellation of
warrants                 (88,392)             -              -             -      (88,392)

Net loss                       -              -              -    (2,901,031)  (2,901,031)
                     ------------  ------------  -------------  -------------  -----------

                     $18,089,828   $    545,000  $           -   $ (5,000,954)  $14,188,787
                     ============  ============  =============  =============  ===========
</TABLE>

    The accompanying notes are an integral part of these consolidated financial
                                   statements.


                                      F-5
<PAGE>
<TABLE>
<CAPTION>
                                     PETROSEARCH ENERGY CORPORATION
                                  CONSOLIDATED STATEMENT OF CASH FLOWS
                             FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004

                                                                                 2005          2004
                                                                             ------------  ------------
<S>                                                                          <C>           <C>
Cash flows from operating activities:
Net loss                                                                     $(2,901,031)  $(1,571,120)
Adjustments to reconcile net loss to net cash used in operating activities:
  Depletion, depreciation and amortization expense                               563,252     2,219,998
  Write off of prepaid oil and gas costs                                          60,000        32,219
  Reduction in subscription receivable in lieu of compensation                         -        45,000
  Common stock and warrants issued as compensation for services                   60,000       360,359
  Amortization of deferred rent                                                       77             -
  Amortization of debt discount and financing costs                               48,283             -
  Bad debt expense                                                               145,443
Changes in operating assets and liabilities:
  Accounts receivable                                                            368,664    (1,330,588)
  Related party receivable                                                             -       (16,926)
  Prepaid expenses and other assets                                             (235,055)     (284,360)
  Accounts payable and accrued liabilities                                      (599,672)      248,926
                                                                             ------------  ------------

Net cash used in operating activities                                         (2,490,039)     (296,492)
                                                                             ------------  ------------

Cash flows from investing activities:
  Capital expenditures, including purchases and development of properties     (7,815,083)   (6,356,134)
  Purchase of prepaid credits for oil and gas properties, net                    (59,323)
  Proceeds from sale of overriding royalty interest                                    -       100,000
  Proceeds from sale of property                                               2,072,002        18,000
                                                                             ------------  ------------

Net cash used in investing activities                                         (5,802,404)   (6,238,134)
                                                                             ------------  ------------

Cash flows from financing activities:
  Proceeds from the sale of common stock                                      10,609,719     1,853,480
  Proceeds from collection of stock subscription receivable                            -     1,231,250
  Proceeds from notes payable                                                  3,950,000     3,100,000
  Repayment of bonds payable                                                                  (200,000)
  Repayment of notes payable                                                  (3,315,000)     (210,000)
                                                                             ------------  ------------

Net cash provided by financing activities                                     11,244,719     5,774,730
                                                                             ------------  ------------

Net increase (decrease) in cash and cash equivalents                           2,952,276      (759,896)

Cash and cash equivalents at beginning of year                                 1,100,568     1,860,464
                                                                             ------------  ------------

Cash and cash equivalents at end of year                                     $ 4,052,844   $ 1,100,568
                                                                             ============  ============

Supplemental disclosures of cash flow information:
  Interest paid                                                              $   227,192   $    40,470
                                                                             ============  ============

  Income taxes paid                                                          $         -   $         -
                                                                             ============  ============
</TABLE>

    The accompanying notes are an integral part of these consolidated financial
                                   statements.


                                      F-6
<PAGE>
                         PETROSEARCH ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
     ------------------------------------------------

     ORGANIZATION
     ------------

     Petrosearch Energy Corporation (the "Company"), a Nevada Corporation formed
     in  November  2004, is an independent oil and gas company based in Houston,
     Texas, with a second office in Dallas, Texas. The Company is engaged in the
     exploration  for  and  the acquisition, development and production of crude
     oil  and  natural  gas.  The  Company  has  established production in North
     Dakota,  Oklahoma  and  Texas  and  is currently engaged in exploration and
     development  activities,  including direct operator activities, through its
     subsidiary,  Petrosearch  Operating  Company,  L.L.C.,  in  North  Dakota,
     Louisiana,  Texas,  Oklahoma,  and Mississippi. The Company identifies high
     quality  prospects and projects and provides the capital, technical support
     and  business  resources  needed  to develop the projects. The Company also
     pursues  ventures  with  other  independent  companies  when  targets  of
     exceptional  potential are available and considers acquisition of producing
     properties  with  additional  development  potential.  The  Company  is the
     successor of Petrosearch Corporation ("Petrosearch Texas") which was formed
     in August 2003 in the state of Texas pursuant to a reverse merger agreement
     with  Texas  Commercial  Resources,  Inc.  ("TCRI").  In  November  2004,
     shareholders  of  Petrosearch Texas approved a 6.5-to-1 reverse stock split
     which  took  effect  immediately  prior  to  its merger with the Company on
     December  30,  2004  (the  "Merger").  Upon  completion  of  the  Merger,
     shareholders  of Petrosearch Texas were issued common shares of Petrosearch
     Energy  Corporation  representing  100%  of the then issued and outstanding
     common  shares.

     The consolidated financial statements presented herein include the accounts
     of  the  Company  and  its  wholly-owned  subsidiaries.  All  significant
     inter-company accounts and transactions have been eliminated.

     ACCOUNTING ESTIMATES
     --------------------

     The  preparation  of  financial  statements  in  conformity with accounting
     principles  generally  accepted  in  the  United States of America requires
     management  to  make  estimates  and  assumptions  that affect the reported
     amounts  of  assets and liabilities at the date of the financial statements
     and  the  reported  amounts  of  revenue  and expenses during the reporting
     period.  Actual  results could differ from those estimates. These estimates
     primarily  involve  the  useful  lives  of  property  and  equipment,  the
     impairment  of  unproved  oil and gas properties, the valuation of deferred
     tax assets and the realization of accounts receivable.

     OIL AND GASPROPERTIES
     ---------------------

     The  Company  follows  the full cost method of accounting for crude oil and
     natural  gas  properties.  Under  this method, all direct costs and certain
     directly  related  internal costs associated with acquisition of properties
     and  successful,  as  well  as  unsuccessful,  exploration  and development
     activities  are  capitalized.  Depreciation,  depletion and amortization of
     capitalized  crude  oil  and  natural  gas  properties and estimated future
     development  costs,  excluding  unproved  properties,  are  based  on  the
     unit-of-production  method  based on proved reserves. Net capitalized costs
     of  crude  oil and natural gas properties, as adjusted for asset retirement
     obligations, net of salvage value, are limited, by country, to the lower of
     unamortized  cost  or  the  cost ceiling, defined as the sum of the present
     value  of  estimated  future  net  revenues  from  proved reserves based on
     unescalated  prices  discounted  at 10 percent, plus the cost of properties
     not being amortized, if any, plus the lower of cost or estimated fair value
     of  unproved properties included in the costs being amortized, if any, less
     related  income  taxes.  Excess  costs  are  charged  to  proved  property
     impairment  expense. No gain or loss is recognized upon sale or disposition
     of crude oil and natural gas properties, except in unusual circumstances.


                                      F-7
<PAGE>
     The  following  table  reflects the depletion expense incurred from oil and
     gas properties during the years ended December 31, 2005 and 2004:

<TABLE>
<CAPTION>
                                             2005       2004
                                           --------  ----------
<S>                                        <C>       <C>
       Depletion Expense                   $543,654  $2,207,949
                                           ========  ==========
       Depletion expense per bbl produced  $  15.24  $    16.83
                                           ========  ==========
</TABLE>

     At  December 31, 2005 and 2004, unproved oil and gas properties not subject
     to  amortization  included  $3,513,597  and  $3,548,812,  respectively,  of
     property  acquisition, exploration and development costs that are not being
     amortized.  These  costs will begin to be amortized when they are evaluated
     and  proved,  reserves  are discovered, impairment is indicated or when the
     lease  terms expire. Unproved leasehold costs consist of interest in leases
     located in Mississippi, Oklahoma and Texas.

     The  following  table  reflects  the  periods  when costs were incurred for
     unproved oil and gas properties costs:

<TABLE>
<CAPTION>
                                      2004        2005       TOTAL
                                   ----------  ----------  ----------
<S>                                <C>         <C>         <C>
       Property acquisition costs  $1,185,625  $1,678,257  $2,863,882
       Exploration costs                    -     649,715     649,715
                                   ----------------------------------

           Total                   $1,185,625  $2,327,972  $3,513,597
                                   ==========  ==========  ==========
</TABLE>

     Unproved properties represent costs associated with properties on which the
     Company  is  performing  exploration activities or intends to commence such
     activities.  These costs are reviewed periodically for possible impairments
     or  reduction  in  value  based  on  geological  and geophysical data. If a
     reduction in value has occurred, costs being amortized are increased.

     OTHER PROPERTY AND EQUIPMENT
     ----------------------------

     Property  and  equipment  is stated at cost. Depreciation is computed using
     the  straight-line  method  over the estimated useful lives of 3 to 5 years
     for  office furniture and equipment and transportation and other equipment.
     Additions  or improvements that increase the value or extend the life of an
     asset  are capitalized. Expenditures for normal maintenance and repairs are
     expensed  as incurred. Disposals are removed from the accounts at cost less
     accumulated depreciation and any gain or loss from disposition is reflected
     in  operations.  Depreciation  expense for other property and equipment for
     the  years  ended  December  31,  2005  and  2004  was $19,598 and $12,049,
     respectively.

     ASSET RETIREMENT OBLIGATIONS
     ----------------------------

     Effective  January  1,  2003,  the  Company  adopted Statement of Financial
     Accounting  Standards  No. 143, Accounting for Asset Retirement Obligations
     ("SFAS  143").  This  statement  applies to obligations associated with the
     retirement  of tangible long-lived assets that result from the acquisition,
     construction and development of the assets. SFAS 143 requires that the fair
     value  of  a  liability  for  a  retirement obligation be recognized in the
     period in which the liability is incurred. For oil and gas properties, this
     is the period in which an oil or gas well is acquired or drilled. The asset
     retirement  obligation is capitalized as part of the carrying amount of our
     oil  and gas properties at its discounted fair value. The liability is then
     accreted each period until the liability is settled or the well is sold, at
     which time the liability is reversed.

