UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington,
D.C. 20549







Form 10-K





R
            ANNUAL
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
      OF 1934For
      the fiscal year ended December 31, 2008OR£
            TRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
      OF 1934





Commission
File No. 001-33777









South
Texas Oil Company


(Exact
Name of Registrant as Specified in Its Charter)





Nevada
            74-2949620(State
      or other jurisdiction of
              incorporation
      or organization)
            (I.R.S.
      Employer
              Identification
      Number)





300
East Sonterra Boulevard, Suite 1220


San
Antonio, Texas 78258


(Address
of principal executive offices, including zip code)


(210) 545-5994


(Registrant’s
telephone number, including area code)





Securities
registered pursuant to Section 12(b) of the Act: None





Securities
registered pursuant to Section 12(g) of the Act:





Title
      of each class
                    
                    Name
      of each exchange
                      on
      which registeredCommon
      Stock, par value $0.001 per share
                    
                    The
      NASDAQ Global
Market





Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.  Yes £     No R





Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Exchange
Act.  Yes £     No R





Indicate
by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.  Yes R     No £





Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the
best of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.  £





Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a small reporting company. See
definitions of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act. (Check
one):


Large accelerated filer £
                    Accelerated filer £Non-accelerated filer £
                    Smaller reporting company  R(Do not check if a smaller reporting company)




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





The
aggregate market value of the voting stock held by non-affiliates of the
registrant based on the closing price of the Registrant’s common stock of $3.69
per share as reported on the NASDAQ Global Stock Market on June 30, 2008 was
$33,505,886.





As of
March 17, 2009, there were outstanding 16,788,862 shares of common
stock.





Documents
Incorporated by Reference





Information
required by Part III will either be included in the registrant’s definitive
proxy statement filed with the Securities and Exchange Commission or filed as an
amendment to this Form 10-K no later than 120 days after the end of the
registrant’s fiscal year, to the extent required by the Securities Exchange Act
of 1934, as amended.









TABLE
OF CONTENTS




PART
      I
                                                              
                                                              1ITEM
      1.
                                                              BUSINESS
                                                              1ITEM
      1A.
                                                              RISK
      FACTORS
                                                              17ITEM
      1B.
                                                              UNRESOLVED
      STAFF COMMENTS
                                                              29ITEM
      2.
                                                              PROPERTIES
                                                              29ITEM
      3.
                                                              LEGAL
      PROCEEDINGS
                                                              29ITEM
      4.
                                                              SUBMISSION
      OF MATTERS TO A VOTE OF SECURITY HOLDERS
                                                              30PART
      II
                                                              
                                                              30ITEM
      5.
                                                              MARKET
      FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
      PURCHASES OF EQUITY
                                                              30ITEM
      6.
                                                              SELECTED
      FINANCIAL DATA
                                                              33ITEM
      7.
                                                              MANAGEMENT
      DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
      OPERATIONS
                                                              33ITEM
      7A.
                                                              QUANTITATIVE
      AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
                                                              43ITEM
      8.
                                                              FINANCIAL
      STATEMENTS AND SUPPLEMETARY DATA
                                                              43ITEM
      9.
                                                              CHANGES
      IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
      DISCLOSURE
                                                              43ITEM
      9A(T).
                                                              CONTROLS
      AND PROCEDURES
                                                              43ITEM
      9B.
                                                              OTHER
      INFORMATION
                                                              45PART
      III
                                                              
                                                              45ITEM
      10.
                                                              DIRECTORS,
      EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
                                                              45ITEM
      11.
                                                              EXECUTIVE
      COMPENSATION
                                                              45ITEM
      12.
                                                              SECURITY
      OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
      STOCKHOLDER MATTERS
                                                              45ITEM
      13.
                                                              CERTAIN
      RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
      INDEPENDENCE
                                                              45ITEM
      14.
                                                              PRINCIPAL
      ACCOUNTANT FEES AND SERVICES
                                                              45PART
      IV
                                                              
                                                              46ITEM
      15.
                                                              EXHIBITS
      AND FINANCIAL STATEMENT SCHEDULES
                                                              46SIGNATURESCERTIFICATIONS










GLOSSARY
OF TERMS





As
commonly used in the oil and natural gas industry and as used in this Annual
Report on Form 10-K, the following terms and abbreviations have the following
meanings:





2-D seismic or
2-D data.  Seismic data that is acquired and processed to yield
a two-dimensional cross section of the subsurface.




3-D seismic or
3-D data.  The method by which a three dimensional image of the
earth’s subsurface is created through the interpretation of reflection seismic
data collected over a surface grid.  3-D seismic surveys allow for a
more detailed understanding of the subsurface than do conventional surveys and
contribute significantly to field appraisal, exploitation and
production.




Annulus.  The
space around a pipe in a wellbore.




Anomaly.  An
entity or property that differs from what is typical or expected, or which
differs from that predicted by a theoretical model.  It may be the
measurement of the difference between an observed or measured value and the
expected values of a physical property.




Bbl.One stock tank barrel
or 42 United States gallons liquid volume.




Bcf.One billion cubic
feet




Bcfe.One billion cubic feet
equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of
oil, condensate or natural gas liquids.




Boe.  Barrel
of oil equivalent.  Boe is calculated by converting 6 Mcf of natural
gas to 1 Bbl of oil.




Boe/d.  Boe
per day.




Bopd.Barrels of oil
per day.




Behind pipe
reserves.  Behind-pipe reserves are expected to be recovered
from zones in existing wells, which will require additional completion work or
future recompletion prior to the start of production.




Bore
hole.  The wellbore itself, including the openhole or uncased
portion of the well.  Bore hole may refer to the inside diameter of
the wellbore wall, the rock face that bounds the drilled hole.




Btu.  One
British thermal unit, which is the heat required to raise the temperature of a
one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.




Butane.  A
gaseous hydrocarbon of the paraffin series.




CO2or carbon
dioxide.  A gas that can be found in naturally occurring
reservoirs, typically associated with ancient volcanoes, and also is a major
byproduct from manufacturing and power production, also utilized in enhanced oil
recovery through injection into an oil reservoir.




Commercial well;
commercially productive well.  An oil and natural gas well
which produces oil and natural gas in sufficient quantities such that proceeds
from the sale of such production exceed production expenses and
taxes.




Completion.  The
installation of permanent equipment for the production of oil or natural gas or,
in the case of a dry hole, the reporting of abandonment to the appropriate
agency.




Compression.  A
force that tends to shorten or squeeze, decreasing volume or increasing
pressure.




Condensate.  Hydrocarbons
associated with natural gas which are liquid under surface conditions but
gaseous in a reservoir before extraction.




i




Darcy.  A unit of
permeability, equivalent to the passage of 1 cubic centimeter of fluid of 1
centipoise viscosity flowing in 1 second under a pressure of 1 atmosphere
through a porous medium having a cross-sectional area of 1 square centimeter and
a length of 1 centimeter.




Delay
rental.  A payment made to the lessor under a non-producing oil
and natural gas lease at the end of each year to continue the lease in force for
another year during its primary term.




Depletion.  The
reduction in petroleum reserves due to production.




Development
activities.  Activities following exploration including the
installation of facilities and the drilling and completion of wells for
production purposes.




Developed
Acreage.  The number of acres which are allocated or assignable
to producing wells or wells capable of production.




Developed
acres.  Acres spaced or assigned to productive
wells.




Development
costs.  All costs incurred in bringing a field to commercial
production.




Development
well.  A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.




Division
order.  A contract setting forth the interest of each owner of
a natural gas or oil property, which serves as the basis on which the purchasing
company pays each owner’s respective share of the proceeds from the natural gas
or oil purchased.




Down-hole
equipment.  Equipment physically located in a
wellbore.




Down-hole lift
methods.  Use of different equipment to aid in the production
of a well whose own reservoir energy is not sufficient to economically produce
the well.




Downspacing
wells.  Additional wells drilled between known producing wells
to better exploit the reservoir.




Dry
holeordry
well.  A well found to be incapable of producing hydrocarbons
in sufficient quantities such that proceeds from the sale of such production
would exceed production expenses and taxes.




EOR.  Enhanced
oil recovery projects involve injection of heat, miscible or immiscible gas, or
chemicals into oil reservoirs, typically following full primary or secondary
water flood recovery efforts, in order to gain incremental recovery of oil from
the reservoir.




Ethane.  A
colorless, gaseous compound of the paraffin series contained in the gases given
off by petroleum and in illuminating gas.




Exploitation.  The
continuing development of a known producing formation in a previously discovered
field.  To maximize the ultimate recovery of oil or natural gas from
the field by development wells, secondary recovery equipment or other suitable
processes and technology.




Exploration.  The
initial phase in petroleum operations that includes generation of a prospect or
play or both, and drilling of an exploration well.




Exploratory
well.  A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.




Extensions and
discoveries.As to any period, the
increases to proved reserves from all sources other than the acquisition of
proved properties or revisions of previous estimates




Farmin.  An
agreement which allows a party to earn a full or partial working interest (also
known as an “earned working interest”) in an oil and natural gas lease in return
for providing exploration funds.




ii




Farmout.  Sale
or transfer of all or part of the operating rights from the working interest
owner (the assignor or farmout party), to an assignee (the farmin party) who
assumes all or some of the burden of development, in return for an interest in
the property.  The assignor may retain an overriding royalty or any
other type of interest.  For Federal tax purposes, a farmout may be
structured as a sale or lease, depending on the specific rights and carved out
interests retained by the assignor.




Federal
unit.  Acreage under Federal oil and natural gas leases subject
to an agreement or plan among owners of the leasehold interests, which satisfies
certain minimum arrangements and has been approved by an authorized
representative of the U.S. Secretary of the Interior, to consolidate under a
cooperative unit plan or agreement for the development of such acreage
comprising a common oil and natural gas pool, field or like area, without regard
to separate leasehold ownership of each participant and providing for the
sharing of costs and benefits on a basis as defined in such agreement or plan
under the supervision of a designated operator.




Fee
land.  The most extensive interest that can be owned in land,
including surface and mineral, including oil and natural gas,
rights.




Field.  An
area consisting of a single reservoir or multiple reservoirs all grouped on or
related to the same individual geological structural feature and/or
stratigraphic condition.




Finding
costs.  The ratio of capital costs necessary to establish
production, divided by the reserves discovered usually reported in $/boe or
$/mcfe.




Flow
lines.  The pipe through which oil or natural gas travels from
well processing equipment to storage or sales.




Formation or
interval.  The fundamental unit of
lithostratigraphy.  A body of rock that is sufficiently distinctive
and continuous that it can be mapped.  In stratigraphy, a formation is
a body of strata of predominately one type of combination of types.  A
group of rocks of the same age extending over a substantial area of a
basin.




Frac or
fracture.  High pressure or explosive methods of breaking rock
formations to facilitate production of oil or natural gas.




Gas or natural
gas.  A highly compressible, highly expansible mixture of
hydrocarbons with a low specific gravity and occurring naturally in a gaseous
form but which may contain liquids.




Gas
lift.  The process of raising or lifting fluid from a well by
injecting gas down the well through tubing or through the tubing casing
annulus.  Injected gas aerates the fluid resulting in less pressure
that the formation, the resulting higher formation pressure forces the fluid out
of the wellbore.  Gas may be injected continuously or intermittently,
depending on the producing characteristics of the well and the arrangement of
the gas-lift equipment.




Gathering
system.  The flowline network and process facilities that
transport and control the flow of oil and natural gas from the wells to a main
storage facility, processing plant or shipping point.  A gathering
system includes pumps, headers, separators, emulsion treaters, tanks,
regulators, compressors, dehydrators, values and associated
equipment.




Geophysical
work.  The use of seismic surveys and the interpretation of
these surveys to better estimate the subsurface environment.




Gross
acresorgross
wells.  The total acres or wells, as the case may be, in which
a working interest is owned.




Held by
production or HBP.  A provision in an oil, gas and mineral
lease that perpetuates a company’s right to operate a property or concession as
long as the property or concession produced a minimum paying quantity of oil or
natural gas.




Horizontal
drilling.  Involves drilling horizontally out from an existing
vertical well bore, thereby potentially increasing the area and reach of the
well bore that is in contact with the reservoir.




Horizontal
wells.  Wells which are drilled at angles greater than 70
degrees from vertical.




iii




Hydraulic
fracturing.  Involves pumping a fluid with or without
particulates into a formation t high pressure, thereby creating fractures in the
rock and leaving the particulates in the fractures to ensure that the fractures
remain open, thereby potentially increasing the ability of the reservoir to
produce oil and natural gas.




Hydrocarbons.  Oil,
natural gas, condensate and other petroleum products.




Hydrostatic
pressure.  The force exerted by a body of fluid at
rest.  It increases directly with the density and the depth of the
fluid and is expressed in many different units, including pounds per square inch
or kilopascals.




Injection
well.  A well in which fluids are injected rather than
produced, the primary objective typically being to maintain reservoir
pressure.  Two common types of injection are gas and
water.  Separated gas from production wells or possibly imported gas
or carbon dioxide may be injected into the upper gas section of the
reservoir.  Water-injection wells are common, where filtered and
treated water is injected to increase production of the reservoir.




Infill
drilling.  Drilling of a
well between known producing wells to better exploit the reservoir.




Initial
production rate.  Generally, the maximum 24 hour production
volume from a well.




LOE.  Lease operating
expense(s), a current period expense incurred to operate a well.




Landowner
royalty.  That interest retained by the holder of a mineral
interest upon the execution of an oil and natural gas lease which typically
ranges from 1/8 to 1⁄4 of all gross revenues from oil and natural gas production,
depending upon the area of the lease, unencumbered with any expenses of
operation, development, or maintenance.




Leases.  Means
full or partial interests in oil and natural gas properties authorizing the
owner of the lease to drill for, purchase and sell oil and natural gas in
exchange for any or all rental, bonus and royalty payments.  Leases
are generally acquired from private landowners (fee leases) and from federal and
state governments on acreage held by them.




Lithostratigrathy.  The
study and correlation of strata to elucidate earth history on the basis of its
lithology, or the nature of the well log response, mineral content, grain, size,
texture and color of rocks.




Low pressure
gathering system.  Small diameter pipelines interconnected in
order to combine natural gas from producing wells which generally have pressures
from 0 to 500 psa.




MBbl.  One
thousand barrels of oil or other liquid hydrocarbons.




MBbl/d.MBbl per
day.




MBoe.  One
thousand barrels of oil equivalent




MBoe/d.  MBoe
per day.




MMBoe.  One
million barrels of oil equivalent.




Mcf.  One
thousand cubic feet.




Mcfe.  One
thousand cubic feet equivalent, determined using the ratio of six Mcf of natural
gas to one Bbl of oil, condensate or natural gas liquids.




MMBbl.  One
million barrels of oil or other liquid hydrocarbons.




MMBtu.  One
million British thermal units.




MMcf.  One
million cubic feet.




MMcf/d.MMcf per
day.




iv




MMcfe.  One
million cubic feet equivalent, determined using a ratio of six Mcf of natural
gas to one Bbl of oil, condensate or natural gas liquids.




MMcfe/d.MMcfe per
day.




Millidarcyormd.  A unit of fluid
permeability equal to one-thousandth of a darcy.




Methane.  Means
a colorless, odorless, flammable gas, CH4, the first member of the methane
series.




Multiple stacked
reservoirs.  Productive formation at different depths in a well
or a field.  As used in explanation, may be referred to as “multiple
stacked objectives.”  Can occur over a few feet or hundreds of feet in
thickness.




NGLs.  Natural
gas liquids, which are the hydrocarbon liquids contained within natural
gas.




NYMEX.  New
York Mercantile Exchange.




Net
acresornet
wells.  The sum of the fractional working interests owned in
gross acres or gross wells, as the case may be.