     Prior  to  2005, the discounted fair value of the Company's expected future
     obligation  was  estimated  to  approximate  salvage  value,  and, thus, no
     obligation was recorded. The estimated asset


                                      F-8
<PAGE>
     retirement  obligation as of December 31, 2005, of $633,455 is attributable
     to  property  additions  in  2005  and  as  been  recognized as a long-term
     obligation in the accompanying balance sheet as of December 31, 2005.

     CASH AND CASH EQUIVALENTS
     -------------------------

     For  purposes of reporting cash flows, the Company considers all short-term
     investments  with  an  original  maturity  of  three  months  or  less when
     purchased to be cash equivalents.

     RECEIVABLES
     -----------

     The Company routinely assesses the recoverability of all material trade and
     other  receivables to determine their collectibility. Many of the Company's
     receivables  are  from  joint  interest  owners  on properties of which the
     Company is the operator. Thus, the Company may have the ability to withhold
     future  revenue  disbursements to recover any non-payment of joint interest
     billings.  Generally,  the  Company's crude oil and natural gas receivables
     are  collected  within  two  months.  The  Company  accrues  a reserve on a
     receivable when, based on the judgment of management, it is probable that a
     receivable  will  not  be  collected  and  the amount of any reserve may be
     reasonably  estimated.  As  of  December  31,  2005  and  2004, the Company
     provided  an allowance of $83,073 and $ -0- for doubtful accounts for trade
     receivables or joint interest owner receivables.

     FAIR VALUE OF FINANCIAL INSTRUMENTS
     ---------------------------------------

     The  Company  includes  fair  value  information  in the notes to financial
     statements  when  the  fair value of its financial instruments is different
     from  the  book  value.  When  the  book  value approximates fair value, no
     additional  disclosure is made. The Company assumes the book value of those
     financial  instruments  that  are  classified  as current approximates fair
     value  because  of the short maturity of these instruments. For non-current
     financial  instruments,  the  Company  uses quoted market prices or, to the
     extent  that there are no available quoted market prices, market prices for
     similar instruments.

     RESTORATION, REMOVAL AND ENVIRONMENTAL LIABILITIES
     --------------------------------------------------

     The  Company is subject to extensive federal, state and local environmental
     laws  and  regulations. These laws regulate the discharge of materials into
     the  environment  and  may  require  the  Company to remove or mitigate the
     environmental effects of the disposal or release of petroleum substances at
     various  sites.  Environmental  expenditures  are  expensed  or capitalized
     depending  on their future economic benefit. Expenditures that relate to an
     existing  condition  caused  by  past  operations  and  that have no future
     economic benefit are expensed.

     Liabilities  for  expenditures  of  a  noncapital  nature are recorded when
     environmental assessments and/or remediation is probable, and the costs can
     be reasonably estimated. Such liabilities are generally undiscounted unless
     the  timing  of  cash  payments for the liability or component are fixed or
     reliably determinable. As of December 31, 2005, the Company believes it has
     no such liabilities.

     CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS
     ------------------------------------------------

     Financial instruments which subject the Company to concentrations of credit
     risk include cash and cash equivalents and accounts receivable. The Company
     maintains  its  cash and cash equivalents with major financial institutions
     selected  based  upon  management's  assessment  of  the  banks'  financial
     stability.  Balances  regularly  exceed  the  $100,000  federal  depository
     insurance  limit.  The  Company has not experienced any losses on deposits.
     The Company performs ongoing credit evaluations and, generally, requires no
     collateral  from  its  customers  or  other  joint  interest  owners. As of
     December  31,  2005,  98% of accounts receivable from oil and gas sales was
     from one customer and 86% of accounts receivable from joint interest owners
     was from one joint interest owner. During the years ended December 31, 2005
     and  2004, respectively, 98% and 100% of the Company's revenue was received
     from four and three customers as follows:


                                      F-9
<PAGE>
<TABLE>
<CAPTION>
                      2005        2004
                   ----------  ----------
<S>                <C>         <C>
       Customer A  $  879,542  $3,114,087
       Customer B     552,998   1,321,128
       Customer C     172,540     283,098
       Customer D      69,622           -
       Others          26,341           -
                   ----------------------
         Total     $1,701,043  $4,718,313
                   ==========  ==========
</TABLE>

     REVENUE RECOGNITION
     -------------------

     The  Company recognizes crude oil and natural gas revenue from its interest
     in  producing  wells as crude oil and natural gas is sold from those wells,
     net of royalties.

     EARNINGS (LOSS) PER SHARE
     -------------------------

     The  Company  provides  basic and dilutive earnings (loss) per common share
     information for each year presented. The basic net loss per common share is
     computed  by dividing the net loss by the weighted average number of common
     shares  outstanding.  Diluted  net  loss  per  common  share is computed by
     dividing  the  net  loss,  adjusted  on  an "as if converted" basis, by the
     weighted  average  number  of  common  shares  outstanding  plus  potential
     dilutive  securities.  For  the  years  ended  December  31, 2005 and 2004,
     potential  dilutive  securities,  assuming the Company had net income, that
     had  an  anti-dilutive  effect  and were not included in the calculation of
     diluted net loss per common share consisted of warrants for the purchase of
     651,281  and  5,207,070  common  shares,  respectively,  and  convertible
     preferred  stock  convertible  into  94,218  and  612,416  common  shares,
     respectively.  Per  share  calculations  reflect  the  effects  of  the
     recapitalization and reverse stock split for all periods presented.

     STOCK BASED COMPENSATION
     ------------------------

     SFAS  No.  123,  "Accounting  for  Stock-Based  Compensation"  established
     financial  accounting  and  reporting  standards  for  stock-based employee
     compensation  plans. It defined a fair value based method of accounting for
     an  employee  stock  option or similar equity instrument and encouraged all
     entities to adopt that method of accounting for all of their employee stock
     compensation  plans  and  include  the  cost  in  the  income  statement as
     compensation  expense.  However,  it  also  allows an entity to continue to
     measure  compensation  cost for those plans using the intrinsic value based
     method  of  accounting  prescribed  by  Accounting Principles Board ("APB")
     Opinion  No.  25,  "Accounting  for Stock Issued to Employees". The Company
     accounts  for  compensation  cost for stock option plans in accordance with
     APB  Opinion  No.  25.  See  "New  Accounting  Pronouncements"  below  for
     information  regarding  the  Company's  adoption  of  SFAS No. 123 (revised
     2004), "Share-Based Payment" ("SFAS 123(R)") on January 1, 2006.

     CAPITALIZED INTEREST
     --------------------

     The  Company  capitalizes  interest  ($46,630 in 2005 and $ -0- in 2004) on
     expenditures  made  in connection with exploration and development projects
     that  are not subject to current amortization. Interest is capitalized only
     for  the  period that activities are in progress to bring these projects to
     their intended use.

     INCOME TAXES
     ------------

     The Company uses the liability method in accounting for income taxes. Under
     this  method,  deferred  tax assets and liabilities are determined based on
     differences  between financial reporting and income tax carrying amounts of
     assets  and  liabilities  and  are measured using the enacted tax rates and
     laws that will be in effect when the differences are expected to reverse. A
     valuation allowance, if necessary, is provided against deferred tax assets,
     based upon management's


                                      F-10
<PAGE>
     assessment as to their realization.

     NEW ACCOUNTING PRONOUNCEMENTS
     -----------------------------

     The  following  discussions  provide  information  about  new  accounting
     pronouncements that have been issued by the FASB:

     In  December 2004, the FASB issued SFAS 123(R), which is a revision of SFAS
     123.  SFAS  123(R)  supersedes APB 25 and amends SFAS No. 95, "Statement of
     Cash  Flows".  Generally,  the  approach  in  SFAS 123(R) is similar to the
     approach  described  in  SFAS  123.  However,  SFAS 123(R) will require all
     share-based  payments  to  employees,  including  grants  of employee stock
     options,  to  be  recognized  as  stock-based  compensation  expense in the
     Company's Consolidated Statements of Operations based on their fair values.
     Proforma disclosure is no longer an alternative.

     SFAS  123(R)  must  be  adopted  no  later than January 1, 2006 and permits
     public companies to adopt its requirements using one of two methods:

     -    A  "modified  prospective"  method  in  which  compensation  cost  is
          recognized beginning with the effective date based on the requirements
          of SFAS 123(R) for all share-based payments granted after the adoption
          date  and based on the requirements of SFAS 123 for all awards granted
          to  employees  prior  to the effective date of SFAS 123(R) that remain
          unvested on the adoption date.

     -    A  "modified  retrospective" method which includes the requirements of
          the  modified  prospective  method  described  above, but also permits
          entities  to  restate  either  all  prior  periods  presented or prior
          interim  periods  of  the  year  of  adoption  based  on  the  amounts
          previously  recognized  under  SFAS  123  for  purposes  of  proforma
          disclosures.

     The  Company adopted the provisions of SFAS 123(R) on January 1, 2006 using
     the modified prospective method.

     As permitted by SFAS 123, the Company accounted for share-based payments to
     employees  prior  to  January  1,  2006  using  the  intrinsic value method
     prescribed  by  APB  25  and  related interpretations. As such, the Company
     generally  did  not recognize compensation expense associated with employee
     stock  option  grants.  Currently,  the Company has no plans to issue stock
     warrants  to  any  parties  other than in financing arrangements with third
     parties.  Consequently,  based  on  current  plans,  the  adoption  of SFAS
     123(R)'s  fair  value  method  will  not  have  a significant impact on the
     Company's  future  results  of  operations  or  financial position. Had the
     Company  adopted  SFAS  123(R)  in  prior  periods,  the  impact would have
     approximated  the  impact  of  SFAS  123  as  described  in  the  proforma
     disclosures.  The  adoption  of  SFAS  123(R)  will  not  result  in  any
     compensation charges in 2006 related to options outstanding at December 31,
     2005,  because  all  employee  stock options were vested as of December 31,
     2005.

     SFAS  123(R)  also  requires  that  tax  benefits  in  excess of recognized
     compensation  expenses be reported as a financing cash flow, rather than an
     operating  cash  flow  as required under prior literature. This requirement
     may  serve  to  reduce  the  Company's  future  cash  flows  from operating
     activities and increase future cash flows from financing activities, to the
     extent of associated tax benefits that may be realized in the future.

     In  June  2005, the Financial Accounting Standards Board (FASB) issued FASB
     Statement  No.  154,  "Accounting  Changes  and  Error  Corrections  -  a
     replacement of APB Opinion No. 20 and FASB Statement No. 3". This Statement
     provides guidance on the accounting for and reporting of accounting changes
     and  error corrections. It establishes, unless impracticable, retrospective
     application  as  the  required  method for reporting a change in accounting
     principle  in  the  absence of explicit transition requirements specific to
     the  newly  adopted  accounting  principle.  This  Statement  also provides
     guidance  for  determining whether retrospective application of a change in
     accounting  principle  is  impracticable  and  for  reporting a change when
     retrospective application is


                                      F-11
<PAGE>
     impracticable.  The  correction  of an error in previously issued financial
     statements  is not an accounting change. However, the reporting of an error
     correction  involves  adjustments to previously issued financial statements
     similar  to  those  generally  applicable to reporting an accounting change
     retrospectively.  Therefore,  the  reporting of a correction of an error by
     restating  previously issued financial statements is also addressed by this
     Statement.  This  Statement  shall  be effective for accounting changes and
     correction  of  errors  made  in  fiscal years beginning after December 15,
     2005.  At  this  time,  the  Company  has  no  plans  to  adopt a change in
     accounting  principle;  however,  this  guidance  could  have a significant
     impact on the Company in the event that an accounting change is made in the
     future.

     In  March 2005, the Financial Accounting Standards Board (FASB) issued FASB
     Interpretation  (FIN)  47,  "Accounting  for  Conditional  Asset Retirement
     Obligations,  an  interpretation  of  FASB  Statement  No.  143".  This
     interpretation  clarifies  that  the  term,  conditional  asset  retirement
     obligation, as used in FASB Statement No. 143, refers to a legal obligation
     to  perform  an asset retirement activity in which the timing and/or method
     of  settlement  are  conditional  on  a future event that may or may not be
     within  the  control  of  the  entity.  The obligation to perform the asset
     retirement  activity  is unconditional even though uncertainty exists about
     the  timing  and/or method of settlement. Thus, the timing and/or method of
     settlement  may be conditional on a future event. Accordingly, an entity is
     required to recognize a liability for the fair value of a conditional asset
     retirement  obligation if the fair value of the liability can be reasonably
     estimated.  The  fair  value  of  a  liability  for  the  conditional asset
     retirement  obligation  should  be recognized when incurred, generally upon
     acquisition,  construction,  or  development  and/or  through  the  normal
     operation  of  the  asset.  Uncertainty  about  the timing and/or method of
     settlement  of a conditional asset retirement obligation should be factored
     into  the  measurement of the liability when sufficient information exists.
     SFAS  No.  143 acknowledges that, in some cases, sufficient information may
     not  be  available  to  reasonably  estimate  the  fair  value  of an asset
     retirement obligation. We do not expect this guidance to have a significant
     impact on the Company.

2.   SALE OF OIL AND GAS PROPERTIES
     ------------------------------

     Effective  July  1,  2005,  the  Company's  wholly  owned  subsidiary,  TK
     Petrosearch,  L.L.C.,  sold  its interest in the Blue Ridge Salt Dome Field
     for  $2,072,002  to  the individual who has managed the TK PetroSearch, LLC
     subsidiary. The assets sold accounted for $1,370,110 of the Company's PV-10
     of  proved  reserves  as  of December 31, 2004, or approximately 10% of the
     Company's total PV-10 value. The property had an estimated remaining 68,700
     barrels of proved oil reserves at the time of the sale. The transaction has
     been  reflected  in the accompanying financial statements as a reduction of
     capitalized  oil  and  gas  properties as required by accounting principles
     generally  accepted  in  the  United  States  of  America.  The  following
     represents  the  unaudited proforma effect on the consolidated statement of
     operations  for  the  year  ended  December  31, 2005 as if the transaction
     occurred  on  January 1, 2005. The sale represents $30.16 per barrel of oil
     of the proved reserves sold.

<TABLE>
<CAPTION>
                                                      PROFORMA       PROFORMA
                                      AS REPORTED    ADJUSTMENTS    (UNAUDITED)
                                     -------------  -------------  -------------
<S>                                  <C>            <C>            <C>
       Oil and gas production
       revenues                        $  1,701,043   $   (552,998)  $  1,148,045
       Costs and expenses                 4,412,653        359,162      4,053,491
                                       -------------  -------------  -------------
       Operating loss                    (2,711,610)      (193,836)    (2,905,446)
       Other expenses                      (189,421)             -       (189,421)
                                       -------------  -------------  -------------
       Net loss                        $ (2,901,031)  $   (193,836)  $( 3,094,867)
                                       =============  =============  =============
       Basic and diluted net loss per
       common share                    $      (0.11)  $      (0.01)  $      (0.12)
                                       =============  =============  =============
</TABLE>


                                      F-12
<PAGE>
3.   PURCHASE OF OIL AND GAS PROPERTIES
     ----------------------------------

     Effective  September  28,  2005, the Company purchased an additional 21.25%
     working  interest  in the Gruman #18-1 Well and Gruman Leases for $637,500,
     increasing  the  Company's working interest in the properties to 85%. As of
     the  time  of  the closing, the purchase provided additional PV-10 value of
     approximately  $3,500,000  (based upon independent engineering report as of
     July  1,  2005), made up of additional proved reserves of 89,755 barrels of
     oil  and  25,672 MCF of gas. The purchase price represents $6.67 per barrel
     of oil equivalent of the proved reserves purchased.

     Effective  November  15,  2005,  the  Company  entered into an agreement to
     purchase  a  100%  working interest in 1780 acres of leases in the Quinduno
     Field  located  in  Roberts  County, Texas from Quinduno Energy, L.L.C. The
     agreement provides for the payment of the purchase price of $2,000,000 cash
     and  3,000,000 shares of unregistered common shares of the Company to occur
     in  three  phases as the project progresses. Should the project not proceed
     past the first phase, Petrosearch's maximum obligation would be $750,000 in
     cash  and  1,000,000  unregistered  common  shares plus the cost of capital
     expenditures for the first phase which are estimated to be $2,900,000. Upon
     completion of the entire project, the seller will back in for a 10% working
     interest  after  Petrosearch  has been repaid all capital expenditure costs
     plus  $9.5  million.  Based  on  the  valuation  of the acquisition of $9.5
     million  on November 15, 2005, this purchase represents $3.37 per barrel of
     oil equivalent of the proved reserves purchased.

     At  any time after completion of the first phase of the project, should the
     Company,  in  the Company's sole discretion, determine to terminate further
     operations,  then the Company must offer Quinduno the Company's interest in
     the  leases for a purchase price equal to an internal rate of return to the
     Company  of  twenty-two  and  one half percent (22.5%), calculated monthly,
     using  the  closing  date under the Agreement as the commencement date and,
     taking  into account all acquisition cash, all capital expenditures, plus a
     sum  of  $7,500,000  and the net income received from the project. Quinduno
     will  have  45  days  to  exercise  its  right of refusal to repurchase the
     leases,  at  which time, upon Quinduno's refusal to repurchase, the Company
     may sell the Company's interest in the leases to a third party.


4.   PREPAID EXPENSES AND OTHER CURRENT ASSETS
     -----------------------------------------

     Prepaid  expenses  and  other  current  assets  consist of the following at
     December  31,  2005  and  2004:

<TABLE>
<CAPTION>
                                              2005         2004
                                           -----------  ----------
<S>                                        <C>          <C>
       Prepaid expenses                    $   152,386  $   90,207
       Note receivable                               -     110,000
       Prepaid bonds                           277,000     177,000
       Current portion of financing costs       42,890           -
       Other receivables                        45,206           -
       Other assets                                  -      11,841
                                           -----------------------

                                           $   517,482  $  389,048
                                           ===========  ==========
</TABLE>


                                      F-13
<PAGE>
5.   ACCRUED LIABILITIES
     -------------------

     Accrued liabilities consist of the following at December 31, 2005 and 2004:

<TABLE>
<CAPTION>
                                                            2005       2004
                                                          --------  ----------
<S>                                                       <C>       <C>
       Revenue payable and operated prepayment liability  $ 21,297  $  139,270
       Accrued interest payable                             36,794      25,187
       Accrued liabilities for capital additions           500,000   1,017,058
       Accrued liability for Professional Fees              50,000           -
       Other accrued expenses                              141,945     157,126
                                                          --------------------

                                                          $750,036  $1,338,641
                                                          ========  ==========
</TABLE>


6.   REVOLVING CREDIT AGREEMENT
     --------------------------

     On  October  1, 2004, the Company entered into a revolving credit agreement
     to  borrow  up  to  $18,000,000 over a one-year period from a company whose
     managing partner is a shareholder of the Company. Draws under the agreement
     were  subject  to  limits  after  the  initial  draw  at  a maximum rate of
     $4,500,000 for each three-month period following the initial draw date with
     undrawn  funds  to  be carried forward to the succeeding draw period. Draws
     were  also limited based on the Company's actual cost of oil and gas leases
     and  the  amount of the Company's proved producing reserves. Advances under
     the  revolving credit agreement bear interest at a rate of six percent (6%)
     per  year  which  was  payable each quarter, and were collateralized by the
     Company's  oil  and gas properties. The agreement stipulates that, after 60
     days  of  each particular draw, the Company repay the outstanding principal
     in  monthly  installments  equal  to  10%  of  the  original  amount of the
     particular  draw  and continue on the same calendar date of each succeeding
     month  thereafter.  The  outstanding principal and interest balance matures
     two  years  from  the  date of the initial draw, which is October 2006. The
     Company  was  assessed  a one quarter of one percent (0.25%) standby fee on
     available undrawn principal each quarter.