Net revenue
interest.  A share of production after all burdens, such as
royalty and overriding royalty, have been deducted from the working
interest.  It is the percentage of production that each party actually
receives.




Nonconventional
gas.Non-conventional gas is
a natural gas found in unusual underground situations such as very impermeable
reservoirs, hydrates, and coal deposits.




Nonproducing
reserves.Reserves
subcategorized as non-producing include shut-in and behind-pipe reserves.
Shut-in reserves are expected to be recovered from (1) completion intervals
which are open at the time of the estimate, but which have not started
producing, (2) wells which were shut-in for market conditions or pipeline
connections, or (3) wells not capable of production for mechanical reasons.
Behind-pipe reserves are expected to be recovered from zones in existing wells,
which will require additional completion work or future recompletion prior to
the start of production.




Oil.  Crude
oil or condensate.




Operator.  An
oil and natural gas venture participant that manages the joint venture, pays
venture costs and bills the venture’s non-operators for their share of venture
costs.  The operator is also responsible to market all oil and natural
gas production, except for those non-operators who take their participation
in-kind.




Overriding
royalty.  A royalty interest that is created out of the
operating or working interest.  Unlike a royalty interest, an
overriding royalty interest terminates with the operating interest from which it
was created or carved out of.  See “royalty interest”.




Over-pressurized.  Subsurface
pressure that is abnormally high, exceeding hydrostatic pressure at a given
depth.




Paid-up
lease.  A lease for which the aggregate lease payments are paid
in full on or prior to the commencement of the lease term.




Payout.  The
point in time when the cumulative total of gross income from the production of
oil and natural gas from a given well, and any proceeds from the sale of such
well, equals the cumulative total costs and expenses of acquiring, drilling,
completing, and operating such well, including tangible and intangible drilling
and completion costs.




P-waves.  An
elastic body wave or sound wave in which particles oscillate in the direction
the wave propagates.




Perforate.  To
pierce the casing wall and cement of a wellbore to provide holes through which
formation fluids may enter or to provide holes in the casing so that materials
may be introduced into the annulus between the casing and the wall of the
borehole.




Permeability.  The
measure of ease with which petroleum can move through a reservoir.




v




Play.  A
term applied to a portion of the exploration and production cycle following the
identification by geologists and geophysicists of areas with potential oil and
natural gas reserves.




Porosity.  The
relative volume of the pore space (or open area) compared to the total bulk
volume of the reservoir.




Present value of
estimated future net revenues or PV-10 value.  When used with
respect to oil and natural gas reserves, the estimated future gross revenues to
be generated from the production of proved reserves, net of estimated production
and future development costs, using the prices provided in this report and costs
in effect as of the date indicated, without giving effect to non-property
related expenses such as general and administrative expense, debt service and
future income tax expenses or to depreciation, depletion and amortization,
discounted using an annual discount rate of 10% and assuming continuation of
existing economic conditions, and is not necessarily the same as market
value.




Primary
recovery.  The first stage of oil production in which natural
reservoir drives are used to recover oil, although some form of artificial lift
may be required to exploit declining reservoir drives.




Productive
well.  A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceeds production expenses and taxes.




Propane.  A
gaseous hydrocarbon of the paraffin series.




Prospect.  Potential
hydrocarbon trap which has been confirmed by geological and geophysical studies
to the degree that drilling of an exploration well is warranted.




Proved developed
nonproducing reserves or PDNPs.Proved reserves that
have been developed and no material amount of capital expenditures are required
to bring on production, but production has not yet been initiated due to timing,
markets, or lack of third party completed connection to a natural gas sales
pipeline.




Proved developed
reserves or PDPs.  Reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.  Additional oil and natural gas expected to be obtained
through the application of fluid injection or other improved recovery techniques
for supplementing the natural forces and mechanisms of primary recovery are
included in “proved developed reserves” only after testing by a pilot project or
after the operation of an installed program has confirmed through production
response that increased recovery will be achieved.




Proved
reserves.  Proved oil and natural gas reserves are the
estimated quantities of oil, natural gas and natural gas liquids which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions, i.e., prices and costs as of the date the estimate is
made.  Prices include consideration of changes in existing prices
provided only by contractual arrangements, but not on escalations based on
future conditions.




Proved
undeveloped drilling location.  A site on which a development
well can be drilled consistent with spacing rules for purposes of recovering
proved undeveloped reserves.




Proved
undeveloped reservesorPUDs.Reserves that are
expected to be recovered from new wells on undrilled acreage or from existing
wells where a relatively major expenditure is required for
recompletion.  Reserves on undrilled acreage are limited to those
drilling units offsetting productive units that are reasonably certain of
production when drilled.  Proved reserves for other undrilled units
are claimed only where it can be demonstrated with certainty that there is
continuity of production from the existing productive
formation.  Estimates for proved undeveloped reserves are not
attributed to any acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques have been
proved effective by actual tests in the area and in the same
reservoir.




PSI.  Pounds per square
inch, a measure of pressure.  Pressure is typically measured as
“psig”, or the pressure in excess of standard atmospheric pressure.




Recompletion.  The
completion for production of an existing wellbore in another formation from that
which the well has been previously completed.




Reprocessing.  Refers
to taking older seismic data and performing new mathematical techniques to
refine subsurface images or to provide additional ways of interpreting the
subsurface environment.




vi




Reserve
life.  A ratio determined by dividing our estimated existing
reserves determined as of the stated measurement date by production from such
reserves for the prior twelve month period.




Reservoir.  A
porous and permeable underground formation containing a natural accumulation of
economically productive oil and/or natural gas that is confined by impermeable
rock or water barriers and is individual and separate from other
reserves.




Rod
pump.  Used in connection with a pumping unit in order to aid
in the production of a well.  The rod pump moves up and down with the
pumping unit and helps lift fluids from the wellbore.




Royalty.  The
share paid to the owner of mineral rights, expressed as a percentage of gross
income from oil and natural gas produced and sold unemumbered by expenses
relating to the drilling, completing and operating of the affected
well.




Royalty
interest.  An interest that entitles the owner of such interest
to a share of the mineral production from a property or to a share of the
proceeds there from.  It does not contain the rights and obligations
of operating the property and normally does not bear any of the costs of
exploration, development and operation of the property.




S-wave.  An
elastic body wave in which particles oscillate perpendicular to the direction in
which the wave propagates.




Salt water
disposal wells.  A well used for the purpose of injecting
produced water back into the ground.




Sand.  An
abrasive material composed of small quartz grains formed from the disintegration
of pre-existing rocks.




Secondary
recovery.  The use of water-flooding or gas injection to
maintain formation pressure during primary production and to reduce the rate of
decline of the original reservoir drive.  Water flooding of a depleted
reservoir.  The first improved recovery method of any type applied to
a reservoir to produce oil not recoverable by primary recovery
methods.




Shale.  Fine-grained
sedimentary rock composed mostly of consolidated clay or mud.  Shale
is the most frequently occurring sedimentary rock.




Shut-in
well.  A well that is not on production, but has not yet been
plugged and abandoned.  Wells may be shut-in in anticipation of future
utility as a producing well, plugging and abandonment or other use.




Side track
drilling.  An operation where a new well bore is drilled from
an existing well bore.




Slick water
fracture stimulation.  The use of water to treat the well in
order to improve rate and reserves.  Fluids are pumped into the
wellbore at high pressure and rate causing a fracture to open in the rock and
extending away from the wellbore.




Spud.  The
initial penetration of the ground or seafloor when drilling a well; the start of
the drilling operation.




Standardized
measure of discounted future net cash flows or the Standardized
Measure.  The present value of estimated future net revenues to
be generated from the production of proved reserves, determined in accordance
with the rules and regulations of the Securities and Exchange Commission (using
prices and costs in effect as of the date of estimation) without giving effect
to non-property related expenses such as general and administrative expenses,
debt service, future income tax expenses or depreciation, depletion and
amortization; discounted using an annual discount rate of 10%.




Stock tank
barrel.  42 U.S. gallons liquid volume.




Stratigraphic.  Refers
to a zone or strata and is typically used in terms of how the hydrocarbon is
trapped in the reservoir.  A stratigraphic trap is where the rock type
changes due to some geological event, such as thinning of the zone, and allows
for the hydrocarbons to remain in place.




Stratigraphy.  The
study of the history, composition, relative ages and distribution of strata, and
the interpretation of strata to elucidate earth history.




Successful
well.  A well capable of producing oil and/or natural gas in
commercial quantities.




vii




Test
well.  An exploration well.




Tcf.  One
trillion cubic feet of natural gas




Tcfe.  One
trillion cubic feet equivalent, determined using the ratio of six Mcf of natural
gas to one Bbl of oil, condensate or natural gas liquids.




Trap.  Geological
structure in which hydrocarbons aggregate to form an oil or natural gas
field.




Tubing.  A
relatively small-diameter pipe that is run into a well bore to serve as a
conduit for the passage of oil and natural gas to the surface.




Undeveloped
acreage.  Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.




Unproved
resources.  Resources that are considered less certain to be
recovered than proved reserves.  Unproved resources may be further
sub-classified to denote progressively increasing uncertainty of
recoverability.




Waterflood.  A
method of secondary recovery in which water is injected into the reservoir
formation to displace residual oil.  The water from injection wells
physically sweeps the displaced oil to adjacent production
wells.  Potential problems associated with waterflood techniques
include inefficient recovery due to variable permeability, or similar conditions
affecting fluid transport within the reservoir, and early water breakthrough
that may cause production and surface processing problems.




Wellbore.  A
borehole or the hole drilled by a drilling bit.  A wellbore may have
casing in it or it may be open (uncased) or part of it may be open.




Working
interest.  The operating interest that gives the owner the
right to drill, produce and conduct operating activities on the property and a
share of production.




Workover.  Maintenance
on a producing well to restore or increase production.




viii




PART
I





ITEM
1.        BUSINESS





This Annual Report on Form 10-K
contains forward-looking statements based on expectations, estimates and
projections as of the date of this filing.  These statements by their
nature are subject to risks, uncertainties and assumptions and are influenced by
various factors.  As a consequence, actual results may differ
materially from those expressed in the forward-looking
statements.  For more information see “Forward-Looking Statements”
included at the end of this Item 1. “Business” and see also Item 1A.
“Risk Factors.”





References





When referring to South Texas Oil
Company (“South Texas,” the “Company,” “we,” “us,” and “our”), the intent is to
refer to South Texas and its consolidated subsidiaries as a whole or on an
individual basis, depending on the context in which the statements are
made.





Organization





South Texas Oil Company was
incorporated under the laws of the State of Nevada on July 31, 2001 as Nutek
Oil, Inc., a wholly owned subsidiary of Nutek, Inc., a Texas corporation
(“Nutek”). Our Articles of Incorporation presently authorize 50,000,000 shares
of common stock at $.001 par value and 5,000,000 shares of preferred stock at
$.001 par value. On August 1, 2001 and January 8, 2004, Nutek made distributions
of the Company’s common stock to its stockholders pursuant to a planned
“spin-off” that resulted in all of the outstanding shares of the Company’s
common stock being held by the stockholders of Nutek. On April 1, 2005, we
changed our name from Nutek Oil, Inc. to South Texas Oil Company.  Our
business activities are primarily conducted through our wholly owned
subsidiaries, Southern Texas Oil Company, STO Drilling Company, STO Operating
Company, and STO Properties LLC, a wholly owned subsidiary of STO Operating
Company. We operate in one reportable segment engaged in the exploration,
development and production of oil and natural gas properties.





Overview





South Texas Oil Company is an
independent oil and natural gas company engaged in the acquisition, production,
exploration and development of oil and natural gas. Our management team has
extensive technical and operating expertise in all areas of our geographic
focus, which are primarily located in Texas, Louisiana, Colorado and the Gulf
Coast. Our producing properties are located in highly prolific fields with long
histories of oil and natural gas operations.





At December 31, 2008, our estimated
total proved oil and natural gas reserves, as prepared by Forrest A. Garb &
Associates Inc., our independent reserve engineering firm, were approximately
5.1 million barrels of oil equivalent (MMBoe), consisting of 3.1 million barrels
of oil (MMBbl), and 12.1 billion cubic feet (Bcf) of natural gas. Approximately
12% of our proved reserves were classified as proved developed and 88% as proved
undeveloped. We have operational control of approximately 96% of our proved
reserves. The PV-10 value of our total proved reserves was approximately $70.3
million based on benchmark commodity prices as of December 31, 2008, which were
$44.60 per barrel of oil and $5.71 per MMBtu of natural gas. For the year ended
December 31, 2008, we produced 102.7 thousand barrels of oil equivalent
(MBoe).





Our principal offices are located at
300 East Sonterra Boulevard, Suite 1220, San Antonio, Texas 78258, telephone
number (210) 545-5994, fax number (210) 545-3317, and our website can be found
at www.southtexasoil.com.  Unless
specifically incorporated by reference in this document, information that you
may find on our website, or any other website, is not part of this document. Our
stock is traded on the NASDAQ Global Market under the ticker symbol
“STXX.”





Business
Strategy





Our
primary goal is to enhance stockholder value by increasing our cash flow, net
asset value, and reserves per share through acquisitions, production,
exploration, development and divestitures of oil and natural gas properties. Our
strategy is to identify prospects internally, acquire lands encompassing those
prospects and evaluate those prospects using subsurface geology, geophysical
data, development and exploratory drilling. Using this strategy, we have
developed an oil and natural gas portfolio of proved reserves, as well as
development and exploratory drilling opportunities on high-potential
conventional and non-conventional oil and natural gas prospects. We seek to be
the named operator of our properties so that we can control the drilling
programs to not only replace production, but add value through the growth of
reserves and future operational synergies.  Our strategy includes
balancing risks by allocating capital expenditures between lower-risk
development and exploitation activities and exploring higher-risk,
higher-potential drilling prospects.





1


As of December 31, 2008, we controlled
approximately 46,502 gross (27,532 net) acres and operated approximately 124
producing well bores located throughout 14 counties in Texas, Louisiana,
Colorado and the Gulf Coast.  The acreage that we operate and control
includes Atascosa, Bastrop, Brazos, Burleson, Calhoun, Fayette, Frio, Gonzales,
Lee, and Matagorda Counties in Texas, Assumption, Lafourche and Terrebonne
Parishes in Louisiana, and Logan County, Colorado. As of December 31, 2008, our
daily net production was approximately 250 barrels of oil equivalent (Boe), of
which approximately 70% is oil.





Our development program is focused on
lower risk, repeatable drilling opportunities to maintain or grow cash
flow.  We have conducted a geological, geophysical and engineering
analysis on our existing assets and have identified 27 horizontal wells to drill
from existing wellbores or offset locations that we have leased. Horizontal well
drilling provides increased exposure to the formation in order to increase the
flow rate and to recover additional oil and natural gas reserves not recoverable
from the existing vertical wellbores.  For 2009, we estimate our total
drilling and development capital expenditures will be approximately $10.0
million.  Our capital expenditure budget is under continuous review
and is subject to on-going adjustment.





Key elements of our business strategy
include the following:





·
            Focus on Our Existing
      Assets.  We intend to focus a significant portion of our
      growth efforts in our existing areas in Texas, Louisiana, Colorado and the
      Gulf Coast. We control approximately 46,502 gross (27,532 net) acres,
      which are largely characterized by long lived reserves and production
      histories in multiple oil and natural gas formations.  We
      believe our focus on and experience in the areas we operate may expose us
      to acquisition opportunities which may not be available to the entire
      industry.