     As  additional  consideration  for this agreement, the Company assigned the
     lender  a one percent (1%) overriding royalty interest in certain producing
     wells  in Oklahoma and Texas and a commitment to provide a one percent (1%)
     overriding  royalty interest in all future leases acquired using funds from
     this  agreement.  Per  the  agreement,  this overriding royalty interest is
     earned  by  the  lender  upon  funding  and  is  not subject to revision or
     reassignment  upon  repayment  or termination of the loan. As a result, the
     Company  capitalized  the  net  present  value  of  this overriding royalty
     interest  of  $24,825,  plus  additional loan costs of $38,743, as deferred
     loan  cost in the consolidated balance sheet as of December 31, 2004. These
     loan  costs  were  being  amortized into interest expense over the two-year
     life of the agreement.

     On  September  29,  2005,  the Company entered into an amended and restated
     revolving  credit  agreement  to  borrow  up to $10,000,000 over a two-year
     period  to  October  1,  2007,  from  a  private,  non-public  entity.  The
     outstanding  loan  balance  under  the  original revolving credit agreement
     dated October 1, 2004, of $825,000 and accrued interest through the date of
     the amended agreement, were deemed to be principal and interest outstanding
     under  the amended and restated revolving credit agreement. Proceeds of the
     credit  line  are  to  be  used  to  finance  activity related to eight new
     prospects  including  costs  associated  with  acquisitions  of oil and gas
     leases,  oil  and  gas  drilling,  reworking,  production,  transportation,
     marketing  and plugging activities under the leases, and all lender charges
     and  fees.  Advances  under  the  amended  and  restated  revolving  credit
     agreement  bear  interest  at  a rate of the Wall Street Journal Prime Rate
     plus  three  percent  (3%)  per  year.  Each advance of principal under the
     amended  facility is treated as a separate loan and is repayable in six (6)
     interest only installments followed by up to twenty four (24) principal and
     interest  installments based upon a 30-month amortization. The Company will
     be  assessed  a  one quarter of one percent (.25%) standby fee on available
     undrawn  principal  each  quarter. The note matures on April 1, 2008. As of
     December  31,  2005,  the  balance  outstanding  under  the  line of credit
     agreement  was  $3,525,000,  $940,000  of  which  is due in the next twelve
     months, $1,410,000 of which is due in


                                      F-14
<PAGE>
     2007, and $1,175,000 of which is due in 2008.

     The  loan  is  collateralized by a first lien on the particular oil and gas
     leases  acquired  with  the  funds,  but  the Company is entitled to obtain
     partial  releases  if  the ratio of proved developed and proved undeveloped
     reserves  underlying  the collateral base meets certain criteria. According
     to the terms of the agreement, the unused available funds under the line of
     credit  will  only be available for draw by the Company if at all times the
     Company's  proved  developed  reserves  equal or exceed twenty-five percent
     (25%)  of  the  outstanding  principal  and interest indebtedness under the
     agreement  and  if  the principal balance of the note outstanding after the
     requested  draw  is less than the sum of 1) the actual costs of the oil and
     gas  lease  purchased and or funded, and 2) the sum of 75% of the Company's
     proved  developed  reserves  and  50%  of  the Company's proved undeveloped
     reserves from all sources pledged as collateral.

     Because  the  lender obtains its funds from the private capital markets and
     or  individuals  who  desire  to participate in the lenders investment bank
     activities,  the lender does not have a guaranteed source of money in which
     to  fund this transaction with the Company. As a result, the lender has not
     guaranteed that all proposed funding under this agreement will be available
     if and when the Company elects to make draw requests.

     As  consideration  for entering into the agreement, the lender will receive
     an  overriding  royalty  in  each  oil and gas lease acquired with facility
     funds  equal  to  2%  of the Company's acquired net revenue interest in the
     lease.  The  overriding  royalty interests are earned when the lender funds
     have  been  utilized  by the Company for direct and or indirect acquisition
     expenses  or  drilling  expenses.  In addition, the lender received 100,000
     warrants  to  purchase  common stock of the Company at an exercise price of
     $2.00 per share and an expiration date of November 1, 2007.

     Under the terms of the credit facility, the Company is required to offer to
     the  lender  the opportunity to participate in up to a minimum of 33.3% and
     up to 100% based on the sole discretion of the Company.

     The  Company  allocates  the  proceeds  received  from debt with detachable
     warrants  using  the  relative fair value of the individual elements at the
     time  of  issuance. The amount allocated to the warrants as a debt discount
     was  calculated  at  $88,422 and was $79,581 at December 31, 2005. The debt
     discount  is recognized as interest expense over the period until the notes
     mature.  In  the  event  the debt is settled prior to the maturity date, an
     expense  will  be  recognized  based on the difference between the carrying
     amount and the amount of the payment.

7.   INCOME TAXES
     ------------

     Through  December  31,  2005,  the  Company  has  incurred losses since its
     inception  and, therefore, has not been subject to federal income taxes. As
     of  December  31,  2005,  the  Company  had  net  operating  loss  ("NOL")
     carryforwards  for  income  tax purposes of approximately $11,400,000 which
     expire  in  various tax years through 2025. Under the provisions of Section
     382  of the Internal Revenue Code, the ownership change in the Company that
     resulted from the recapitalization of the Company could limit the Company's
     ability to utilize its NOL carryforward to reduce future taxable income and
     related tax liabilities. Additionally, because United States tax laws limit
     the  time  during  which  NOL  carryforwards  may be applied against future
     taxable income, the Company may be unable to take full advantage of its NOL
     for federal income tax purposes should the Company generate taxable income.

     The  composition  of  deferred  tax  assets  and the related tax effects at
     December 31, 2005 and 2004 are as follows:


                                      F-15
<PAGE>
<TABLE>
<CAPTION>
                                                    2005         2004
                                                ------------  ----------
<S>                                             <C>           <C>
       Deferred tax assets:
         Net operating loss carry-forward       $ 3,874,325   $1,327,265
         Allowance for doubtful accounts             42,868            -
         Contribution carryover                       2,346        2,346
                                                ------------------------

           Total deferred tax assets              3,919,539    1,329,611

         Less valuation allowance                (1,628,636)   (647,632)
                                                ------------------------

         Net deferred tax asset                   2,290,903     681,979
                                                ------------------------

       Deferred tax liabilities:
         Book/tax basis difference in oil and
           gas properties                        (2,277,366)   (671,268)
         Book/tax basis difference in property
           and equipment                            (13,537)    (10,711)
                                                ------------------------

           Total deferred tax liability          (2,290,903)   (681,979)
                                                ------------------------

             Net deferred tax                   $         -   $       -
                                                ============  ==========
</TABLE>

     The difference between the income tax benefit in the accompanying statement
     of  operations  and  the  amount  that  would  result  if  the U.S. Federal
     statutory  rate  of  34%  were  applied to pre-tax loss for the years ended
     December  31,  2005  and  2004  is  as  follows:

<TABLE>
<CAPTION>
                                                   2005                2004
                                            AMOUNT       %       AMOUNT       %
                                          ----------  -------  ----------  -------
<S>                                       <C>         <C>      <C>         <C>
       Benefit for income tax at federal  $(986,351)  (34.0)%  $(534,180)  (34.0)%
       statutory rate
       Non-deductible expenses                5,347       0.0    159,654      10.1
       Increase in valuation allowance      981,004      28.0    374,526      23.9
                                          ----------------------------------------
                                          $       -        -%  $       -        -%
                                          ==========  =======  ==========  =======
</TABLE>

8.   RIGHT OF FIRST REFUSAL AGREEMENT
     --------------------------------

     Effective  December 30, 2005, Petrosearch Energy Corporation, joined by six
     of  its  subsidiaries,  entered into an Agreement with Rock Energy Partners
     Operating,  L.P.  and  Rock Energy Partners, L.P. (collectively referred to
     herein  as  "Rock"). The Agreement generally covers the geographic areas of
     current  operations  in  Jefferson County, Mississippi and Colorado County,
     Texas affecting the Company and Rock, including agreements and stipulations
     regarding  future  operations  in  those  geographic areas, the terms under
     which  future  exploration and development participation opportunities will
     be  offered  by  the  Company to Rock, and agreed procedures for conducting
     internal  audits and accounting reconciliations. As part of the transaction
     with  Rock,  the  parties  have  executed an Amended Right of First Refusal
     Agreement  (the  "Amended ROFR") which replaces the previous Right of First
     Refusal  Agreement  between the Company and Rock which was entered in March
     2004 (the "ROFR").

     The  Amended  ROFR  has more limited applicability to the Company's various
     projects  than  the ROFR. While the original agreement required all Company
     prospects  to  be  presented to Rock for consideration by Rock, the Amended
     ROFR  does  not  require  that all Company prospects be offered to Rock for
     participation.  The  Amended  ROFR  also  does not require that the Company
     offer  to  Rock  prospects in any specified area, although the parties have
     separately  stipulated to certain specified areas of mutual interest in the
     Mississippi  and  Colorado County areas based upon historical operations in
     those  areas. The Amended ROFR permits the Company to decide which projects
     will  be  offered  to  Rock, so long as the projects actually presented are
     projects  in  which  the Company owns or intends to retain a minimum of ten
     percent (10%) of the project interest available to the Company.


                                      F-16
<PAGE>
     Under  the  Amended ROFR, Rock's percentage participation is limited to the
     range  between  ten  percent  (10%) minimum participation and forty percent
     (40%)  maximum  participation,  while the ROFR permitted Rock to take up to
     100%  of  a  prospect, if desired. All of the above participation interests
     are fractions of the interest available to the Company.

     The  Amended ROFR also calls for a minimum funding commitment required from
     Rock  equal  to $3,000,000 per year, without the right to carry over to any
     subsequent  year as a credit excess expenditures above the minimum required
     commitment  for  that year. The term of the Amended ROFR will automatically
     renew  from  December  31  of  a given year to December 31 of the following
     year:  1)  if  Rock meets its funding minimum in a calendar year, 2) if the
     funding minimum is not met, but the Company otherwise has failed to offer a
     sufficient  number  of projects to Rock such that theoretical participation
     by  Rock  in one-half of the offered prospects to the extent of twenty five
     percent (25%) would have resulted in Rock achieving the funding minimum; or
     3)  if  more  than  one-half  of  the prospects offered to Rock are offered
     during October, November or December of a calendar year.

     The  Amended ROFR provides that the reversionary interest to be retained by
     the  Company  in  each  prospect  which  is  accepted  by  Rock  shall be a
     twenty-five  percent  (25%) reversionary interest in each interest assigned
     to  Rock,  with the reversion to take effect upon "payout" or recoupment of
     Rock's  development  costs net to that interest. Under the Amended ROFR, if
     the  particular prospect is a drilling project without existing oil and gas
     production,  then payout will be computed on a well-by-well basis. However,
     if  the  prospect  includes existing oil and gas production acquired by the
     parties,  then  payout will be computed on a prospect-wide basis, inclusive
     of  drilling  costs  expended  after acquisition on reworked and new wells.
     Under  the  Amended ROFR, the Company has agreed to reduce its after payout
     reversionary interest in an accepted project in the event the Company gives
     better  after-payout  terms  to a third party in the same prospect, thereby
     providing  Rock  the  same  benefits of the terms offered to any such third
     party.

     The  Company's Jefferson County, Mississippi operations have, to date, been
     conducted  by  the  Company's  operating  subsidiary, Petrosearch Operating
     Company,  L.L.C.  ("POC").  Prior  to this transaction, one hundred percent
     (100%)  of  the  applicable  oil  and  gas  leases on which drilling of the
     Phillips-Burkley  No. 1 well have occurred were assigned to Rock subject to
     a  reversionary  interest  retained  and owned by the Company's subsidiary,
     Buena  Vista  Petrosearch,  L.L.C.  ("BVPS"), which was to take effect when
     Rock recouped 100% of its development costs.

     As  part  of the transaction, the Company may fund all exploration costs of
     the  Phillips-Burkley  No. 1 well going forward pursuant to a new operating
     agreement  between  POC and BVPS. Further, as part of the transaction, Rock
     will  be  assigned  a 50% net revenue interest in the BVPS once the company
     has  recouped  its  investment  in  the  subsidiary.  Rock  will retain its
     ownership of the gas pipeline associated with the project but will grant us
     the  right  to  transport gas through the pipeline at the rate of ten cents
     per  Mcf  through December 31, 2006 and five cents per Mcf thereafter. Rock
     has  executed  a  promissory  note in favor of the Company in the principal
     amount  of  $825,449  to  repay the outstanding acquisition and development
     costs of the project which accrued prior to September 30, 2005. The balance
     of  this  note  has been included in accounts receivable-joint owners as of
     December  31,  2005.  This  note  bears  interest  at the rate of 6% and is
     payable  in four equal monthly installments expected to begin June 1, 2006.
     The  sharing  of  production  proceeds,  if  any,  derived  from  the
     Phillips-Burkley  No.  1  well will be staged. Beginning with the effective
     date  of  the  agreement until the Company recoups from production all sums
     paid  by  the Company toward Phillips-Burkley #1 operations after September
     30,  2005  (the  "Stage  1 Payout"), the Company will retain all of the net
     profits,  if  any,  as a production payment. After the Stage 1 Payout event
     occurs, the Company and Rock shall share equally in the production payment.
     At  such  time  during  this sharing period, the Company and Rock will each
     receive  $3,905,505  (the  "Stage  2  Payout").  Subsequent  to the Stage 2
     Payout,  certain persons vested with a collective 20% reversionary interest
     in BVPS (one of whom is the Company's chief operating officer who owns a 5%
     reversionary  interest) will be entitled to receive their limited liability
     company  interest  which  will  decrease  the  collective  interests of the
     Company  and Rock in BVPS to 80% of profits from leasehold revenues. At the
     point  of  the Stage 2 Payout, Rock's 40% interest as the owner of one-half
     of BVPS shall be


                                      F-17
<PAGE>
     assigned  to  it  by  BVPS,  thereby eliminating Rock's interest in BVPS in
     favor  of  a direct working interest ownership. However, Rock has the right
     to waive this automatic conversion to direct ownership after Stage 2 Payout
     if it desires.

     As  part  of the transaction, if either the Company or Rock acquires an oil
     and gas lease within the area of mutual interest designated by the parties,
     then  the  acquiring party shall offer to the other the right to acquire at
     cost  a  50%  interest  in  the  acquired  oil  and  gas  lease  within the
     Mississippi AMI leases.

     Under  the prior agreements between the parties, one hundred percent (100%)
     of  the  Colorado  County "Garwood" Prospect was assigned by the Company to
     Rock  subject  to  a  reversionary  interest  retained and owned by Pursuit
     Petrosearch,  L.L.C.  ("Pursuit"),  the  Company's subsidiary, which was to
     take  effect  when  Rock  recouped  100%  of  its  development  costs  on a
     well-by-well  basis.  As  in  the case of the Jefferson County, Mississippi
     operations,  the  operator for the "Garwood" Prospect to date has been POC.
     Under  the  terms  of  the  transaction,  the  parties  have  divided  this
     geographic  region  into  three  (3)  parts,  the Garwood North Leases, the
     Garwood  South  Leases  and  the  Garwood  Area of Mutual Interest or "AMI"
     Leases.  As  to the Garwood North area, POC will remain the operator. As to
     the  Garwood  South  and  Garwood  AMI  Leases,  Rock will be the operator.
     However,  Rock  has  engaged POC as a contract operator for a term which is
     yet  to  be  determined  in  order  to  take  advantage  of  POC's existing
     regulatory registrations and bonding status.

     The  ROFR  provided  for  a reversionary interest equal to thirty-three and
     one-third  percent (33.33%) of the interest assigned to Rock which interest
     would  take  effect  upon  Rock  recouping  100%  of  its  acquisition  and
     development  costs. Under the terms of the transaction, the Company's after
     payout reversionary interest has been adjusted to 21.5% as to Garwood South
     Leases  and  will  be  computed  on a the well-by-well basis. The Company's
     after  payout  reversionary  interest  will  remain  33.33% as to the wells
     drilled  on  Garwood  North  Leases,  likewise on a well-by-well basis. For
     purposes  of  calculating  "payout", the parties have stipulated to certain
     existing  balances  outstanding  which  are  owed  by  Rock to the Company,
     subject  to  completion  of  an audit. These sums will be applied as payout
     calculation  deficits in the payout formulae as more fully described in the
     transaction documents.

     Rock  agreed  to  expend net to its interests during calendar year 2006 not
     less  than  $8,000,000  toward development of the Garwood North and Garwood
     South  leases.  The parties contemplate that this commitment will be met by
     Rock's participation in two projects contemplated in 2006, being a new well
     in  the Garwood North area and a recompletion of an existing wellbore known
     as  the  Kallina  #2  well.  The  timing  of  the 2006 projects will not be
     overlapped so that costs may be closely monitored. Rock is not obligated to
     commit  to  operations  exceeding  $8,800,000, should the proposed projects
     exceed $8,000,000 in the aggregate.

     For  five  (5)  years  from the date of the Agreement, the Company and Rock
     have  agreed  that  as to oil and gas leases in the Garwood prospect, which
     one  or the other has acquired prior to consummation of the Agreement which
     are  neither  in  the Garwood North nor Garwood South area, the party which
     has  acquired  the  particular  lease  shall  offer  the other the right to
     acquire  percentage  ownership in the lease, being 80% if the offer is made
     to Rock and 20% if the offer is made to the Company.

9.   COMMITMENTS AND CONTINGENCIES
     -----------------------------

     OPERATING LEASE
     ---------------

     The  Company  rents  office space under long-term office leases that expire
     through  2010.  The  future  minimum  lease  payments  required  under  the
     operating  leases that have initial non-cancelable lease terms in excess of
     one year amount to $493,077 of which $94,196 is to be paid in 2006, $96,234
     is  to  be  paid  in 2007, $99,989 is to be paid in 2008, $101,888 is to be
     paid  in  2009,  and  $100,770 is to be paid in 2010. Rent expense incurred
     under  operating  leases  during the years ended December 31, 2005 and 2004
     was $101,321 and $85,172, respectively.

     LEGAL PROCEEDINGS
     -----------------

     We  are  currently  not  a  party  to  any  material  legal  proceedings.


                                      F-18
<PAGE>
10.  STOCKHOLDERS' EQUITY
     --------------------

     COMMON STOCK
     -------------

     Effective April 23, 2004, the Company amended its articles of incorporation
     to  increase  the  total number of shares of stock that the Company has the
     authority  to issue to 1,020,000,000, consisting of 1,000,000,000 shares of
     common stock, par value $.001 per share, and 20,000,000 shares of preferred
     stock, par value $1.00 per share.

     Upon  the  merger  on December 30, 2004, the Company's authorized shares of
     common  stock  decreased  to 100,000,000 from 1,000,000,000. The authorized
     preferred stock of 20,000,000 remained the same.