·
            Develop and Exploit Existing
      Oil and Natural Gas Properties.As of December 31, 2008,
      we had identified 27 horizontal wells to drill from existing wellbores or
      offset locations that we have leased. Horizontal well drilling provides
      more access to the formation in order to increase the flow rate and to
      recover additional oil and natural gas reserves not recoverable from the
      existing vertical wellbores. The 27 identified wells are located in the
      Giddings Field in south central Texas and within the Austin Chalk trend.
      Our primary target formations within this trend are the Austin Chalk,
      Buda, Georgetown, Eagleford and Wilcox. The Austin Chalk trend covering
      our acreage ranges from approximately 150 feet to 750 feet in thickness
      and is subdivided into upper, middle and lower zones, with a vertical
      depth ranging between 6,000 feet and 12,000 feet.  Our
      development program within the Giddings Field is focused on lower risk,
      repeatable drilling opportunities to grow cash flow and proved
      reserves.  Additionally, as of December 31, 2008, we drilled,
      cased and cemented two directional wells in Matagorda Bay which are
      currently undergoing completion procedures. Those two wells were drilled
      with a barge rig in shallow Texas state waters in Calhoun County with
      target formations in the Frio sands ranging from 8,500 feet to 12,500
      feet.  Total measured depth (TMD) for well #127-1 reached 12,464
      feet in August 2008 and for well #150-1ST1 reached 10,260 feet in November
      2008.





·
            Complete Selective
      Acquisitions, Joint Ventures and Divestitures. We seek to acquire
      and/or enter into joint ventures for producing oil and natural gas
      properties, primarily in our core areas. We evaluate acquisitions and
      joint ventures based on criteria designed to increase cash flow, reserves,
      and production on an accretive basis. In December 2008, we announced a
      joint venture project agreement with Blue Moon Exploration, a privately
      held Houston-based geological and geophysical prospect generation
      firm.  Blue Moon Exploration’s prospects complement our existing
      core areas of focus while providing extensive access to geological,
      geophysical and seismic data. As part of this strategy, we may engage in
      strategic divestitures of non-core assets to redeploy capital into
      projects to develop both lower-risk and higher-return projects. We
      recently entered into an agreement to divest two non-core assets, which
      included our DJ Basin property located in Logan County, Colorado and our
      Unit U34 drilling rig, divestiture is expected to close in the second
      quarter of 2009.  See “—Recent Developments—$26.1 Million Debt
      Restructuring and Non-Core Asset
  Divestitures”.




2




We believe that the following strengths
complement our business strategy:




·
            High Quality Asset
      Base.We own, and plan
      to maintain, a geographically focused reserve base. Our principal
      operations are in the Giddings Field of south central Texas, Louisiana and
      the shallow Texas state waters of the Gulf Coast.  Our properties are
      generally characterized by a high oil concentration, with long reserve
      lives, and a multi-year inventory of development drilling and exploitation
      projects. These resource plays present significant opportunities to
      grow our reserves with low finding and development costs.  Since a
      majority of our acreage in these areas is held by production (HBP), we are
      not required to commit capital over a short period of time to avoid lease
      expirations.





·
            Operational Control.We
      seek to be the operator of our properties so that we can control the
      timing and extent of our capital expenditures and the drilling programs
      that not only replace production, but also add value through the growth of
      cash flow, reserves and future operational synergies. As of December 31,
      2008, we maintained operational control of approximately 96% of our proved
      reserves. Our high degree of operating control allows us to control
      capital allocation and expenses and the timing of additional development
      and exploitation of our producing
properties.





·
            Experienced Management Team
      with Significant Technical Expertise.Our management
      team has extensive technical and operating expertise in all areas of our
      geographic focus.  We believe that the knowledge, experience and
      expertise of our staff will continue to support our efforts to enhance
      stockholder value.  Since our new management team was installed
      in June 2008, we have implemented a disciplined top-to-bottom analysis of
      the Company and a comprehensive evaluation of our asset base and core
      operating areas, resulting in the achievement of substantial growth in
      proved reserves and other operational and financial efficiencies. We have
      increased our proved reserves from approximately 0.581 MMBoe in 2007 to
      approximately 5.1 MMBoe at December 31, 2008, a 778%
    increase.





·
            Insider Ownership.As
      of March 5, 2009, our management team and directors beneficially owned
      approximately 14% of our outstanding shares of common stock, which aligns
      management’s objectives with our
stockholders.





Capital
Expenditures





Our efforts in 2008 were mainly focused
on evaluating our existing assets to determine the best areas and techniques for
development. This evaluation included a comprehensive and meticulous review of
our asset base and core operating areas, our geological and geophysical data,
reserves data and extensive land and title review and evaluation, which resulted
in part to the increase in proved reserves reported. For 2009, our estimated
capital expenditure budget is $10.0 million, and we intend to focus our drilling
program primarily on the Austin Chalk, Buda, Georgetown, Eagleford and Wilcox
formations in the Giddings Field where we currently have an inventory of 27
horizontal wells to drill with laterals that range from 500 feet to 5,000 feet.
The capital expenditure budget includes an estimated $5.5 million for the
Giddings Field horizontal wells, $4.0 million for the Blue Moon Exploration
joint venture project focused in Texas and Louisiana, and $0.5 million for
Matagorda Bay completion activities. Our 2009 capital expenditure budget
presently excludes acquisitions, but may include installation of gathering
system infrastructure and pipeline hookups and the acquisition of geophysical
operations, including seismic data.





Due to current capital and credit
market conditions in which numerous financial institutions haveeffectively restricted
current liquidity within the capital markets throughout the United States and
around the world, we cannot be certain that funding will be available to
us in required amounts or on acceptable terms. To the extent we access
credit or capital markets in the near term, our ability to obtain terms and
pricing similar to its existing terms and pricing may be
limited.Our current cash balances and cash flow from operations
will not provide adequate working capital to fully fund our 2009 capital
expenditure budget, and we intend to pursue potential debt
and/or equity financing and to evaluate other alternatives, such as joint
ventures with third parties or sales of interests in one or more of our
properties in order to fund our capital expenditures. Such transactions may
result in a reduction in our operating interests or require us to relinquish the
right to operate the property. We also plan to
renegotiate and/or refinance our existing secured debt, which includes
approximately a $7.0 million senior secured bridge note and approximately $9.0
million in notes outstanding under our credit facility, which mature in
September 2009 and December 2009, respectively. Entry into a new credit
facility is expected to result in increased interest expense, and there can be
no assurance that the borrowing base will remain at the current level.There can be no assurance that any such transactions can be completed or
that such transactions will satisfy our operating capital requirements. If we
are not successful in obtaining sufficient funding or completing an alternative
transaction on a timely basis on terms acceptable to us, we could be required to
curtail our expenditures or restructure our operations, and we would be unable
to implement our original exploration and drilling program, either of which
could have a material adverse effect on our business, financial condition and
results of operations. Our capital expenditure budget
may be modified depending upon commodity prices and market
conditions.





3




Recent
Developments





New
Management Team and Relocation of Corporate Headquarters





On June 24, 2008, we announced that
Michael Pawelek, South Texas Oil Company’s current Chairman of the Board, was
named as our Chief Executive Officer and President. Additionally, Wayne Psencik
was appointed as Executive Vice President and Chief Operating Officer, and
Sherry Spurlock was appointed as Executive Vice President and Chief Financial
Officer. The management change was an internally planned
succession.  Additionally, Theodore J. Wicks was appointed Executive
Vice President of Corporate Development in October 2008 and Robert W. Kuehner
was appointed Vice President of Land Management in August
2008.  Effective July 1, 2008, South Texas Oil Company moved its
corporate headquarters to 300 East Sonterra Boulevard, Suite 1220, San Antonio,
Texas 78258.  Our office number is (210) 545-5994 and the fax number
is (210) 545-3317.





Senior
Secured Bridge Financing





On September 19, 2008, we closed a $7.0
million bridge financing with the Longview Marquis Master Fund, L.P. (“Marquis”)
in the form of a senior secured note of which $6.75 million was available to us
for general working capital purposes.  The senior secured note carries
an interest rate of 12.5% per annum payable quarterly in cash and matures in
September 2009.





Subsequent
Events





$26.1
Million Debt Restructuring and Non-Core Asset Divestitures





On February 23, 2009, we announced a
comprehensive debt restructuring and related agreements with The Longview Fund
L.P. (“Longview”), which will extinguish 62% of our existing notes payable under
our credit facility and our senior secured debt.  The definitive
agreements with Longview provide that Longview will restructure $26.1 million of
debt (plus accrued interest) through (i) the payment of $16.3 million in debt
(plus accrued interest) held by Longview in exchange for 1.6 million shares of
our Series A Convertible Preferred Stock and (ii) a debt/non-core asset exchange
between us and Longview valued at $9.8 million.





Pursuant to a securities exchange
agreement, we will issue to Longview approximately 1.6 million shares of Series
A Convertible Preferred Stock in exchange for the surrender and cancellation of
approximately $16.3 million of notes payable held by Longview. Each share of
Series A Convertible Preferred Stock has a stated value equal to $10.00 per
share, has no coupon rate, does not pay dividends, and has no voting rights. The
shares of Series A Convertible Preferred Stock are convertible into shares of
our common stock at any time subsequent to 90 days after the issuance of the
shares at a conversion price of $0.50 per share of common stock. Stockholders
holding more than a majority of our outstanding common stock (approximately
59.36%) have approved the creation and issuance of the shares of Series A
Preferred Stock to Longview, and we have filed an information statement with the
Securities and Exchange Commission (the “SEC”), which is subject to SEC review.
Following SEC review, we will provide notice to all of our stockholders that did
not consent to such action, by delivery of an Information Statement prepared
pursuant to Section 14 of the Securities Exchange Act of 1934 (the “Exchange
Act”), and the exchange will close a minimum of 20 days following the mailing of
the Information Statement to our stockholders.





We also entered into a definitive asset
purchase and sale agreement with Longview sell our Colorado DJ Basin property
and our Unit U34 drilling rig and associated assets to Longview for a combined
total of $9.8 million. Subject to the terms and conditions of the purchase and
sale agreement, on the closing date, we have agreed to convey these assets to
Longview in exchange for Longview’s discharge and satisfaction of $9.8 million
in debt.  The Colorado property disposition includes our entire 37.5%
non-operated working interest in 23,111 gross (8,666 net) acres located in Logan
County, Colorado. The DJ Basin property includes approximately 217,000 Boe of
proved reserves and an estimated 18 Boe/d of net production.





Closing of both transactions is subject
to customary closing conditions and SEC review of our Information Statement on
Schedule 14C. The final closing price will reflect typical closing and
post-closing adjustments. Following the closing of both transactions, our
remaining senior secured debt Marquis will be approximately $16.0
million.





4




Properties





As of December 31, 2008, we controlled
approximately 46,502 gross (27,532 net) acres and operated approximately 124
producing well bores located throughout 14 counties and/or parishes in Texas,
Louisiana, Colorado and the Gulf Coast. Our properties are located in the
following areas in the United States:





·
            Giddings
      Field, which is located in south central Texas, and includes the Bastrop,
      Brazos, Burleson, Fayette, Gonzales, and Lee Counties,
    Texas;


·
            Big
      Foot Field, which is located in south central Texas and includes the
      Atascosa and Frio Counties, Texas;


·
            DJ
      Basin, which is located in Logan County, Colorado (which properties we
      have subsequently agreed to
divest);


·
            Gulf
      Coast, which includes our Matagorda Bay wells in the shallow state waters
      of Matagorda and Calhoun Counties, Texas;
and


·
            Louisiana,
      which includes projects with Blue Moon Exploration in Assumption,
      Lafourche and Terrebonne Parishes,
Louisiana.










5





Giddings
Field





As of December 31, 2008, we controlled
approximately 16,655 gross (14,142 net) acres, which included 47 producing well
bores with net production of approximately 212 Boe/d in the Giddings Field. Our
Giddings Field is 100% operated, and we hold an approximate 86% working
interest. The majority of our proved reserves are located in the Giddings Field.
As of December 31, 2008, we have identified 27 horizontal wells to drill from
existing wellbores or offset locations that we have leased. We also possess
approximately 70 linear miles of 2-D seismic data. For 2009, our capital
expenditure budget includes $5.5 million for the Giddings Field horizontal well
development program. Our development program within the Giddings Field is
focused on lower risk, repeatable drilling opportunities to grow cash flow and
reserves. Horizontal well drilling provides increased exposure to the formation
in order to increase the flow rate and to recover additional oil and natural gas
reserves not recoverable from the existing vertical
wellbores.  Horizontal drilling also allows multiple fracture zones,
which are not connected, to be developed by a single well.





Our acreage position in the Giddings
Field covers the Bastrop, Brazos, Burleson, Fayette and Lee, Counties, Texas.
Our acreage leasehold primarily covers the updip, shallow side of the Giddings
Field, which is an oil-prone area. The primary target formations of the 27
identified horizontal wells are the Austin Chalk, Buda, Georgetown, Eagleford
and Wilcox. These formations are generally characterized by high initial
production rates and steep decline rates, with first year production declines
approaching approximately 60%. Well logs and seismic data indicate fracture
systems striking in a NE-SW direction, which are separated by non-fractured
carbonate. The Austin Chalk covering our acreage in the Giddings Field ranges
from 150 feet to 750 feet in thickness, and consists of interbedded chalk and
marl (limestone with shale).





The Giddings Field, is a 10- to 20-
mile-wide trend extending from Mexico through Central Texas and into northwest
Louisiana. The primary producing reservoir is the Austin Chalk (Upper
Cretaceous, 85-90 million years old), with secondary production from the Taylor
(Upper Cretaceous) and deeper Buda and Georgetown Formations (Lower Cretaceous
98-105 million years old). The Austin Chalk is subdivided into upper, middle and
lower zones, with a vertical depth ranging between 6,000 and 12,000 feet. The
Austin Chalk, Buda and Georgetown formations are a naturally fractured carbonate
reservoir, with limited matrix porosity (1-5%) and permeability (0.003-0.03
md).  Most hydrocarbon production in the Austin Chalk comes from an
extensive network of fractures.  The first commercial discovery in the
Austin Chalk was made in Texas in 1923 at Luling Field, followed by the Pearsall
Field in 1935, then the Giddings Field in 1960.  The Giddings Field
has historically produced over 1.5 billion Boe.





Big
Foot Field





Our Big Foot Field is located in Frio
and Atascosa Counties, Texas. The Big Foot Field was first discovered by Shell
Oil Company in 1949, has produced over 5 million Boe and is characterized
as a shallow, oily play. The primary producing formations are the Olmos B and
Olmos D sands, which range in depth from 3,100 feet to 3,600 feet.  We have
73 wells cumulatively producing approximately 30 barrels of oil net per day
(Bopd), with a 100% working interest in 4,050 acres. South Texas Oil recently
completed two re-fracs in two separate wells which previously were completed and
producing. These wells were marginal producers pumping from 0.25 to 0.5 Bopd
each. After fracture stimulation utilizing modern techniques, one of the wells
is pumping at a stabilized rate of approximately 7 Bopd, up from 0.5 Bopd. Our
geological and geophysical staff has initially identified 20 additional wells
for potential workover activity. Our anticipated Big Foot Field refrac program
could increase production and return shut-in wellbores to producing status. In
addition to our workover activity, most of our existing wells in the Big Foot
Field were drilled on 20-acre spacing, providing us with at least 40 additional
infill drilling locations based on 10-acre well density.





DJ
Basin





As of
December 31, 2008, South Texas Oil controlled approximately 23,111 gross (8,666
net) predominantly contiguous acres in the DJ Basin in Logan County, Colorado,
in which it has approximately a non-operated, 37.5% net working
interest.  Current net production is approximately 18 Boe/d from four
producing wells, or 7% of our daily production. We recently entered into a
definitive asset purchase and sale agreement with Longview to divest our
Colorado DJ Basin property and our Unit U34 drilling rig and associated assets
to Longview for a combined total of $9.8 million. See “—Recent
Developments—$26.1 Million
Debt Restructuring and Non-Core Asset Divestitures”.