     PREFERRED STOCK
     ---------------

     The  Company's  articles  of  incorporation authorize the issuance of up to
     20,000,000 shares of preferred stock with characteristics determined by the
     Company's  board  of  directors. As a result of the recapitalization of the
     Company  in  2003,  effective  November  5, 2003, the Company had 1,000,000
     shares  of  Series  A 8% Convertible Preferred Stock ("Series A Preferred")
     authorized, issued and outstanding as of December 31, 2003. The shares have
     a  par  and  stated  value  of $1.00 per share. If declared by the Board of
     Directors, dividends are to be paid quarterly in cash or in common stock of
     the  Company to the holders of shares of the Series A Preferred. The shares
     of  the  Series A Preferred rank senior to the common stock both in payment
     of  dividends  and  liquidation  preference.  The  Series  A  Preferred  is
     convertible into common stock of the Company at a conversion price of $6.50
     per  share (post-reverse split). Beginning August 19, 2003, the Company had
     the  right  to  redeem  all or part of the shares of Series A Preferred for
     cash  at  a  redemption price equal to $6.50 per share plus all accrued and
     unpaid  dividends on the shares to be redeemed. During 2004, 516,584 shares
     of  Series  A  Preferred  were  converted to 79,474 shares of the Company's
     common  stock. As of December 31, 2005, no dividends have been declared and
     approximately $131,000 of dividends were in arrears related to the Series A
     Preferred if the Company decided to declare dividends.

     As  a  result of the recapitalization of the Company, effective November 5,
     2003,  the  Company  has 100,000 shares authorized and 43,000 shares issued
     and  outstanding  of  Series  B  Convertible  Preferred  Stock  ("Series  B
     Preferred")  as  of  December  31, 2005 and 2004. The shares have a par and
     stated  value of $1.00 per share. The shares of the Series B Preferred rank
     senior  to  the  common  stock  in  liquidation  preference.  The  Series B
     Preferred  is  convertible  into  common stock of the Company at an initial
     conversion  price  of $2.14 per share (post-reverse split) at the option of
     the  holder. Beginning October 1, 2003, the Company had the right to redeem
     all  or  part  of the shares of Series B Preferred for cash at a redemption
     price equal to $6.50 per share.

     As  a  result of the recapitalization of the Company, effective November 5,
     2003,  the  Company  had 100,000 shares authorized and 75,000 shares issued
     and  outstanding  of  Series  C  Convertible  Preferred  Stock  ("Series  C
     Preferred")  as of December 31, 2003. The shares had a par and stated value
     of  $1.00  per share. The shares of the Series C Preferred ranked senior to
     the  common  stock  in  liquidation  preference. The Series C Preferred was
     convertible into common stock of the Company at an initial conversion price
     of  $2.14  per  share  (post-reverse  split)  at  the option of the holder.
     Beginning  December  13,  2003,  the Company had the right to redeem all or
     part  of  the  shares  of Series C Preferred for cash at a redemption price
     equal to the stated value of $1.00 per share. During 2004 all 75,000 shares
     of  Series C Preferred were converted to 34,615 shares (post-reverse split)
     of the Company's common stock.

     As  a  result of the recapitalization of the Company, effective November 5,
     2003,  the  Company  had 600,000 shares authorized and 37,500 shares issued
     and  outstanding  of  Series  D  8%  Convertible Preferred Stock ("Series D
     Preferred")  as of December 31, 2003. The shares had a par and stated value
     of  $1.00  per share. If declared by the Board of Directors, dividends were
     to  be  paid  quarterly  in  cash  or in common stock of the Company to the
     holders  of  shares  of  the Series D Preferred. The shares of the Series D
     Preferred ranked senior to the common stock both in payment of dividends


                                      F-19
<PAGE>
     and  liquidation  preference.  The  Series D Preferred was convertible into
     common  stock  of  the  Company  at  a  conversion price of $1.62 per share
     (post-reverse split) at the option of the holder. Beginning March 10, 2004,
     the  Company  had the right to redeem all or part of the shares of Series D
     Preferred for cash at a redemption price equal to the stated value of $1.00
     per  share  plus  all  accrued  and  unpaid  dividends  on the shares to be
     redeemed.  During  2004  all  37,500  Series  D Preferred were converted to
     23,077 shares (post-reverse split) of the Company's common stock.

     STOCK WARRANTS
     --------------

     The  Company  periodically  issues  incentive stock warrants to executives,
     officers,  directors  and  employees  to  provide  additional incentives to
     promote the success of the Company's business and to enhance the ability to
     attract  and retain the services of qualified persons. The issuance of such
     warrants  are  approved  by the Board of Directors. The exercise price of a
     warrant  granted is determined by the fair market value of the stock on the
     date  of grant. For purposes of determining compensation expense associated
     with  stock  warrants,  the  intrinsic  value  of  the  Company's stock was
     determined based upon the quoted market price of the Company's common stock
     for  executives,  officers  and  directors  and fair value of the Company's
     stock  was determined based upon the Black-Scholes option pricing model for
     non-employees.

     During  2004,  the  Company  granted warrants to purchase 973,082 shares of
     common stock (post-reverse split) at prices ranging from $5.20 per share to
     $9.75 per share. All warrants were granted at an exercise price equal to or
     greater  than  the  fair  market  value  at the date of grant and, thus, no
     compensation  cost  was  recorded.  All  of  these warrants are immediately
     exercisable  except  for 115,384 that vest one year from the date of grant.
     These warrants expire in 2007.

     During  November  2004,  the  Company, prior to its merger with Petrosearch
     Texas,  entered  into  a  two-year  employment agreement with its new chief
     executive  officer  ("CEO")  for  which  the  CEO  was  granted warrants to
     purchase 3,637,738 shares of the Company's common stock at $1.95 per share,
     which  was  the  fair market value of the common stock at the date of grant
     and,  thus,  no  compensation  cost  was recorded. The warrants expire four
     years from the date of grant.

     During  2004,  the  Company  granted  warrants to purchase 76,923 shares of
     common stock at a price range of $5.20 to $9.75 per share to certain of its
     advisory  board  members.  These  warrants were exercisable immediately and
     expire  three  years from the date of grant. Using the Black Scholes Option
     Pricing  Model,  the  issuance  of  the  warrants  resulted  in $279,879 of
     additional  compensation  expense included in the accompanying statement of
     operations  for the year ended December 31, 2004. The Company no longer has
     an advisory board.

     During  2005,  the Company granted warrants to purchase 1,215,000 shares of
     common  stock  of  the  Company  to  board  of  directors and employees for
     services  performed  during  2005.  The warrants expire in 2008 and have an
     exercise price of $1.95, which exceeded the fair market value of the common
     stock at the date of grant and, thus, no compensation cost was recorded.

     In September, 2005, the Company granted warrants to purchase 100,000 shares
     of  common  stock  of  the  Company  with an exercise price of $2.00 and an
     expiration date in 2007 to a lender for financing costs associated with the
     Company's  amended  credit  facility  with  the  lender (Note 6). The value
     allocated to the warrants as a debt discount was $88,422.

     During December, 2005, the Company extended the expiration date of warrants
     held by an officer of the Company to purchase 92,308 shares of common stock
     of  the  Company  at  an  exercise price of $0.98 per share from August 28,
     2006, to November 15, 2008.

     During  2005,  the Company cancelled warrants to purchase 153,847 shares of
     common  stock  of the Company valued at $88,392 to reduce a note receivable
     from a former officer of the Company.

     Until the Company's adoption of the provisions of SFAS 123(R) on January 1,
     2006  (See  Note  1),  the  Company elected to follow Accounting Principles
     Board  Opinion  No. 25, "Accounting for Stock Issued to Employees" (APB 25)
     and related Interpretations in accounting for its employee stock


                                      F-20
<PAGE>
     warrants because, as discussed below, the alternative fair value accounting
     provided  for  under  FASB  Statement  No. 123, "Accounting for Stock-Based
     Compensation",  requires  use  of  option  valuation  models  that were not
     developed for use in valuing employee stock options/warrants. Under APB 25,
     if  the  exercise  price of the Company's employee stock options is greater
     than  or  equal  to the market price of the underlying stock on the date of
     grant, no compensation expense is recognized.

     Proforma  information  regarding  net income (loss) and earnings (loss) per
     share  is required by Statements 123 and 148, and has been determined as if
     the  Company  had  accounted for its employee stock warrants under the fair
     value  method  of  these  Statements. For warrants granted during the years
     ended  December  31,  2005  and  2004, the fair value for such warrants was
     estimated  at  the date of grant using a Black-Scholes option-pricing model
     with the following assumptions:

<TABLE>
<CAPTION>
                               2005        2004
                            ----------  ----------
<S>                         <C>         <C>
       Dividend yield             -0-         -0-

       Expected volatility         70%        135%

       Risk free interest        3.00%       2.25%

       Expected lives       2-4 years   3-4 years
</TABLE>

     The  Black-Scholes  option  valuation  model  was  developed  for  use  in
     estimating  fair  value  of traded options or warrants that have no vesting
     restrictions  and  are  fully  transferable.  In addition, option valuation
     models  require  the  input  of highly subjective assumptions including the
     expected  stock  price  volatility.  Because  the  Company's employee stock
     warrants  have characteristics significantly different from those of traded
     options/warrants,  and  because changes in the subjective input assumptions
     can materially affect the fair value estimate, in management's opinion, the
     existing models do not necessarily provide a reliable single measure of the
     fair value of its employee stock warrants.

     For  purposes  of  proforma  disclosures,  the  estimated fair value of the
     warrants is included in expense over the vesting period or expected life of
     the warrant.

<TABLE>
<CAPTION>
                                                                   2005          2004
                                                               ------------  ------------
<S>                                                            <C>           <C>
     Net loss as reported                                      $(2,901,031)  $(1,571,120)

     Add: Stock-based employee compensation expense                      -             -
     included in reported net loss, net of tax

     Deduct: Stock-based employee compensation expense            (833,855)   (6,619,962)
     determined under the fair value method, net of tax        ------------  ------------

     Proforma net loss                                         $(3,734,886)  $(8,191,082)
                                                               ============  ============

     Basic and diluted net loss per common share, as reported  $     (0.11)  $     (0.09)
                                                               ============  ============

     Proforma basic and diluted net loss per common share      $     (0.15)  $     (0.47)
                                                               ============  ============
</TABLE>

     No  tax  effects  were  included  in the determination of proforma net loss
     because  the  deferred  tax  asset  resulting  from  stock-based  employee
     compensation  would  be  offset  by  an  additional valuation allowance for
     deferred tax assets.

     A  summary of the Company's stock warrant activity (reverse split adjusted)
     and related information


                                      F-21
<PAGE>
     for the years ended December 31, 2005 and 2004 follows:

<TABLE>
<CAPTION>
                                                           WEIGHTED
                                 NUMBER OF                  AVERAGE
                               SHARES UNDER    EXERCISE    EXERCISE
                                  WARRANT        PRICE       PRICE
                               -------------  -----------  ---------
<S>                            <C>            <C>          <C>
       Balance outstanding at
         December 31, 2003        2,761,539   $0.98-$9.75  $    4.62

         Issued                   1,050,000   $4.88-$9.75  $    4.62
         Effect of merger         3,637,738   $      1.95  $    1.95
         Exercised                 (115,385)  $      2.60  $    2.60
                               -------------

       Balance outstanding at
         December 31, 2004        7,333,892   $0.98-$9.75  $    3.77

         Issued                   1,407,308   $0.98-$2.00  $    1.89
         Cancelled                 (246,155)  $      0.98  $    0.98
                               -------------

       Balance outstanding at
         December 31, 2005        8,495,045   $0.98-$9.75  $    3.57
                               =============
</TABLE>

     All  outstanding  stock  warrants  are  exercisable at December 31, 2005. A
     summary of outstanding stock warrants at December 31, 2005 follows:

<TABLE>
<CAPTION>
                                                               WEIGHTED
      NUMBER OF                      REMAINING                  AVERAGE
     COMMON STOCK                    CONTRACTED    EXERCISE    EXERCISE
     EQUIVALENTS   EXPIRATION DATE  LIFE (YEARS)     PRICE       PRICE
     ------------  ---------------  ------------  -----------  ---------
<S>                <C>              <C>           <C>          <C>
          630,769  August 2006               .67        $0.98      $0.98
          692,308  September 2006            .68        $1.63      $1.63
        1,076,923  November 2006             .92        $9.75      $9.75
          211,538  February 2007            1.17        $9.75      $9.75
           30,769  March 2007               1.25        $9.75      $9.75
          300,000  April 2007               1.34        $9.75      $9.75
          161,538  May 2007                 1.42  $6.50-$9.75      $7.27
           76,923  July 2007                1.50  $5.20-$6.50      $6.24
          269,231  September 2007           1.67  $4.88-$5.20      $5.15
          100,000  November 2007            1.92        $2.00      $2.00
          150,000  March 2008               2.25        $1.95      $1.95
           20,000  August 2008              2.62        $1.95      $1.95
        4,775,046  November 2008            2.92        $1.95      $1.93
-----------------
        8,945,045
=================
</TABLE>

11.  RELATED PARTY TRANSACTIONS
     --------------------------

     During  the years ended December 31, 2005 and 2004, the Company was engaged
     in various transactions with related parties as follows:

     During  the  years  ended December 31, 2005 and 2004, a vendor owned by the
     spouse of a director of the Company through December 8, 2005, at which time
     he  resigned  as director, provided drilling services totaling $485,570 and
     $280,457,  respectively.  The  balance  owed  to  this  vendor was $-0- and
     $45,705  at December 31, 2005 and 2004, respectively. The director's spouse
     was also a 15 - 30% working interest owner in the Fort Bend County Prospect
     (Blue  Ridge)  which the Company sold in 2005. Accounts receivable from the
     spouse for joint interest billings was $-0- and $268,973 as of December 31,
     2005 and 2004, respectively.


                                      F-22
<PAGE>
     Mr. Wayne Beninger, who became the Company's Chief Operating Officer on May
     16,  2005, is the owner of Southwest Oil & Gas Management (Southwest) which
     has  provided  engineering  and  geological  consulting  services  for  the
     Company's  projects.  During  the  fiscal year ended December 31, 2004, the
     Company  paid  Southwest approximately $600,000 for such services. When Mr.
     Beninger  became  an  employee of the Company, the agreement with Southwest
     was terminated. From January 1, 2005, until the agreement was terminated on
     May  15,  2005,  the  Company  paid  Southwest  approximately  $365,000 for
     engineering  and geological consulting services. Mr. Beninger has an option
     to  purchase  for  $1.00 a 5% interest (after payout to the Company and its
     drilling  partner)  in  the  Company's  subsidiary that holds the Jefferson
     County, Mississippi project.

     During 2004, the Company's board of directors provided executives an option
     to repay the $149,410 of notes receivable that were outstanding on December
     1,  2004, in cash or a return of shares of common stock at $1.56 per share,
     when the current fair market value of the common stock was $1.95 per share,
     resulting in the executives having to return 20% more shares to the Company
     rather than what would have been returned based on the fair market value of
     the  common stock. The principal of $149,410 and interest balance of $9,366
     were  repaid  by all officers in December 2004 through the return of 95,776
     and  6,004  shares of the Company's common stock, respectively, held by the
     executives.

     As  of  December  1,  2004,  $145,000  was  recorded  in stock subscription
     receivable  from  executives  of  the  Company.  The  stock  subscription
     receivables  of  $100,000  were repaid in 2004 through the return of 64,103
     shares  of  the  Company's  common  stock  under the terms described in the
     previous paragraph. The stock subscription receivable of $45,000 was repaid
     in lieu of compensation in 2004.

     The related party receivable balance from executives increased from $51,900
     at  December  1,  2004,  to  $63,234 in 2004 as a result of advances to two
     officers  of  the  Company.  The total balance was repaid to the Company in
     2004  through  the return and cancellation of 40,480 shares of common stock
     of the Company personally held by the two officers.

12.  EARNINGS PER SHARE
     ------------------

     Following  is  a  reconciliation  of the numerators and denominators of the
     basic  and  diluted  EPS computations for the years ended December 31, 2005
     and  2004:

<TABLE>
<CAPTION>
                                                     2005          2004
                                                 ------------  ------------
<S>                                              <C>           <C>
       Net loss                                  $(2,901,031)  $(1,571,120)
       Less:  Preferred stock dividends              (38,673)      (38,673)
                                                 ------------  ------------

       Net loss available to common
         stockholders (numerator)                $(2,939,704)  $(1,609,793)
                                                 ============  ============

       Weighted average shares of common stock
         (denominator)                            25,409,348    17,576,294
                                                 ============  ============

       Basic and diluted net loss per share      $     (0.12)  $     (0.09)
                                                 ============  ============
</TABLE>

13.  NON-CASH INVESTING AND FINANCING ACTIVITIES
     -------------------------------------------

     During  the  years ended December 31, 2005 and 2004, the Company engaged in
     various non-cash financing and investing activities as follows:


                                      F-23
<PAGE>
<TABLE>
<CAPTION>
                                                                            2005       2004
                                                                         ----------  ---------
<S>                                                                      <C>         <C>
     Transfer of overriding royalty interest for debt issuance costs     $   64,784  $       -
                                                                         ==========  =========

     Reduction of prepaid services for development
       of oil and gas properties                                         $        -  $ 333,765
                                                                         ==========  =========

     Issuance of common stock for acquisition of
       Property                                                          $1,090,000  $  51,920
                                                                         ==========  =========

     Cancellation of common stock for reduction in
       subscription receivable                                           $        -  $ 249,410
                                                                         ==========  =========

     Cancellation of common stock for reduction in
       related party receivable                                          $        -  $  72,600
                                                                         ==========  =========

     Increase in accounts payable and accrued
       liabilities for property costs                                    $  500,000  $ 429,069
                                                                         ==========  =========

     Increase in property costs for asset retirement obligation accrual  $  633,455  $       -
                                                                         ==========  =========

     Issuance of warrants with debt                                      $   88,422  $       -
                                                                         ==========  =========

     Cancellation of warrants for reduction in note receivable           $   88,392  $       -
                                                                         ==========  =========

     Transfer of automobile for reduction in liability                   $   15,346  $       -
                                                                         ==========  =========
</TABLE>

14.  IMPAIRMENT AND SALE OF OIL AND GAS PROPERTIES
     ---------------------------------------------

     At  December  31, 2005 and 2004, the net capitalized costs of crude oil and
     natural  gas  properties  did not exceed the present value of the estimated
     reserves; as such, no write-down was recorded.

15.  BUSINESS SEGMENTS
     -----------------

     The  Company  believes that all of its material operations are conducted in
     the  exploration  and  production  of  oil and gas in the United States and
     currently reports as a single segment.

16.  SUPPLEMENTAL OIL AND GAS INFORMATION - UNAUDITED
     ------------------------------------------------

     The following supplemental information regarding the oil and gas activities
     of  the  Company  is  presented  pursuant  to  the  disclosure requirements
     promulgated  by the Securities and Exchange Commission ("SEC") and SFAS No.
     69, Disclosures About Oil and Gas Producing Activities (`Statement 69").

     ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
     ---------------------------------------------------

     Set  forth below is a summary of the changes in the estimated quantities of
     the  Company's  crude  oil and condensate, and gas reserves for the periods
     indicated,  as estimated by the Company as of December 31, 2005. All of the
     Company's  reserves  are  located within the United States. Proved reserves
     cannot  be  measured  exactly  because  the estimation of reserves involves
     numerous  judgmental determinations. Accordingly, reserve estimates must be
     continually  revised  as a result of new information obtained from drilling
     and  production history, new geological and geophysical data and changes in
     economic conditions.

     Proved reserves are estimated quantities of gas, crude oil, and condensate,
     which  geological  and  engineering  data  demonstrate,  with  reasonable
     certainty,  to  be  recoverable in future years from known reservoirs under
     existing  economic  and operating conditions. Proved developed reserves are
     proved reserves that can be expected to be recovered through existing wells
     with existing equipment and operating methods.