6


Gulf
Coast





We control 2,240 gross (652 net) acres
in shallow Texas state waters in Matagorda Bay, in which we currently have
identified four exploratory prospects from a 120-square-mile 3-D seismic
survey. As of June 2008, we agreed to contract operate the Matagorda Bay
properties on behalf of Sonterra Resources, Inc., and we operate the
Matagorda Bay wells and hold a working interest of approximately 20.5%
and 37.5% on well #127-1 and well #150-1ST1, respectively. As of December 31,
2008, we drilled, cased and cemented two directional wells in Matagorda Bay,
which are currently undergoing completion procedures. These wells were drilled
with a barge rig in shallow Texas state waters (10-15 feet water depth) in
Calhoun County, Texas. Target formations in the Frio sands are the Bolmex,
Melbourne and Nodosaria which range from 8,500 feet to 12,500 feet. Total
measured depth (TMD) for well #127-1 reached 12,464 feet in August 2008 and for
well #150-1STI reached 10,260 feet in November 2008. Well #127-1 was a new
exploratory drill and well #150-1ST1 was a side-track re-entry development well.
Diagnostic well log analysis indicates multiple natural gas and condensate pay
zones. A 1-mile gas sales pipeline is permitted.





Louisiana





We currently have leasehold acreage and
are pursuing leases in Assumption, Lafourche and Terrebone Parishes,
Louisiana.  As part of our joint venture project agreement with Blue Moon
Exploration, we are strategically focused on expanding our operations and
developing oil and natural gas prospects throughout Louisiana. These prospects,
which we anticipate operating, primarily target the Miocene formations. As of
December 31, 2008, we leased 446 gross (22 net) acres in Lafourche Parish.





Drilling
and Acreage





Drilling
Activity





The following table sets forth the
results of our drilling activities, which include the number and type of wells
that we drilled during the years ended December 31, 2008, 2007 and
2006:





Years Ended December 31,2008
                        
                        
                        2007
                        
                        
                        2006Gross1
                        
                        
                        Net1
                        
                        
                        Gross
                        
                        
                        Net
                        
                        
                        Gross
                        
                        
                        NetDevelopment
      wells, completed as:Productive
                        
                        
                        1.0
                        
                        
                        
                        0.93
                        
                        
                        
                        9.0
                        
                        
                        
                        6.43
                        
                        
                        
                        3.0
                        
                        
                        
                        1.87Non-Productive
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        3.0
                        
                        
                        
                        2.38
                        
                        
                        
                        -
                        
                        
                        
                        -Exploratory
      wells, completed as:Productive
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -Non-Productive
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -Total
                        
                        
                        1.0
                        
                        
                        
                        0.93
                        
                        
                        
                        12.0
                        
                        
                        
                        8.81
                        
                        
                        
                        3.0
                        
                        
                        
                        1.87





(1)
            Does not include 3.0 gross
      (1.58 net) wells that were in the process of being completed as of
      December 31, 2008.




Developed
and Undeveloped Acreage





The following table sets forth our
developed and undeveloped gross and net leasehold acreage, including options to
acquire leasehold acreage, as of December 31, 2008:





Developed Acreage
                  
                  
                  Undeveloped Acreage
                  
                  
                  Total AcreageLocation
                  
                  Gross
                  
                  
                  Net
                  
                  
                  Gross
                  
                  
                  Net
                  
                  
                  Gross
                  
                  
                  NetGiddings
      Field
                  
                  
                  10,532
                  
                  
                  
                  8,607
                  
                  
                  
                  6,123
                  
                  
                  
                  5,535
                  
                  
                  
                  16,655
                  
                  
                  
                  14,142Big
      Foot Field
                  
                  
                  3,972
                  
                  
                  
                  3,972
                  
                  
                  
                  78
                  
                  
                  
                  78
                  
                  
                  
                  4,050
                  
                  
                  
                  4,050Matagorda
      Bay
                  
                  
                  2,240
                  
                  
                  
                  652
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  2,240
                  
                  
                  
                  652DJ
      Basin
                  
                  
                  2,700
                  
                  
                  
                  1,013
                  
                  
                  
                  20,411
                  
                  
                  
                  7,653
                  
                  
                  
                  23,111
                  
                  
                  
                  8,666Louisiana
                  
                  
                  
                  
                  
                  
                  
                  
                  446
                  
                  
                  
                  22
                  
                  
                  
                  446
                  
                  
                  
                  22Total
      Acreage
                  
                  
                  19,444
                  
                  
                  
                  14,244
                  
                  
                  
                  27,058
                  
                  
                  
                  13,288
                  
                  
                  
                  46,502
                  
                  
                  
                  27,532





We use the successful efforts method of
accounting for our oil and natural gas properties. Exploration costs such as
exploratory geological and geophysical costs and delay rentals are charged
against earnings as incurred. The costs to acquire, drill and equip exploratory
wells are capitalized pending determinations of whether proved reserves can be
attributed to our interests as a result of drilling the well.  If
management determines that commercial quantities of oil and natural gas have not
been discovered, costs associated with exploratory wells are charged to
exploration expense. Costs to acquire mineral interests, to drill and equip
development wells, to drill and equip exploratory wells that find proved
reserves, and related costs to plug and abandon wells and costs of site
restoration are capitalized.





7


Depletion, depreciation and
amortization of proved oil and natural gas properties is computed using the
units of production method based on proved reserves. Sales of entire interests
in proved and unproved properties, and sales of partial interests of proved
properties result in the recognition of gains or losses.  Sales of
partial interests of unproved properties are generally treated as a recovery of
the cost of the interests retained.





Capitalized costs of our proved and
unproved properties at December 31, 2008 and 2007 are summarized as
follows:





December 31,2008
                                        
                                        
                                        2007Proved
      properties
                                        
                                        $
                                        49,489,536
                                        
                                        
                                        $
                                        23,383,575Less accumulated depreciation,
      depletion and amortization
                                        
                                        
                                        (9,656,545
                                        )
                                        
                                        
                                        (5,727,612
                                        )Net proved
    properties
                                        
                                        
                                        39,832,991
                                        
                                        
                                        
                                        17,655,963Unproved
      properties:Oil and gas leasehold
      costs
                                        
                                        
                                        944,359
                                        
                                        
                                        
                                        30,757,344Drilling
      in progress
                                        
                                        
                                        4,924,395
                                        
                                        
                                        
                                        -5,868,754
                                        
                                        
                                        
                                        30,757,344Net
      capitalized costs
                                        
                                        $
                                        45,701,745
                                        
                                        
                                        $
                                        48,413,307





Production





Our oil and natural gas production
volumes and average sales price for the years ended December 31, 2008, and 2007
are as follows:





Years Ended December 31,2008
                    
                    
                    2007Natural
      gas production (MMcf):
                    
                    
                    153.9
                    
                    
                    
                    291.7Oil
      production (MBbl)
                    
                    
                    77.1
                    
                    
                    
                    121.1Equivalent
      production (MBoe)
                    
                    
                    102.7
                    
                    
                    
                    169.7Average
      price per unit:Natural gas (per
    Mcf)
                    
                    $
                    10.32
                    
                    
                    $
                    3.40Oil (per Bbl)
                    
                    $
                    99.61
                    
                    
                    $
                    35.99Equivalent (per
    Boe)
                    
                    $
                    90.14
                    
                    
                    $
                    31.53





Delivery
Commitments





At December 31, 2008, we had no
delivery commitments with our purchasers.





Proved
Reserves





At December 31, 2008, our estimated
total proved oil and natural gas reserves, as prepared by Forrest A. Garb &
Associates Inc., an independent reserve engineering firm, were approximately 5.1
million barrels of oil equivalent, consisting of 3.1 million barrels of oil, and
12.1 billion cubic feet of natural gas. Approximately 12% of our proved reserves
were classified as proved developed and 88% as proved undeveloped. We maintain
operational control of approximately 96% of our proved reserves. The PV-10 value
of our total proved reserves was approximately $70.3 million based on benchmark
commodity prices as of December 31, 2008, which were $44.60 per barrel of oil
and $5.71 per MMBtu of natural gas. For the year ended December 31, 2008, we
produced 102.7 thousand barrels of oil and natural gas equivalent (MBoe). We
booked a higher quantity of proved undeveloped locations due to what we believe
is the lower-risk nature of these reserves as demonstrated through analogous
well data from long-term historical production in the immediate areas that were
evaluated.  The majority of the low-risk proved undeveloped (PUD)
locations are located in the Giddings Field, which has demonstrated reliable
production and reservoir characteristics for us and other operators over the
years.




8


Proved
oil and natural gas reserves are the estimated quantities of natural gas, oil,
condensate and NGLs that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Reserve estimates are
considered proved if economical productivity is supported by either actual
production or conclusive formation tests. Estimated reserves that can be
produced economically through application of improved recovery techniques are
included in the “proved” classification when successful testing by a pilot
project or the operation of an active, improved recovery program in the
reservoir provides support for the engineering analysis on which the project or
program is based. Estimated proved developed oil and natural gas reserves can be
expected to be recovered through existing wells with existing equipment and
operating methods.





Our
reported reserves are estimates only, which, by their nature, are subject to
revision. The estimates are made using available geological and reservoir data,
as well as production performance data. These estimates are reviewed throughout
the year and revised either upward or downward, as warranted by additional
performance data. With the exception of our DJ Basin property for 2008, Forrest
A. Garb & Associates Inc. engineered all material fields. We selected the
properties for engineering by Forrest A. Garb & Associates Inc. and MHA
Petroleum Consultants. The 2008 DJ Basin reserves were engineered by
Denver-based MHA Petroleum Consultants and were audited by Forrest A. Garb &
Associates Inc.





Forrest
A. Garb & Associates Inc. opined that the overall proved reserves for the
engineered properties are in the aggregate, reasonable, and prepared in
accordance with generally accepted petroleum engineering and evaluation
principles and conform to the SEC’s definition of proved reserves as set forth
in Rule 210.4-10(a) of Regulation S-X. The estimates of proved
reserves as of December 31, 2008 and 2007, changes in estimated proved
reserves during the last two years and estimates of future net cash flows and
discounted future net cash flows from estimated proved reserves are contained in
Note 12 — Supplemental Oil and Gas Disclosures of Item 15 in this
Form 10-K. These estimated future net cash flows are based on prices on the
last day of the year and are calculated in accordance with Statement of
Financial Accounting Standards (SFAS) No. 69, “Disclosures about Oil and
Gas Producing Activities.” Disclosure of this value and related reserves has
been prepared in accordance with SEC Regulation S-X
Rule 4-10.





In
December 2008, the SEC released the final rule for “Modernization of Oil and Gas
Reporting” (Modernization). The Modernization disclosure requirements will
permit reporting of oil and natural gas reserves using an average price based
upon the prior 12-month period rather than year-end prices and the use of new
technologies to determine proved reserves, if those technologies have been
demonstrated to result in reliable conclusions about reserves volumes. Companies
will also be allowed to disclose probable and possible reserves in SEC filed
documents. In addition, companies will be required to report the independence
and qualifications of its reserves preparer or auditor and file reports when a
third party is relied upon to prepare reserves estimates or conduct a reserves
audit. The Modernization disclosure requirements become effective for our Annual
Report on Form 10-K for the year ended December 31,
2009.





The following table presents certain
information as of December 31, 2008 for all of our proved reserves and
properties:





Estimated Net Reserves
              
              
              Estimated Future Net
                RevenueOil and
                Condensate
              
              
              Natural
                Gas
              
              
              Discounted at
                10% Per YearProved Reserve Category:
              
              (MBbl)
              
              
              (MMcf)
              
              
              (in thousands)Proved
      Reserves at Year End:DevelopedProducing
              
              
              266.25
              
              
              
              426.93
              
              
              $
              4,782.13Nonproducing
              
              
              13.16
              
              
              
              0.00
              
              
              
              100.03Behind
      Pipe
              
              
              70.88
              
              
              
              1,188.42
              
              
              
              4,920.35Undeveloped
              
              
              2,727.52
              
              
              
              10,465.24
              
              
              
              60,522.58Total Proved
              
              
              3,077.82
              
              
              
              12,080.60
              
              
              $
              70,325.10




9




Years Ended December 31,Proved Reserves Category
      (MBoe):
                              
                              2008
                              
                              
                              2007DevelopedProducing
                              
                              
                              337.4
                              
                              
                              
                              501.2Nonproducing
                              
                              
                              13.16
                              
                              
                              
                              15.6Behind
      Pipe
                              
                              
                              268.9
                              
                              
                              
                              -Undeveloped
                              
                              
                              4,471.7
                              
                              
                              
                              64.6Total
      Proved (MBoe)
                              
                              
                              5,091.1
                              
                              
                              
                              581.4Average
      price per unit:Natural Gas (per
    Mcf)
                              
                              $
                              5.71
                              
                              
                              $
                              6.79Oil (per Bbl)
                              
                              $
                              44.60
                              
                              
                              $
                              92.50





Years Ended December 31,Proved
      Reserves Category (MBoe):
                          
                          2008(1)
                          
                          
                          2007(1)Oil
      (MBbl)
                          
                          
                          3,077.8
                          
                          
                          
                          388.7Natural
      Gas (MMcf)
                          
                          
                          12,080.6
                          
                          
                          
                          1,156.4Combined
      Proved (MBoe)
                          
                          
                          5,091.1
                          
                          
                          
                          581.4SEC
      PV-10 Value (in millions)
                          
                          $
                          70.3
                          
                          
                          $
                          18.2


(1)
            The
      oil reserves shown include oil and condensate. Oil volumes are expressed
      in barrels (Bbl) or thousand barrels (MBbl); a barrel is equivalent to 42
      United States gallons. Natural gas volumes are expressed in thousands of
      standard cubic feet (Mcf) at the contract temperature and pressure bases.
      The term MBoe which is defined as thousands of barrels of equivalent oil
      is also used and is calculated by converting natural gas volumes to oil
      volumes at the ratio of 6:1.




Reconciliation
of Non-GAAP Financial Measures




The
following table shows our reconciliation of our standardized measure of
discounted future net cash flows to our PV-10 (the most directly comparable
measure calculated and presented in accordance with GAAP). PV-10 is our estimate
of the present value of future net revenues from estimated proved natural gas
reserves after deducting estimated production and ad valorem taxes, future
capital costs and operating expenses, but before deducting any estimates of
future income taxes. The estimated future net revenues are discounted at an
annual rate of 10% to determine their "present value." We believe PV-10 to be an
important measure for evaluating the relative significance of our oil and
natural gas properties and that the presentation of the non-GAAP financial
measure of PV-10 provides useful information to investors because it is widely
used by professional analysts and sophisticated investors in evaluating oil and
natural gas companies. Because there are many unique factors that can impact an
individual company when estimating the amount of future income taxes to be paid,
we believe the use of a pre-tax measure is valuable for evaluating our company.
We believe that most other companies in the oil and natural gas industry
calculate PV-10 on the same basis. PV-10 should not be considered as an
alternative to the standardized measure of discounted future net cash flows as
computed under GAAP.