                                      F-24
<PAGE>
<TABLE>
<CAPTION>
                                                      OIL         GAS
                                                   ----------  ----------
     QUANTITY OF OIL AND GAS RESERVES                (BBLS)      (MCF)
     --------------------------------------------  ----------  ----------
<S>                                                <C>         <C>
     Total proved reserves at December 31, 2003      460,654     177,438

     Extensions and discoveries                       25,856   1,158,000
     Production                                     (120,525)    (64,009)
     Revisions to previous estimate                    7,812     (24,392)
                                                   ----------  ----------

       Total proved reserves at December 31, 2004    373,797   1,247,037

     Extensions and discoveries                    2,033,869   1,121,000
     Production                                      (33,676)     (4,725)
     Sale of Assets                                  (64,771)      - 0 -
     Revisions to previous estimate                   36,575    (519,565)

     Total proved reserves at December 31, 2005    2,345,794   1,843,747
                                                   ==========  ==========

     PROVED DEVELOPED RESERVES:

       December 31, 2005                             330,838     229,747
                                                   ==========  ==========

       December 31, 2004                             181,945      94,075
                                                   ==========  ==========
</TABLE>

     CAPITALIZED COSTS OF OIL AND GAS PRODUCING ACTIVITIES
     -----------------------------------------------------

     The  following  table sets forth the aggregate amounts of capitalized costs
     relating  to  the  Company's  oil  and  gas  producing  activities  and the
     aggregate  amount  of  related  accumulated  depletion,  depreciation  and
     amortization as of December 31, 2005 and 2004:

<TABLE>
<CAPTION>
                                                     2005          2004
                                                 ------------  ------------
<S>                                              <C>           <C>
       Unproved oil and gas properties           $ 3,513,597   $ 3,548,812
       Proved oil and gas properties              11,849,520     5,490,447
                                                 ------------  ------------

         Total                                    15,363,117     9,039,259

       Less accumulated depletion, depreciation
         and amortization                         (1,929,727)   (2,152,511)
                                                 ------------  ------------

           Net capitalized costs                 $13,433,390   $ 6,886,748
                                                 ============  ============
</TABLE>

     COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
     --------------------------------------------------

     The  following  table  reflects  the costs incurred in oil and gas property
     acquisition,  exploration and development activities during the years ended
     December 31, 2005 and 2004:

<TABLE>
<CAPTION>
                               2005        2004
                            ----------  ----------
<S>                         <C>         <C>
         Acquisition costs  $4,079,919  $3,298,830
                            ==========  ==========

         Exploration costs  $1,147,816  $2,288,195
                            ==========  ==========

         Development costs  $1,096,124  $1,397,403
                            ==========  ==========
</TABLE>


                                      F-25
<PAGE>
     STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
     --------------------------------------------------------

     The  following table reflects the Standardized Measure of Discounted Future
     Net  Cash  Flows  relating  to the Company's interest in proved oil and gas
     reserves as of December 31, 2005 and 2004:

<TABLE>
<CAPTION>
                                                            2005           2004
                                                        -------------  ------------
<S>                                                     <C>            <C>
       Future cash inflows                              $158,565,979   $23,742,174
       Future development and production costs           (59,263,004)   (6,250,065)
                                                        -------------  ------------

       Future net cash inflows before income taxes        99,302,975    17,492,109
       Future income taxes                               (27,804,833)   (4,961,317)
                                                        -------------  ------------

       Future net cash flows                              71,498,142    12,530,792
       10% discount factor                               (36,654,786)   (2,704,002)
                                                        -------------  ------------

         Standardized measure of discounted future net
           cash inflow                                  $ 34,843,356   $ 9,826,790
                                                        =============  ============
</TABLE>

     STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
     --------------------------------------------------------

     Future  net cash flows at each year end, as reported in the above schedule,
     were determined by summing the estimated annual net cash flows computed by:
     (1)  multiplying  estimated  quantities  of  proved reserves to be produced
     during  each  year  by  current  prices,  and  (2)  deducting  estimated
     expenditures  to  be  incurred  during each year to develop and produce the
     proved reserves (based on current costs).

     Income  taxes  were computed by applying year-end statutory rates to pretax
     net  cash  flows,  reduced by the tax basis of the properties and available
     net  operating  loss  carryforwards.  The annual future net cash flows were
     discounted,  using  a  prescribed  10%  rate,  and  summed to determine the
     standardized measure of discounted future net cash flow.

     The  Company  cautions  readers  that  the standardized measure information
     which  places  a  value on proved reserves is not indicative of either fair
     market  value  or  present  value  of  future  cash  flows.  Other  logical
     assumptions  could  have  been used for this computation which would likely
     have  resulted  in  significantly  different  amounts.  Such information is
     disclosed  solely  in  accordance  with  Statement  69 and the requirements
     promulgated  by  the  SEC  to provide readers with a common base for use in
     preparing  their  own  estimates  of  future  cash  flows and for comparing
     reserves  among companies. Management of the Company does not rely on these
     computations when making investment and operating decisions.

17.  SUBSEQUENT EVENTS
     -----------------

     CAPITAL RAISE

     On  February  8,  2006,  Petrosearch Energy Corporation completed a private
     placement  of  equity  securities  solely to accredited investors for total
     proceeds  of  $2,700,000  (the  "Offering").  Pursuant to the Offering, the
     Company issued 1,928,572 shares of the Company's common stock at a price of
     $1.40  per  share and 964,286 three year warrants to purchase shares of the
     Company's  common  stock  with  an exercise price of $2.00 per share to the
     accredited  investors. On February 3, 2006, the Company engaged a placement
     agent  to  handle  the Offering. At the time of closing, the Company paid a
     placement fee of 5% of the gross proceeds of the Offering. Additionally, at
     the  time  of  closing,  the  placement  agent  received 96,429 warrants to
     purchase  shares of the Company's common stock equal to 5% of the number of
     shares of common stock issued to the


                                      F-26
<PAGE>
     accredited  investors  at the time of closing of the Offering. The warrants
     issued  to  the placement agent are exercisable for three years and have an
     exercise  price  of  $2.00  per  share.  The shares of common stock and the
     shares  of common stock underlying the warrants have piggyback registration
     rights. The Company intends to use the proceeds of the Offering for working
     capital and general corporate purposes.

     BARNETT SHALE AGREEMENT

     On  March  30,  2006,  we  entered  into  an  Extension  Agreement  with
     ExxonMobil  Corporation,  Harding Company ("Harding"), Eagle Oil & Gas Co.,
     PS  Gas  Partners, LLC, and Gas Partners, L.P. (the "Extension Agreement"),
     under  which  the  parties  have  agreed  to  extend  until  May  2,  2006,
     ExxonMobil's  preferential  purchase  rights  related  to the separate sale
     agreements  between  Harding Company and each of the other parties relating
     to the Barnett Shale project, including our February 6, 2006, First Amended
     and Restated Program Agreement with Harding Company (the "First Amended and
     Restated Program Agreement") previously announced in our Form 8-K filing on
     February  6,  2006.

     The  First  Amended  and  Restated  Program  Agreement  followed a June 29,
     2005  Lease  Acquisition  and  Development  Agreement  between  ExxonMobil
     Corporation and Harding Company and a Memorandum of Understanding Regarding
     Gas  Evacuation  from  ExxonMobil  and  Harding  Barnett  Shale E&P Venture
     covering  the  project  (the  "ExxonMobil/Harding  Agreements").  Under the
     ExxonMobil/Harding  Agreements, Harding is responsible to serve as operator
     for a significant portion of the area of mutual interest and to acquire and
     develop  the  leases  in  the  area  of  mutual  interest.  ExxonMobil  is
     responsible  for  the  operation  and  construction  of  the  gathering and
     evacuation  system  associated  with  the  area of mutual interest and will
     serve  as  operator  for  the  balance  of  the  area  of  mutual interest.

     At  the  time  of  the  execution of the First Amended and Restated Program
     Agreement,  Harding  had not obtained from ExxonMobil a consent to transfer
     and  a  waiver  of Exxon/Mobil's a preferential purchase right set forth in
     the  ExxonMobil/Harding  agreement.  At  the  time  of our execution of and
     initial  funding under the First Amended and Restated Program Agreement, we
     did not have a direct contractual relationship with ExxonMobil. We believed
     that  all  conditions  necessary  to assign and convey the working interest
     from  Harding had been met. We subsequently learned that ExxonMobil had not
     waived  the  contingencies  and that ExxonMobil desired to explore possible
     alternative  ownership structures beneficial to all concerned before making
     a  determination  with  respect  to  the  preferential  right  to purchase.

     The  purpose  of  the  Extension  Agreement  is  to  give  all  the parties
     involved  the  ability  to explore possible alternative structures with the
     goal  to  form  an integrated venture which would include both upstream and
     pipeline  assets  and  activities,  which  would  better align each party's
     interest, and which would enhance the ability of the venture to assure that
     adequate  pipeline  capacity  would  be  available  to  move natural gas to
     market.  The  opportunity  to  participate  in  an integrated venture which
     includes  the  gathering and evacuation system was not present in the First
     Amended and Restated Program Agreement. The potential alternative structure
     has potential positive features. The Extension Agreement likewise preserves
     to  the  parties  all of their respective rights and claims as they existed
     prior  to  the  execution  of  the  Extension  Agreement.

     In  the  event  that  the  parties  cannot  achieve  a  mutually  agreed
     alternative  structure  on or before May 2, 2006, ExxonMobil could exercise
     its  preferential  purchase  right  which,  if exercised, would prevent our
     participation  in  the  project.  In  the  event  of  such  a  loss of this
     opportunity  to  participate  in  the  project,  our  legal  rights are not
     prejudiced  by  the  Extension Agreement and we would then expect to pursue
     all  potential  remedies  available  to  us  relating  to  the  factual
     circumstances  surrounding  these  agreements.




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