At December 31,(in
      thousands)
                  
                  2008
                  
                  
                  2007PV-10
      Value
                  
                  $
                  70,325.1
                  
                  
                  $
                  18,244.7Future
      income taxes
                  
                  
                  (51,499.6
                  )
                  
                  
                  (8,591.0
                  )Discount
      of future income taxes at 10% per annum
                  
                  
                  26,250.0
                  
                  
                  
                  3,021.3Standardized
      measure
                  
                  $
                  45,075.1
                  
                  
                  $
                  12,675.0





Operational
Overview





Major
Customers





We
operate exclusively in the oil and natural gas industry.  We generally
sell our products based on current market prices to our customer under contracts
that range from month-to-month to up to a year. For the year ended December 31,
2008, sales of oil, natural gas and NGL’s to Texon Corporation, DCP Midstream
Partners LP, Energy Transfer Partners, LP, and Shell Trading (US) Company
accounted for approximately 70%, 13%, 3%, and 2%, respectively, of our total
revenue, or 88% in the aggregate.  If we were to lose any one of our
major oil and natural gas purchasers, the loss could temporarily cease or delay
production and sale of our oil and natural gas.  Although we believe
that we are not dependent upon any one customer, in the event one of our major
customers is unwilling or unable to purchase our production, we believe we could
readily identify a substitute purchaser.  Sales are generally made
pursuant to contracts that vary in length from a month-to-month basis to one
year. The prices are typically tied to West Texas Intermediate crude and Houston
Ship Channel natural gas commodity futures trading prices.





10




Competition





We are a small independent oil and
natural gas exploration and production company and we face competition from
other oil and natural gas companies in all aspects of our business, including
acquisition of producing properties and oil and natural gas leases, and
obtaining goods, services and labor.  Many of our competitors have
substantially greater financial and other resources.  Factors that
affect our ability to acquire properties include available funds, available
information about the property and our standards established for minimum
projected return on investment. Many of these companies explore for, produce and
market oil and natural gas, carry on refining operations and market the
resultant products on a worldwide basis. The primary areas in which we encounter
substantial competition are in locating and acquiring desirable leasehold
acreage for our drilling operations, locating and acquiring attractive producing
oil and natural gas properties, and obtaining purchasers and transporters of the
oil and natural gas we produce. There is also competition between producers of
oil and natural gas and other industries producing alternative energy and fuel.
Furthermore, competitive conditions may be substantially affected by various
forms of energy legislation and/or regulation considered from time to time by
the government of the United States; however, it is not possible to predict the
nature of any such legislation or regulation that may ultimately be adopted or
its effects upon our future operations. Such laws and regulations may, however,
substantially increase the costs of exploring for, developing or producing
natural gas and oil and may prevent or delay the commencement or continuation of
a given operation. The effect of these risks cannot be accurately
predicted.





Operational
Risks





Oil and natural gas exploration and
development involves a high degree of risk, which even a combination of
experience, knowledge and careful evaluation may not be able to overcome. There
is no assurance that we will discover or acquire additional oil and natural gas
in commercial quantities. Oil and natural gas operations also involve the risk
that well fires, blowouts, equipment failure, human error and other
circumstances that may cause accidental leakage of toxic or hazardous materials,
such as petroleum liquids or drilling fluids into the environment, or cause
significant injury to persons or property may occur. In such event, substantial
liabilities to third parties or governmental entities may be incurred, the
payment of which could substantially reduce available cash and possibly result
in loss of oil and natural gas properties. Such hazards may also cause damage to
or destruction of wells, producing formations, production facilities and
pipeline or other processing facilities. We are not aware of any of these
instances that have occurred to date for which a liability should be accrued. As
is common in the oil and natural gas industry, we will not be insured fully
against all risks associated with our business either because such insurance is
not available or because premium costs are considered prohibitive. A loss not
fully covered by insurance could have a materially adverse effect on our
financial position and results of operations. For further discussion on risks
see section titled “Risk Factors” set forth in “Item 1A. Risk
Factors.”





Title to
Interests





As is
customary in the oil and natural gas industry, we have a dedicated land
department that generally conducts a preliminary review of title records, which
may include opinions or reports of appropriate professionals or counsel, is made
at the time we acquire properties. We believe that our title to all of the
various interests set forth above is satisfactory and consistent with the
standards generally accepted in the oil and natural gas industry, subject only
to immaterial exceptions that do not detract substantially from the value of the
interests or materially interfere with their use in our operations. The
interests owned by us may be subject to one or more royalty, overriding royalty,
and other outstanding interests (including disputes related to such interests)
customary in the industry. The interests may additionally be subject to
obligations or duties under applicable laws, ordinances, rules, regulations, and
orders of arbitral or governmental authorities. In addition, the interests may
be subject to burdens such as production payments, net profits interests, liens
incident to operating agreements and current taxes, development obligations
under oil and natural gas leases, and other encumbrances, easements, and
restrictions, none of which detract substantially from the value of the
interests or materially interfere with their use in our
operations.  Prior to the commencement of drilling operations, we
conduct a thorough title examination and perform curative work with respect to
significant defects.  To the extent title opinions or other
investigations reflect title defects on those properties, we are typically
responsible for curing any title defects prior to commencing drilling
operations.  Prior to completing an acquisition of producing natural
gas leases, we perform title reviews on the most significant leases and,
depending on the materiality of properties, we may obtain a title opinion or
review previously obtained title opinions.  As a result, we have
obtained title opinions on a significant portion of our oil and natural gas
properties and believe that we have satisfactory title to our producing
properties in accordance with standards generally accepted in the oil and
natural gas industry.





11




Seasonal
Nature of Business





Seasonal weather conditions and lease
stipulations can limit the drilling and producing activities and other
operations in regions of the United States where we operate. Weather conditions
affect the demand for, and prices of, oil and natural gas and can also delay
drilling activities, disrupting our overall business plans. Demand for natural
gas typically decreases during the summer months and increases during the winter
months. Seasonal anomalies such as mild winters or hot summers sometimes lessen
this fluctuation.  The demand for oil is generally determined at a
global level, based on supply shortage concerns driven primarily by natural
disasters such as hurricanes and by political instability in certain oil
producing regions of the world.





Governmental
and Environmental Regulation





Domestic exploration and production of
oil and natural gas are extensively regulated at both the federal, state and
local levels. Legislation affecting the oil and natural gas industry is under
constant review for amendment or expansion, frequently increasing the regulatory
burden. Also, numerous departments and agencies, both federal and state, are
authorized by statute to issue, and have issued, rules and regulations binding
on the oil and natural gas industry that often are costly to comply with and
that carry substantial penalties for failure to comply. In addition, production
operations are affected by changing tax and other laws relating to the petroleum
industry, constantly changing administrative regulations and possible
interruptions or termination by government authorities.





Thus, the operation of our properties
is subject to extensive and continually changing regulation affecting the oil
and natural gas industry. Many departments and agencies, federal, state and
local, are authorized by statute to issue, and have issued, rules and
regulations binding on the oil and natural gas industry and its individual
participants. The failure to comply with such rules and regulations can result
in substantial penalties. The regulatory burden on the oil and natural gas
industry increases its cost of doing business and, consequently, affects its
profitability.





Transportation
and Sale of Natural Gas





The interstate transportation and sale
for resale of natural gas is subject to federal regulation, including
transportation rates and various other matters, by the Federal Energy Regulatory
Commission (“FERC”). Federal wellhead price controls on all domestic natural gas
were terminated on January 1, 1992 and none of our natural gas sales prices are
currently subject to FERC regulation. We cannot predict the impact of future
government regulation on any natural gas operations.





Regulation
of Production





The production of oil and natural gas
is subject to regulation under a wide range of federal, state and local
statutes, rules, orders and regulations. State and federal statutes and
regulations require permits for drilling operations, drilling bonds, and reports
concerning operations. Texas, the state in which we own properties, has
regulations governing conservation matters, including provisions for the
unitization or pooling of oil and natural gas properties, the establishment of
maximum rates of production from oil and natural gas wells, the spacing of
wells, and the plugging and abandonment of wells and removal of related
production equipment. Texas also restricts production to the market demand for
oil and natural gas. These regulations can limit the amount of oil and natural
gas which can be produced from our wells, limit the number of wells, or limit
the locations at which we can conduct drilling operations. Moreover, each state
generally imposes a production or severance tax with respect to production and
sale of oil, natural gas and natural gas liquids within its
jurisdiction.





Environmental
Regulations





Operation of our properties is 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 human health and environmental protection. These laws and
regulations may, among other things, require acquisition of a permit before
drilling or development commences, restrict the types, quantities and
concentrations of various materials that can be released into the environment in
connection with development and production activities, and limit or prohibit
construction or drilling activities in certain ecologically sensitive and other
protected areas.  Failure to comply with these laws and regulations or
to obtain or comply with permits may result in the assessment of administrative,
civil and criminal penalties, imposition of remedial requirements and the
imposition of injunctions to force future compliance. Our business and prospects
could be adversely affected to the extent laws are enacted or other governmental
action is taken that prohibits or restricts our development and production
activities or imposes environmental protection requirements that result in
increased costs to us or the oil and natural gas industry in
general.





12


Oil and natural gas exploration and
production activities on federal lands are subject to the National Environmental
Policy Act, or NEPA. NEPA requires federal agencies, including the Department of
Interior and various other federal, state, and local environmental, zoning,
health and safety agencies, to evaluate major agency actions having the
potential to significantly impact the environment human, animal and plant
health, and affect our operations and costs. In recent years, environmental
regulations have taken a cradle-to-grave approach to waste management,
regulating and creating liabilities for the waste at its inception to final
disposition. Exploration, development and production of our properties are
subject to numerous environmental programs, some of which include solid and
hazardous waste management, water protection, air emission controls and controls
affecting wetlands, coastal operations and antiquities.





In the course of evaluations, an agency
will have an Environmental Assessment prepared that assesses the potential
direct, indirect and cumulative impacts of a proposed project and, if necessary,
will prepare a more detailed Environmental Impact Statement that may be made
available for public review and comment. All of the current exploration and
production activities on our properties, as well as proposed exploration and
development plans, on federal lands require governmental permits that are
subject to the requirements of NEPA. This process has the potential to delay the
development of our oil and natural gas projects.





In addition, environmental programs
typically regulate the permitting, construction and operations of a facility.
Many factors, including public perception, can materially impact the ability to
secure an environmental construction or operation permit. Once operational,
enforcement measures can include significant civil penalties for regulatory
violations regardless of intent. Under appropriate circumstances, an
administrative agency can request a cease and desist order to terminate
operations.





We conduct development and production
activities designed to comply with all applicable environmental regulations,
permits and lease conditions, including, monitoring subcontractors for
environmental compliance. While we believe operations of our properties conform
to those conditions, we remain at risk for inadvertent noncompliance, conditions
beyond our control and undetected conditions resulting from activities by prior
owners or other operators.  Pursuant to industry customs, we obtain
insurance policy coverage for each of the participants in a particular project
at a level of coverage that is commensurate with the potential
loss.





Waste
Handling





The Resource Conservation and Recovery
Act, or RCRA, and comparable state statutes, affect oil and natural gas
exploration and production activities by imposing regulations on the generation,
transportation, treatment, storage, disposal and cleanup of “hazardous wastes”
and on the disposal of non-hazardous wastes. Under the auspices of the
Environmental Protection Agency, or EPA, the individual states administer some
or all of the provisions of RCRA, sometimes in conjunction with their own, more
stringent requirements. Drilling fluids, produced waters, and most of the other
wastes associated with the exploration, development, and production of oil,
natural gas, or geothermal energy constitute “solid wastes,” which are regulated
under the less stringent non-hazardous waste provisions, but there is no
guarantee that the EPA or the individual states will not adopt more stringent
requirements for the handling of non-hazardous wastes or categorize some
non-hazardous wastes as hazardous for future regulation. Indeed, legislation has
been proposed from time to time in Congress to re-categorize certain oil and
natural gas exploration and production wastes as “hazardous
wastes”.





We believe that we are currently in
substantial compliance with the requirements of RCRA and related state and local
laws and regulations, and that they hold all necessary and up-to-date permits,
registrations and other authorizations to the extent that our operations require
them under such laws. We may be required in the future to make substantial
outlays to comply with environmental laws and regulations. The additional
changes in operating procedures and expenditures required to comply with future
laws dealing with the protection of the environment cannot be
predicted.





13




Occupational
Safety





In the conduct of our activities, our
operations will be subject to the requirements of the federal Occupational
Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard
communication standard, the EPA community right-to-know regulations under Title
III of the federal Superfund Amendment and Reauthorization


Act and
similar state statutes require us to organize information about hazardous
materials used, released or produced in its operations. Certain of this
information must be provided to employees, state and local governmental
authorities and local citizens. We are also subject to the requirements and
reporting set forth in OSHA workplace standards.





Insurance




We maintain insurance on our properties
and operations for risks and in amounts customary in the industry.  Such
insurance includes general liability, excess liability, control of well,
operators extra expense and casualty coverage.  Not all losses are insured,
and we retain certain risks of loss through deductibles, limits and
self-retentions.





Executive
Officers of the Company





Name
                      
                      Age
                      
                      PositionMichael
      J. Pawelek
                      
                      50
                      
                      Chairman,
      President and CEOWayne
      A. Psencik
                      
                      45
                      
                      Executive
      Vice President, Chief Operating OfficerSherry
      L. Spurlock
                      
                      47
                      
                      Executive
      Vice President, Chief Financial OfficerTheodore
      J. Wicks
                      
                      40
                      
                      Executive
      Vice President, Corporate DevelopmentRobert
      W. Kuehner
                      
                      60
                      
                      Vice
      President, Land ManagementEdward
      B. Shaw
                      
                      46
                      
                      Vice
      President,
Operations





Mr. Michael J. Pawelek has
been Chairman of the Board of Directors of the Company since November 2007 and
serves on the Board’s Executive committee. He has been Chief Executive Officer
and President of the Company since June 2008. In 1981, Mr. Pawelek began his
career as a geophysicist focused on the Austin Chalk trend with Clayton Williams
Company through 1985. From 1985 to 1989 he was employed by TXO Production
Corporation as a district geophysicist. In 1989, he founded CPX Petroleum, which
drilled over 60 wells under his management. From 1991 to 1999, he founded and
was the Chief Executive Officer of Universal Seismic Associates, Inc., which
generated annual revenue of $65 million and had over 400 employees. From 1999 to
2001, he served as Vice President of Operations of Amenix USA, Inc., a private
exploration and production company focused on oil and natural gas exploration in
Louisiana. From 2001 to 2004, he held a similar position at IBC Petroleum,
managing the company’s assets while seeking financial partners. From 2004 to
2007 he was President of BOSS Exploration & Production Corporation, a
privately held Gulf Coast production company. Immediately prior to joining the
Company as its CEO, Mr. Pawelek served as President of Sonterra Resources, Inc.,
a company that has oil and natural gas assets in Texas state waters in Matagorda
Bay. Mr. Pawelek received a BS degree in Engineering from Texas A&M
University.





Mr. Wayne A. Psencik is the
Executive Vice President and Chief Operating Officer and has served in such
capacity since June 2008. Mr. Psencik previously served
as Vice PresidentofOperations at Sonterra
Resources, Inc. and its predecessor companies, from April 2007 through June
2008. From 2005 to 2007, he held the position of Vice President of Operations of
Boss Exploration & Production Corporation. From 2001 to 2005, Mr. Psencik
served as an engineer and drilling manager at El Paso Production Company, where
he was responsible for the design and implementation of drilling and completion
operations and the supervision of staff engineers in the Gulf of Mexico unit.
From 1999 to 2001 he was a consulting drilling engineer for Coastal Oil and Gas
Company focused in the Gulf of Mexico. Mr. Psencik served as district manager
from 1996 to 1999 for Chesapeake Operating Company for its southern division.
From 1994 to 1996, Mr. Psencik held positions of drilling engineer for
Chesapeake Operating Company, focusing on horizontal drilling in Texas and
Louisiana. From 1991 to 1994, he was a drilling engineer working Gulf of Mexico
projects for AGIP Petroleum. Mr. Psencik earned his BS degree in petroleum
engineering from Texas A&M University.





Ms. Sherry L. Spurlock is the
Executive Vice President and Chief Financial Officer and has served in such
capacity since June 2008. Prior to joining our Company, Ms. Spurlock served as
Chief Financial Officer of Sonterra Resources, Inc. and its predecessor
companies, from April 2007 through June 2008. From 2005 to 2007, she was the
Chief Financial Officer of Boss Exploration & Production Corporation, where
she was responsible for the preparation of the financial statements and other
financial and accounting matters. From 2000 to 2005, Ms. Spurlock was the
controller and held various other financial positions with United Oil &
Minerals, LP, a private oil and natural gas exploration company. From 1992 to
2000, Ms. Spurlock served as Controller at Brigham Exploration Company, an
Austin, Texas-based publicly traded exploration and production company. While at
Brigham, she was responsible for the SEC reporting and internal management
reporting among other audit and accounting systems management. Prior to that,
she held accounting positions at private and public oil and natural gas
companies and began her career as an accountant at Deloitte, Haskins and Sells.
Ms. Spurlock is a certified public accountant and holds a BBA degree in
accounting from Stephen F. Austin State University.





14




Mr. Theodore J. Wicks is the
Executive Vice President of Corporate Development and has served in such
capacity since October 2008. Prior to joining our Company, Mr. Wicks was a
Managing Director with Petro Capital Securities, LLC (“PCS”), a Dallas-based
energy investment bank, since 2007. Mr. Wicks’ responsibilities at PCS included
client coverage and leading the structuring and execution of a wide variety of
M&A, strategic advisory and capital markets transactions for clients across
all sectors of the energy industry. Prior to PCS, Mr. Wicks was a Vice President
in the energy investment banking group of First Albany Capital. From 2006 to
2007, Mr. Wicks was a Vice President in the energy investment banking group of
Sanders Morris Harris. From 2004 to 2005, Mr. Wicks was a Director in the Equity
Capital Markets group at KeyBanc Capital Markets, and from 1999 through 2003,
Mr. Wicks was a Vice President in the Equity Capital Markets group of RBC
Capital Markets. Mr. Wicks earned his Masters of Business Administration in
Finance and Bachelor of Arts with Accounting and Finance concentrations from the
University of St. Thomas.





Mr. Robert W. Kuehner is the
Vice President of Land Management and has served in such capacity since August
2008. From 1985 to 2008, Mr. Kuehner formed Bob Kuehner & Co., an
independent oil and natural gas broker company. From 1983 to 1985, Mr. Kuehner
was a District Landman for Clayton Williams Company covering their Giddings
field Austin Chalk play. From 1981 to 1983, Mr. Kuehner joined Hilliard Oil and
Gas Co. managing all exploration and land activities for their San Antonio and
Midland offices.  From 1979 to 1981, he held the position of District
Landman for Suburban Propane Gas in San Antonio, Texas. From 1970 to 1975, Mr.
Kuehner worked as a landman covering East Texas and South Texas activities for
Union Oil Company of California in both their Houston and Corpus Christi
offices. Mr. Kuehner has 39 years of experience in the oil and natural gas
industry and holds a BBA degree in Petroleum Land Management from University of
Texas.





Mr. Edward B. Shaw is the
Vice President of Operations and has served in such capacity since June
2008.  From December 2005 to June 2008, Mr. Shaw served as Chief
Operating Officer for the Company. Mr. Shaw is trained as an electrical engineer
with over 10 years of energy related experience in Saudi Arabia. While in Saudi
Arabia, Mr. Shaw researched and developed methods of monitoring oil and natural
gas wells to optimize production, including using existing products integrated
with emerging telemetry technologies.  Mr. Shaw has a HND degree in
electrical engineering.





Employees





As of December 31, 2008, we
employed approximately 15 personnel.  We believe that our relationship
with our employees is satisfactory. None of our employees are represented by
labor unions or covered by any collective bargaining agreement.





Principal ExecutiveOffices





The Company is a Nevada incorporated
company with headquarters in San Antonio, Texas.  Our principal
offices are located at 300 East Sonterra Boulevard, Suite 1220, San Antonio,
Texas 78258, telephone number (210) 545-5994, fax number (210) 545-3317. We also
maintain a field exploration and/or production office in Giddings,
Texas.





Company
Website





The
Company’s internet website is www.southtexasoil.com.Information
on the Company’s website should not be considered a part of, or incorporated by
reference into, this Annual Report on Form 10-K.





Corporate
Governance Matters





Our website is www.southtexasoil.com. Under
the Corporate Governance tab interested parties may find copies of our Audit
Committee Charter, our Compensation and Human Resources Committee Charter, our
Corporate Governance and Nominating Committee Charter, our Corporate Governance
Policy, and our Code of Business Conduct and Ethics.





Access
to Company Reports





For
further information pertaining to us, interested parties may inspect without
charge at the public reference facilities of the SEC at 100 F Street, NE, Room
1580, Washington, D.C. 20549 any of our filings with the SEC. Copies of all or
any portion of the documents may be obtained by calling the SEC at
1-800-732-0330. In addition, the SEC maintains a website that contains reports,
proxy and information statements and other information that is filed
electronically with the SEC. The website can be accessed at www.sec.gov.





15




Forward
Looking Statements





This
Annual Report on Form 10-K (the “Annual Report”) contains “forward-looking
statements” that represent our beliefs, projections and predictions about future
events. All statements other than statements of historical fact are
“forward-looking statements,” including any projections of earnings, revenue or
other financial items, any statements of the plans, strategies and objectives of
management for future operations, any statements concerning proposed new
projects or other developments, any statements regarding future economic
conditions or performance, any statements of management’s beliefs, goals,
strategies, intentions and objectives, and any statements of assumptions
underlying any of the foregoing. Words such as “may,” “will,” “should,” “could,”
“would,” “predicts,” “potential,” “continue,” “expects,” “anticipates,”
“future,” “intends,” “plans,” “believes,” “estimates” and similar expressions,
as well as statements in the future tense, identify forward-looking
statements.





These
statements are necessarily subjective and involve known and unknown risks,
uncertainties and other important factors that could cause our actual results,
performance or achievements, or industry results, to differ materially from any
future results, performance or achievements described in or implied by such
statements. Actual results may differ materially from expected results described
in our forward-looking statements, including with respect to correct measurement
and identification of factors affecting our business or the extent of their
likely impact, the accuracy and completeness of the publicly available
information with respect to the factors upon which our business strategy is
based or the success of our business. Furthermore, industry forecasts are likely
to be inaccurate, especially over long periods of time and in relatively new and
rapidly developing industries such as oil and natural gas. Factors that may
cause actual results, our performance or achievements, or industry results, to
differ materially from those contemplated by such forward-looking statements
include without limitation:





·
            our
      ability to attract and retain
management;


·
            our
      business and growth strategies;


·
            anticipated
      trends in our business;


·
            our
      future results of operations;


·
            our
      oil and natural gas reserve
estimates;


·
            our
      ability to make or integrate
acquisitions;


·
            our
      liquidity and ability to finance our exploration, acquisition and
      development activities;


·
            the
      volatility in commodity prices for oil and natural
  gas;


·
            our
      ability to successfully and economically explore for and develop oil and
      natural gas resources;


·
            market
      conditions in the oil and natural gas
industry;


·
            the
      timing, cost and procedure for
acquisitions;


·
            the
      impact of government regulation;


·
            estimates
      regarding future net revenues from oil and natural gas reserves and the
      present value thereof;


·
            planned
      capital expenditures (including the amount and nature
      thereof);


·
            increases
      or decreases in oil and natural gas
production;


·
            the
      number of wells we anticipate being drilled in the
  future;


·
            estimates,
      plans and projections relating to acquired
  properties;


·
            the
      number of potential drilling locations on lands in which we have an
      interest;


·
            our
      financial position, business strategy and other plans and objectives for
      future operations;


·
            the
      possibility that our acquisitions may involve unexpected
      costs;


·
            the
      accuracy of internally estimated proved
  reserves;


·
            the
      presence or recoverability of estimated oil and natural gas
      reserves;


·
            the
      ability to replace oil and natural gas
reserves;


·
            the
      availability and costs of drilling rigs and other oilfield
      services;


·
            unsuccessful
      drilling;


·
            environmental
      risks;


·
            exploration
      and development risks;


·
            competition;


·
            the
      ability of our management team to execute its plans to meet its goals;
      and




16




·
            other
      economic, competitive, governmental, legislative, regulatory, geopolitical
      and technological factors that may negatively impact our businesses,
      operations and pricing.




Forward-looking statements should not
be read as a guarantee of future performance or results, and will not
necessarily be accurate indications of whether, or the times by which, our
performance or results may be achieved. Forward-looking statements are based on
information available at the time those statements are made and management’s
belief as of that time with respect to future events, and are subject to risks
and uncertainties that could cause actual performance or results to differ
materially from those expressed in or suggested by the forward-looking
statements. Important factors that could cause such differences include, but are
not limited to, those factors discussed under the headings “Risk Factors,”
“Management’s Discussion and Analysis of Financial Condition and Results of
Operations,” “Business” and elsewhere in this report.All forward-looking
statements speak only as of the date of this annual report. We do not intend to
publicly update or revise any forward-looking statements as a result of new
information, future events or otherwise. These cautionary statements qualify all
forward-looking statements attributable to us or persons acting on our
behalf.





Current
Economic Conditions





The recent worldwide financial and
credit crisis has reduced the availability of liquidity and credit to fund the
continuation and expansion of many business operations. The shortage of
liquidity and credit combined with recent substantial losses in equity markets
has led to a worldwide economic recession. The slowdown in economic activity
caused by such recession has reduced worldwide demand for energy resulting in
lower oil and natural gas prices. Oil prices declined from record levels in
early July 2008 of over $140 per barrel to below $40 per barrel in December
2008, while natural gas prices have declined from over $13 per Mcf to below $6
per Mcf over the same period.




Lower oil and natural gas prices not
only decrease our revenues but also reduce the amount of oil and natural gas
that we can produce economically over the life of the wells, and therefore lower
our oil and natural gas reserves recorded in accordance with guidelines
established by the SEC. A substantial or extended decline in oil or natural gas
prices may materially and adversely affect our future business, financial
condition, results of operations, liquidity or ability to finance planned
capital expenditures. Our current working capital and commodity prices received
from production are insufficient to fund our 2009 budget, and as a result we may
be required to reduce capital spending, issue equity or debt, sell a portion of
our properties, or enter into joint ventures.




Securities
Act Disclaimer





This Form
10-K does not constitute an offer to sell or the solicitation of an offer to buy
any securities.





ITEM
1A.        RISK FACTORS





Our business activities and the value
of our securities are subject to significant hazards and risks, including those
described below. You should carefully consider the risks described below as
well as other information provided to you in this document, including
information in the section of this document entitled “Information Regarding
Forward Looking Statements.” The risks and uncertainties described below are not
the only ones that we face. Additional risks and uncertainties not presently
known to us or that we currently believe are immaterial may also impair our
business operations. If any of the following risks actually occur, our business,
financial condition or results of operations could be materially adversely
affected, the value of our common stock could decline, and you may lose all or
part of your investment. Additional risks relating to our securities may be
included in the prospectuses for securities we issue in the future.





Risks
Related to Our Business





We
have incurred significant losses and anticipate that we will continue to incur
losses for the foreseeable future.





In the fiscal years ended December 31,
2008 and 2007, we incurred net losses after taxation of approximately $19.7
million and $6.6 million, respectively. There is no assurance that we will be
able to successfully achieve an increase in production and reserves so as to
operate in a profitable manner. If the business of oil and natural gas well
exploration and development slows, and commodity prices notably decline, our
margins and profitability will suffer. We are unable to predict whether our
operating results will be profitable. Our operations have consumed a substantial
amount of cash since inception. We expect to continue to spend substantial
amounts to:





17


·
            identify
      and exploit oil and natural gas
opportunities;


·
            maintain
      and increase the company’s human resource including full time and
      consultant resources;


·
            evaluate
      drilling opportunities;


·
            identify
      acquisition candidates; and


·
            evaluate
      future projects and areas for long term
  development.





We
expect to have increased cash requirements to fund our operations and
growth.





We expect
that our cash requirement for operations will increase significantly over the
next several years. We will be required to raise additional capital to meet
anticipated needs. Our future funding requirements will depend on many factors,
including, but not limited to:





·
            success
      of ongoing operations;


·
            forward
      commodity prices; and


·
            operating
      costs (including human resource
costs).





The growth of our business will require
substantial capital on a continuing basis. We use debt to fund a portion of our
acquisition activities and we will likely use debt to fund a portion of our
future acquisition activities.  To date, our sources of cash for
operations have also been primarily limited to the issuance of debt and the sale
of equity securities. We cannot be certain that additional funding will be
available on acceptable terms, or at all. To the extent that we raise additional
funds by issuing equity securities or securities that are convertible or
exchangeable for shares of our common stock, our stockholders may experience
significant dilution. Any debt financing, if available, may involve restrictive
covenants that impact our ability to conduct our business. If we are unable to
raise additional capital, when required, or on acceptable terms, our growth will
be limited and we may have to significantly delay, scale back or discontinue our
operations, or cause our business to fail in its entirety.





We
have a substantial amount of indebtedness, which may adversely affect our cash
flow and our ability to operate our business, remain in compliance with debt
covenants and make payments on our debt.





As of
December 31, 2008, our total secured debt was approximately $41.3 million.
We also have various commitments for operating leases, drilling contracts and
transportation and purchase obligations for services and products. Our level of
debt could have important consequences, including the following: it may be more
difficult for us to satisfy our obligations with respect to our indebtedness,
and any failure to comply with the obligations of any of our debt agreements,
including financial and other restrictive covenants, could result in an event of
default under the indenture with Longview Marquis Master Fund, governing our
senior notes and the agreements governing our other indebtedness; we may have
difficulty borrowing money in the future for acquisitions, capital expenditures
or to meet our operating expenses or other general corporate obligations; the
amount of our interest expense may increase because certain of our borrowings
are at variable rates of interest; we will need to use a substantial portion of
our cash flows to pay principal and interest on our debt, which will reduce the
amount of money we have for operations, working capital, capital expenditures,
expansion, acquisitions or general corporate or other business activities; we
may have a higher level of debt than some of our competitors, which may put us
at a competitive disadvantage; we may be more vulnerable to economic downturns
and adverse developments in our industry or the economy in general, especially
declines in oil and natural gas prices; and our debt level could limit our
flexibility in planning for, or reacting to, changes in our business and the
industry in which we operate.





Our ability to meet our expenses and
debt obligations will depend on our future performance, which will be affected
by financial, business, economic, regulatory and other factors. We will be
unable to control many of these factors, such as economic conditions and
governmental regulation. We cannot be certain that our earnings will be
sufficient to allow us to pay the principal and interest on our debt and meet
our other obligations. For instance, approximately $7.0 million of our debt
matures and becomes payable on September 2009 and approximately $34.3
million of our notes outstanding under our credit facility mature and
becomes payable on December 2009. We believe that based on our current
production levels and prices for oil and natural gas, our cash flows from
operations, may not be sufficient to fully repay the debt when due without
further reductions in our capital expenditure levels or non-strategic asset
sales. If we do not have enough money to service our debt, we may be required
but unable to refinance all or part of our existing debt, sell assets, borrow
more money or raise equity on terms acceptable to us, if at all. Further,
failing to comply with the financial and other restrictive covenants in our
credit agreements and the Indenture governing our senior notes could result in
an event of default, which could adversely affect our business, financial
condition and results of operations.





18




We
may incur substantially more debt, which may intensify the risks described
herein, including our ability to service our indebtedness.





Together
with our subsidiaries, we may incur substantially more debt in the future in
connection with our acquisition, development, exploitation and exploration of
oil and natural gas producing properties. The restrictions in our debt
agreements on our incurrence of additional indebtedness are subject to a number
of qualifications and exceptions, and under certain circumstances, indebtedness
incurred in compliance with these restrictions could be substantial. Also, these
restrictions do not prevent us from incurring obligations that do not constitute
indebtedness. To the extent new indebtedness is added to our current
indebtedness levels, the risks described above could substantially
increase.





Restrictive
debt covenants could limit our growth and our ability to finance our operations,
fund our capital needs, respond to changing conditions and engage in other
business activities that may be in our best interests.





As of
December 31, 2008, we had approximately $41.3 million of total secured debt
outstanding under our credit facility and senior secured notes. Our credit
facility and senior secured notes generally contain customary covenants,
including, among others, provisions relating to the maintenance of the oil and
natural gas properties securing the debt; and restricting our ability to assign
or further encumber the properties securing the debt. In addition, our credit
facility requires us to maintain certain financial and production
covenants.





As of the date of this report, we were
in compliance with all such covenants. If we were to breach any of our debt
covenants and not cure the breach within any applicable cure period, the lender
could require us to repay the debt immediately, if that should occur, we may be
unable to pay all such debt or to borrow sufficient funds to refinance it. Even
if new financing were then available, it may not be on terms that are acceptable
to us. To the extent such debt is secured, upon default the lender could
immediately begin proceedings to take possession of the properties securing the
credit facility. Any such property loss would materially and adversely affect
our cash flow and results of operations.





The
global financial and credit crisis and any associated prolonged decline in the
price of oil and natural gas will likely limit our access to liquidity and
credit and curtail our ability to fund our planned exploration, developments,
and production activity, which could adversely affect our business, financial
condition and results of operations.





The
global financial and credit crisis has reduced the availability of liquidity and
credit to fund the continuation and expansion of industrial business operations
worldwide. Significant write-offs in the financial services sector, the
repricing of credit risk and the current weak economic conditions have made it
difficult, and will likely continue to make financing difficult. As a result of
concerns about the stability of financial markets generally and the solvency of
counterparties specifically, the cost of obtaining money from the credit markets
generally has increased as many lenders and institutional investors have
increased interest rates and enacted tighter lending standards. As a result of
the current credit environment, we may be unable to obtain additional funding
under our existing credit agreements. In addition, the current disruption in the
financial markets has reduced the likelihood that we could successfully issue
common stock or other equity-related securities to fund our operations and
growth.





The shortage of liquidity and credit
combined with recent substantial losses in worldwide equity markets has lead to
an extended national or global economic recession. A slowdown in economic
activity caused by a recession would likely reduce national and worldwide demand
for energy and result in lower oil and natural gas prices. Our revenues, cash
flow and profitability and our ability to maintain or increase our borrowing
capacity, to repay current or future indebtedness and to obtain additional
capital on attractive terms depend substantially upon oil and natural gas
prices. Prolonged decline in the price of oil and natural gas will likely limit
our access to liquidity and credit and curtail our ability to fund our planned
exploration, development, and production activity, which could adversely affect
our business, financial condition and results of operations.





Oil
and natural gas prices are volatile and low prices could have a material adverse
impact on our business.





Our
revenues, profitability and future growth and the carrying value of our
properties depend substantially on prevailing oil and natural gas prices. Prices
also affect the amount of cash flow available for capital expenditures and our
ability to borrow and raise additional capital. The amount we will be able to
borrow under any senior revolving credit facility will be subject to periodic
redetermination based in part on changing expectations of future prices. Lower
prices may also reduce the amount of oil and natural gas that we can
economically produce and have an adverse effect on the value of our properties.
Prices for oil and natural gas have increased significantly and have been more
volatile over the past twelve months. Historically, the markets for oil and
natural gas have been volatile, and they are likely to continue to be volatile
in the future. Among the factors that can cause volatility are:




19




·
              the
      domestic and foreign supply of oil and natural
  gas;


·
                the
      ability of members of the Organization of Petroleum Exporting Countries,
      or OPEC, and other producing
      countries to agree upon and maintain oil prices and production
      levels;


·
                political
      instability, armed conflict or terrorist attacks, whether or not in oil or
      natural gas producing
regions;


·
              the
      selling price and production costs of
gasoline;


·
              the
      level of consumer product
demand;


·
              the
      growth of consumer product demand in emerging markets, such as
      China;


·
              labor
      unrest in oil and natural gas producing
regions;


·
              weather
      conditions, including hurricanes and other natural
    disasters;


·
              the
      price and availability of alternative
fuels;


·
              the
      price of foreign imports;


·
              worldwide
      economic conditions; and


·
            the
      availability of liquid natural gas
imports.





These external factors and the volatile
nature of the energy markets make it difficult to estimate future prices of oil
and natural gas and our ability to raise capital.





Oil
and natural gas development, re-completion of wells from one reservoir to
another reservoir, restoring wells to production and drilling and completing new
wells are speculative activities and involve numerous risks and substantial and
uncertain costs.





Our
growth will be materially dependent upon the success of our future development
program.  Drilling for oil and natural gas and re-working existing wells
involve numerous risks, including the risk that no commercially productive oil
or natural gas reservoirs will be encountered.  The cost of drilling,
completing and operating wells is substantial and uncertain, and drilling
operations may be curtailed, delayed or cancelled as a result of a variety of
factors beyond our control, including:




·
            unexpected
      drilling conditions;


·
            pressure
      fluctuations or irregularities in
formations;


·
            equipment
      failures or accidents;


·
            inability
      to obtain leases on economic terms, where
  applicable;


·
            adverse
      weather conditions;


·
            compliance
      with governmental requirements; and


·
            shortages
      or delays in the availability of drilling rigs or crews and the delivery
      of equipment.




Drilling
or re-working is a highly speculative activity.  Even when fully and
correctly utilized, modern well completion techniques such as hydraulic
fracturing and horizontal drilling do not guarantee that we will find oil and/or
natural gas in our wells.  Our future drilling activities may not be
successful and, if unsuccessful, such failure would have an adverse affect on
our future results of operations and financial condition.  We cannot assure
you that our overall drilling success rate or our drilling success rate for
activities within a particular geographic area will not decline.  We may
identify and develop prospects through a number of methods, some of which do not
include hydraulic fracturing and horizontal drilling, and some of which may be
unproven.  The drilling and results for these prospects may be particularly
uncertain.  Our drilling schedule and costs may vary from our capital
budget.  The final determination with respect to the drilling of any
scheduled or budgeted prospects will be dependent on a number of factors,
including, but not limited to:





·
            the
      results of previous development efforts and the acquisition, review and
      analysis of data;


·
            the
      availability of sufficient capital resources to us and the other
      participants, if any, for the drilling of the
  prospects;


·
            the
      approval of the prospects by other participants, if any, after additional
      data has been compiled;


·
            economic
      and industry conditions at the time of drilling, including prevailing and
      anticipated prices for oil and natural gas and the availability of
      drilling rigs and crews;


·
            our
      financial resources and results;


·
            the
      availability of leases and permits on reasonable terms for the prospects;
      and


·
            the
      success of our drilling technology.




20




We cannot
assure you that these projects can be successfully developed or that the wells
discussed will, if drilled, encounter reservoirs of commercially productive oil
or natural gas.  There are numerous uncertainties in estimating quantities
of proved reserves, including many factors beyond our control.





Unless
we replace our oil and natural gas reserves, primarily oil reserves, our
reserves and production will decline, which would adversely affect our cash
flows and income.





Successful
development and production of those reserves cannot be assured. Additional
drilling or workovers will be necessary in future years both to maintain
production levels and to define the extent and recoverability of existing
reserves. Our present wells may not continue to produce at current or
anticipated rates of production, development drilling may not be successful,
production of oil or natural gas may not commence when expected, and there may
be unfavorable markets for oil and natural gas produced in the
future.  If we are unable to develop or produce reserves for continued
production at current rates, we may become unprofitable or cease
business.





We
are subject to complex laws and regulations that can adversely affect the cost,
manner and feasibility of doing business.





Our
operations are directly or indirectly subject to extensive and continually
changing regulation affecting the oil and natural gas industry. Many departments
and agencies, both federal, state and local, are authorized by statute to issue,
and have issued, rules and regulations binding on the oil and natural gas
industry and our individual participants. The failure to comply with such rules
and regulations can result in substantial penalties. The regulatory burden on
the oil and natural gas industry increases our cost of doing business and,
consequently, affects our profitability.





If operations of our properties are
found to be in violation of any of the laws and regulations to which we are
subject, we may be subject to the applicable penalty associated with the
violation, including civil and criminal penalties, damages, fines and the
curtailment of operations. Any penalties, damages, fines or curtailment of
operations, individually or in the aggregate, could adversely affect our ability
to operate our business and our financial results. In addition, many of these
laws and regulations have not been fully interpreted by the regulatory
authorities or the courts, and their provisions are open to a variety of
interpretations. Any action against us for violation of these laws or
regulations, even if we successfully defend against it, could cause us to incur
significant legal expenses and divert management’s attention from the operation
of our business.





Our
operations and properties are also subject to numerous federal, state and local
laws and regulations specifically relating to environmental protection from the
time projects commence until abandonment. These laws and regulations govern,
among other things: the amounts and types of substances and materials that may
be released; the issuance of permits in connection with exploration, drilling
and production activities; the protection of endangered species; the release of
emissions; the discharge and disposition of generated waste materials; offshore
oil and natural gas operations; the reclamation and abandonment of wells and
facility sites; and the remediation of contaminated sites. In addition, these
laws and regulations may impose substantial liabilities for our failure to
comply with them or for any contamination resulting from our operations. Future
environmental laws and regulations, such as proposed legislation regulating
climate change, may negatively impact our industry. The cost of meeting these
requirements may have an adverse effect on our financial condition, results of
operations and cash flows.





We
are vulnerable to risks associated with operating in the shallow Texas state
waters that could negatively impact our operations and financial
results.





Our
operations and financial results could be significantly impacted by conditions
in the shallow Texas state waters because we explore and produce in that area.
As a result of this activity, we are vulnerable to the risks associated with
operating in the shallow Texas state waters, including those relating to:
hurricanes and other adverse weather conditions; oil field service costs and
availability; compliance with environmental and other laws and regulations;
remediation and other costs resulting from oil spills or releases of hazardous
materials; and failure of equipment or facilities. In addition, we are currently
conducting some of our exploration in the shallow Texas state waters, where
operations are more difficult and costly than on land. Further, production of
reserves from reservoirs in the shallow Texas state waters generally declines
more rapidly than from reservoirs in many other producing regions of the world.
This results in recovery of a relatively higher percentage of reserves from
properties in the shallow Texas state waters during the initial few years of
production and, as a result, our reserve replacement needs from new prospects
may be greater there than for our operations elsewhere. Also, our revenues and
return on capital will depend significantly on prices prevailing during these
relatively short production periods.





21




We
may experience a financial loss if any of our significant customers fail to pay
us for our oil or natural gas and to the extent these customers reduce the
volumes they purchase from us.





We depend
on certain key customers for sales of our oil, natural gas and NGL. For the year
ended December 31, 2008, sales of oil, natural gas and NGLs to Texon
Corporation, DCP Midstream Partners LP, Energy Transfer Partners, LP, and Shell
Trading (US) Company accounted for approximately 70%, 13%, 3%, and 2%,
respectively, of the Company’s total revenue, or 88% in the aggregate. Our
ability to collect the proceeds from the sale of oil and natural gas from our
customers depends on the payment ability of these and other customers. If any
one or more of our significant customers fails to pay us for any reason, we
could experience a material loss. In addition, in recent years, a number of
energy marketing and trading companies have discontinued their marketing and
trading operations, which has significantly reduced the number of potential
purchasers for our oil and natural gas production. This reduction in potential
customers has reduced market liquidity and, in some cases, has made it difficult
for us to identify creditworthy customers. We may experience a material loss as
a result of the failure of our customers to pay us for prior purchases of our
oil or natural gas. Furthermore, the loss of any significant customer may cause
a temporary interruption in sales of, or a lower price for, our oil and natural
gas that could have a significant negative impact on our business. If that were
to happen, it may not be possible for us to immediately obtain replacement oil
and natural gas purchasers as the industry is extremely
competitive.





Many
of our leases are in areas that have been partially depleted or drained by
offset wells.




Many of our key project areas are
located in the Giddings Field, which has produced approximately 1.6 billion Boe
since drilling began there in the 1960’s. As a result, many of our leases
are in areas that have already been partially depleted or drained by earlier
offset drilling. This may inhibit our ability to find economically
recoverable quantities of reserves in these areas. Our identified drilling
location inventories are scheduled out over several years, making them
susceptible to uncertainties that could materially alter the occurrence or
timing of their drilling, resulting in temporarily lower cash from operations,
which may impact our ability to pay distributions.




Our management has specifically
identified and scheduled drilling locations as an estimation of our future
multi-year drilling activities on our existing acreage. As of
December 31, 2008, we had identified 27 lateral development well locations
with redevelopment and re-completion potential on our leased acreage in the
Giddings Field. These identified drilling locations represent a significant
part of our growth strategy. Our ability to drill and develop these
locations depends on a number of factors, including the availability of capital,
seasonal conditions, regulatory approvals, oil, natural gas and NGL prices,
costs and drilling results. Our final determination on whether to drill any
of these drilling locations will be dependent upon the factors described above
as well as, to some degree, the results of our drilling activities with respect
to our proved drilling locations.  Because of these uncertainties, we
do not know if the numerous drilling locations we have identified will be
drilled within our expected timeframe or will ever be drilled or if we will be
able to produce oil, natural gas and NGL from these or any other potential
drilling locations.  As such, our actual drilling activities may
materially differ from those presently identified, which could adversely affect
our business.





Estimates
of oil and natural gas reserves are uncertain and any material inaccuracies in
these reserve estimates will materially affect the quantities and the value of
our reserves.





This
Annual Report contains estimates of our proved oil and natural gas reserves.
These estimates are based upon various assumptions, including assumptions
required by the SEC relating to oil and natural gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds. The
process of estimating oil and natural gas reserves is complex. This process
requires significant decisions and assumptions in the evaluation of available
geological, geophysical, engineering and economic data for each
reservoir.





Actual future production, oil and
natural gas prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable oil and natural gas reserves will vary
from those estimated. Any significant variance could materially affect the
estimated quantities and the value of our reserves. Our properties may also be
susceptible to hydrocarbon drainage from production by other operators on
adjacent properties. In addition, we may adjust estimates of proved reserves to
reflect production history, results of exploration and development, prevailing
oil and natural gas prices and other factors, many of which are beyond our
control.





22


Although we have prepared estimates of
these oil and natural gas reserves and the costs associated with development of
these reserves in accordance with SEC regulations, we cannot assure you that the
estimated costs or estimated reserves are accurate, that development will occur
as scheduled or that the actual results will be as estimated. Accordingly,
reserve estimates may be subject to downward or upward adjustment. The
information regarding discounted future net cash flows included in this report
should not be considered as the current market value of the estimated oil and
natural gas reserves attributable to our properties. As required by the SEC, the
estimated discounted future net cash flows from proved reserves are based on
prices and costs as of the date of the estimate, while actual future prices and
costs may be materially higher or lower. Actual future net cash flows also will
be affected by factors such as the amount and timing of actual production,
supply and demand for oil and natural gas, increases or decreases in
consumption, and changes in governmental regulations or taxation. In addition,
the 10% discount factor, which is required by the SEC to be used in calculating
discounted future net cash flows for reporting purposes, is not necessarily the
most appropriate discount factor based on interest rates in effect from time to
time and risks associated with us or the oil and natural gas industry in
general.





Future
hedging activities may prevent us from realizing the benefits in oil or natural
gas price increases.





As of the
date of this report, we have no hedge positions in place. All hedge positions
were closed out in December 2008. However, in an attempt to reduce our
sensitivity to oil and natural gas price volatility, in the future we may enter
into hedging transactions which may include fixed price swaps, price collars,
puts and other derivatives. In a typical hedge transaction, we may fix the
price, a floor or a range, on a portion of our production over a predetermined
period of time. There are numerous risks associated with hedging activities such
as the risk that reserves are not produced at rates equivalent to the hedged
position, and the risk that production and transportation cost assumptions used
in determining an acceptable hedge could be substantially different from the
actual cost. In addition, the counter-party to the hedge may become unable or
unwilling to perform its obligations under hedging contracts, and we could incur
a material adverse financial effect if there is any significant non-performance.
While intended to reduce the effects of oil and natural gas price volatility,
hedging transactions may limit potential gains earned by us from oil and natural
gas price increases and may expose us to the risk of financial loss in certain
circumstances, including instances in which our production is less than the
hedged volumes, there is a widening of price basis differentials between
delivery points for our production and the delivery point assumed in the hedge
arrangement, or a sudden unexpected event materially impacts oil and natural gas
prices. Engaging in hedging activities may prevent us from realizing the
benefits of price increases above the levels of the hedges during certain time
periods





We
may be unable to effectively maintain our oil and natural gas exploration
business.





Timely,
effective and successful oil and natural gas exploration and production is
essential to maintaining our reputation as an oil and natural gas exploration
and production company. Lack of opportunities or success may significantly
affect our viability. The principal components of our operating costs include
salaries paid to corporate staff, costs of retention of qualified independent
engineers and geologists, annual system maintenance and rental costs, insurance,
transportation costs and substantial equipment and machinery costs. Because the
majority of these expenses are fixed, a reduction in the number of successful
oil exploration projects, failures in discovery of new opportunities or
termination of ongoing projects will result in lower revenues and margins. Prior
success in exploration or production of wells does not guarantee future success
in similar ventures; thus, our revenues could decline and our ability to
effectively engage in oil recovery business would be harmed.





Loss
of key executives and failure to attract qualified managers, technologists,
independent engineers and geologists could limit our growth and negatively
impact our operations.





We depend
upon our management team to a substantial extent. In particular, we depend upon
Mr. Michael J. Pawelek, our Chairman, President and Chief Executive Officer, Mr.
Wayne A. Psencik, our Chief Operating Officer, Ms. Sherry L. Spurlock, our Chief
Financial Officer, Mr. Theodore J. Wicks, our Executive Vice President of
Corporate Development, Mr. Robert W. Kuehner, our Vice President of Land
Management, and Mr. Edward D. Shaw, our Vice President of Operations, for their
skills, experience, and knowledge of the company and industry contacts. The loss
of any of these executives, or other members of our management team, could have
a material adverse effect on our business, results of operations or financial
condition.





23


As we grow, we may increasingly require
field managers with experience in our industry and skilled engineers, geologists
and technologists to operate our diagnostic, seismic and 3D equipment. It is
impossible to predict the availability of qualified managers, technologists,
skilled engineers and geologists or the compensation levels that will be
required to hire them. In particular, there is a very high demand for qualified
technologists who are particularly necessary to operate systems similar to the
ones that we operate.  We may not be able to hire and retain a
sufficient number of technologists, engineers and geologists and we may be
required to pay bonuses and higher independent contractor rates to our
technologists, engineers and geologists which would increase our expenses. The
loss of the services of any member of our senior management or our inability to
hire qualified managers, technologists, skilled engineers and geologists at
economically reasonable compensation levels could adversely affect our ability
to operate and grow our business.





We
will need to increase the size of our organization, and may experience
difficulties in managing growth.





We are a
small company with 15 employees as of December 31, 2008. We expect to experience
a period of expansion in headcount, facilities, infrastructure and overhead and
anticipate that further expansion will be required to address potential growth
and market opportunities. Future growth will impose significant added
responsibilities on members of management, including the need to identify,
recruit, maintain and integrate additional independent contractors and managers.
Our future financial performance and our ability to compete effectively will
depend, in part, on our ability to manage any future growth
effectively.





Assets
we acquire may prove to be worth less than we paid because of uncertainties in
evaluating recoverable reserves and potential liabilities.





We expect
acquisitions will contribute to our future growth, but we cannot assure that we
will recover the costs we incur in acquiring oil and natural gas properties.
Successful acquisitions require an assessment of a number of factors, including
estimates of recoverable reserves, exploration potential, future oil and natural
gas prices, operating and capital costs and potential environmental and other
liabilities. Such assessments are inexact and their accuracy is inherently
uncertain. There can be no assurance that any properties we acquire will be
economically produced or developed. Re-engineering operations pose the risk that
anticipated benefits, which may include reserve additions, production rate
improvements or lower recurring operating expenses, may not be achieved, or that
actual results obtained may not be sufficient to recover
investments.





In
connection with our assessments of the properties we acquire, we perform a
review which we believe is generally consistent with industry practices.
However, such a review will not reveal all existing or potential problems. In
addition, our review may not permit us to become sufficiently familiar with the
properties to fully assess their deficiencies and capabilities. We do not
inspect every well. Even when we inspect a well, we do not always discover
structural, subsurface and environmental problems that may exist or arise. We
may not be able to obtain contractual indemnities from the seller for the
liabilities that it created, or we may be required to assume the risk of the
physical condition of the properties in addition to the risk that the properties
may not perform in accordance with our expectations. Even if a seller agrees to
provide indemnity, the indemnity may not be fully enforceable and may be limited
by floors and caps on such indemnity. The indemnifications we received in the
Leexus Acquisition are subject to floors, caps and time limitations and do
not cover all these types of risks.





As a result of these factors, we may
not be able to acquire oil and natural gas properties that contain economically
recoverable reserves or be able to complete such acquisitions on acceptable
terms.





We
may have write-downs of our asset values, which could negatively affect our
results of operations and net worth.





We follow
the successful efforts method of accounting for our oil and natural gas
properties. We are required to periodically review our oil and gas assets for
impairment. If oil, natural gas and NGLs prices remain depressed or continue to
decline, we may be required to write-down the value of our oil and natural gas
properties. Such non-cash asset impairments could negatively affect our results
of operations





Title
to the properties in which we have an interest may be impaired by title
defects.





We generally obtain title opinions on
significant properties in which we have working interests. However, there is no
assurance that we will not suffer a monetary loss from title defects or failure.
Generally, under the terms of the operating agreements affecting our properties,
any monetary loss is to be borne by all parties to any such agreement in
proportion to their interests in such property. If there are any title defects
or defects in assignment of leasehold rights in properties in which we hold an
interest, we will suffer a financial loss.





24




The
unavailability or high cost of drilling rigs, equipment, supplies, personnel and
oil field services could adversely affect our ability to execute our exploration
and development plans on a timely basis and within our budget.





Our
industry is cyclical and, from time to time, there is a shortage of drilling
rigs, equipment, supplies or qualified personnel for the operator of our
properties. During these periods, the costs and delivery times of rigs,
equipment and supplies are substantially greater. In addition, the demand for,
and wage rates of, qualified drilling rig crews rise as the number of active
rigs in service increases. Increasing levels of exploration and production in
response to any future increases in the prices of oil and natural gas may result
in rising demand for oilfield services, in which case the costs of these
services may increase while the quality of these services may suffer. If the
unavailability or high cost of drilling rigs, equipment, supplies or qualified
personnel is particularly severe in Texas, Louisiana, Colorado and the Gulf
Coast, we could be materially and adversely affected because our properties are
concentrated in those areas.





Oilfield
service and materials’ prices may escalate, and the availability of such
services may be inadequate to meet our needs.





Our
business plan to develop oil and natural gas resources requires third party
oilfield service vendors and various materials such as steel tubulars, which we
do not control. Long lead times and spot shortages may prevent us from, or
delay us in, maintaining or increasing the production volumes we expect. In
addition, escalating costs for such services and materials may render certain or
all of our projects uneconomic, as compared to the earlier prices we may have
assumed when deciding to redevelop newly purchased or existing properties. 
Further adverse economic outcomes may result from the long lead times often
necessary to execute and complete our redevelop plans.





Transportation
delays, including as a result of disruptions to infrastructure, could adversely
affect our operations.





Our
business will depend on the availability of a distribution infrastructure. Any
disruptions in this infrastructure network, whether caused by earthquakes,
storms, other natural disasters or human error or malfeasance, could materially
impact our business. Therefore, any unexpected delay in transportation of our
produced oil and natural gas could result in significant disruption to our
operations. We rely upon others for distribution of oil and natural gas, and any
failure on their part could impede the delivery of our oil and natural gas,
impose additional costs on us or otherwise cause our results of operations or
financial condition to suffer.





The
oil and natural gas exploration and production industry is very competitive, and
some of our exploration and production competitors have greater financial and
other resources than we do.





The
market for oil and natural gas recovery projects is generally highly
competitive. Our ability to compete depends on many factors, many of which are
outside of our control. These factors include: timing and market acceptance,
introduction of competitive technologies, and price and purchaser’s interest in
acquiring our oil and natural gas output.  Many existing competitors,
as well as potential new competitors, have longer operating histories, greater
name recognition, substantial track records, and significantly greater
financial, technical and technological resources than us. This may allow them to
devote greater resources to the development and promotion of their oil and
natural gas exploration and production projects. Many of these competitors offer
a wider range of oil and natural gas opportunities not available to us and may
attract business partners consequently resulting in a decrease of our business
opportunities. These competitors may also engage in more extensive research and
development, adopt more aggressive strategies and make more attractive offers to
existing and potential purchasers, and partners. Furthermore, competitors may
develop technology and oil and natural gas exploration strategies that are equal
or superior to us and achieve greater market recognition. In addition, current
and potential competitors have established or may establish cooperative
relationships among themselves or with third parties to better address the needs
of our target market. As a result, it is possible that new competitors may
emerge and rapidly acquire significant market share. There can be no assurance
that we will be able to compete successfully against our current or future
competitors or that competition will not have a material adverse effect on our
business, results of operations and financial condition.





Material
differences between the estimated and actual timing of critical events may
affect the completion of and commencement of production from development
projects.





We are
involved in several development projects. Key factors that may affect the timing
and outcome of such projects include: project approvals by joint-venture
partners; timely issuance of permits and licenses by governmental agencies;
weather conditions; manufacturing and delivery schedules of critical equipment;
and commercial arrangements for pipelines and related equipment to transport and
market hydrocarbons. Delays and differences between estimated and actual timing
of critical events may affect our projections related to such development
projects.





25




Indemnities
may be unenforceable or uncollectible which could adversely affect our business,
financial condition and future operations.





The joint
operating agreements with participants in an oil and natural gas ventures
generally provide for the indemnification of the operator; however, joint
operating agreements may not be in force and effect with regard some of our
properties in which we are the operator. Furthermore, such indemnification
rights may not be enforceable or a participant may not be financially able to
comply with its indemnification obligations. We may not be able to obtain such
indemnification agreements in the future.  The failure to obtain
enforceable indemnification agreements or a participant’s inability to indemnify
us may cause us to assume all operating costs of a property.  Such a
result could adversely affect our business, financial condition and future
operations which additionally, could cause us to become insolvent.





We
have limited control over the activities on properties we do not operate, and
are dependent on the skill, ability and decisions of third party operators with
regard to such properties.





We
operate most, but not all, of our properties. As of December 31, 2008, our DJ
Basin, Colorado property was a non-operated property.  The success of
the drilling, development, production and marketing of the oil and natural gas
from non-operated properties is dependent upon the decisions of third-party
operators and their diligence to comply with various laws, rules and regulations
affecting such properties. The failure of any third-party operator to make
decisions, perform their services, discharge their obligations, deal with
regulatory agencies, and comply with laws, rules and regulations, including
environmental laws and regulations in a proper manner with respect to properties
in which we have an interest could result in material adverse consequences to
our interest in such properties, including substantial penalties and compliance
costs. We have limited ability to influence or control the operation or future
development of non-operated properties or the amount of capital expenditures
that we are required to fund with respect to them. Our dependence on the
operator and other working interest owners for these projects and our limited
ability to influence or control the operation and future development of these
properties could materially adversely affect the realization of our targeted
returns on capital and lead to unexpected future costs.





We
have hurricane associated risks in connection with our operations in the Texas,
Louisiana and the Gulf Coast.





We could
be subject to production curtailments resulting from hurricane damage to certain
fields or, even in the event that producing fields are not damaged, production
could be curtailed due to damage to facilities and equipment owned by oil and
natural gas purchasers, or vendors and suppliers, because a portion of our oil
and natural gas properties are located in or near coastal areas of the Texas,
Louisiana and Gulf Coast. Our Matagorda Bay properties are located in the
shallow Texas state waters in Calhoun and Matagorda Counties and could be
subject to associated hurricane related risks.





We
may not carry sufficient insurance, which could adversely affect our business,
financial condition and future operations.





To
protect against possible liability, we maintain liability insurance with
coverage that we believe is consistent with industry practice and appropriate in
light of the risks attendant to our business. However, if we are unable to
maintain insurance in the future at an acceptable cost or at all, or if our
insurance does not fully cover us and a successful claim was made against us, we
could be exposed to liability. Moreover, large claims successfully asserted
against us might cause us to pay much higher insurance premiums or a large
deductible or co-payment. Any claim made against us not fully covered by
insurance could be costly to defend against, result in a substantial damage
award against us and divert the attention of management from our operations,
which could have an adverse effect on our financial performance. The nature of
the oil and natural gas business involves a variety of operating hazards such as
fires, explosions, cratering, blow-outs, adverse weather conditions, pollution
and environmental risks, encountering formations with abnormal pressures, and,
in horizontal wellbores, the increased risk of mechanical failure and collapsed
holes, the occurrence of any of which could result in substantial losses to us.
Other significant hazards may be discovered in the future. We may be subject to
liability claims as an owner of working interests with respect to certain types
of liabilities.





Repercussions
from terrorist activities or armed conflict could harm our
business.





Terrorist
activities, anti-terrorist efforts or other armed conflict involving the United
States or its interests abroad may adversely affect the United States and global
economies and could prevent us from meeting our financial and other obligations.
If events of this nature occur and persist, the political instability and
societal disruption could reduce overall demand for oil and natural gas,
potentially putting downward pressure on prevailing oil and natural gas prices
and causing a reduction in our revenues. Oil and natural gas production
facilities, transportation systems and storage facilities could be direct
targets of terrorist attacks, and our operations could be adversely impacted if
infrastructure integral to our operations is destroyed or damaged by such an
attack. Costs for insurance and other security may increase as a result of these
threats, and some insurance coverage may become more difficult to obtain, if
available at all.





26




Risks
Related to Our Common Stock





The
requirements of being a public company, including compliance with the reporting
requirements of the Exchange Act and the requirements of the Sarbanes Oxley Act,
strain our resources and increase our costs, and we may be unable to comply with
these requirements in a timely or cost-effective manner.





As a
public company, we need to comply with laws, regulations and requirements,
including certain corporate governance provisions of the Sarbanes-Oxley Act of
2002 and related regulations of the SEC. Complying with these statutes,
regulations and requirements occupies a significant amount of the time of our
board of directors and management. We are or may be required to:





·
            institute
      a comprehensive compliance
function;


·
              establish
      internal policies, such as those relating to disclosure controls and
      procedures and insider trading;


·
            design,
      establish, evaluate and maintain a system of internal controls over
      financial reporting in compliance with the requirements of Section 404 of
      the Sarbanes-Oxley Act and the related rules and regulations of the SEC
      and the Public Company Accounting Oversight
  Board;


·
            prepare
      and distribute periodic reports in compliance with our obligations under
      the federal securities laws;


·
            involve
      and retain outside counsel and accountants in the above activities;
      and


·
            establish
      an investor relations function.





Section 404 of the Sarbanes-Oxley
Act of 2002 requires companies subject to the act to disclose any material
weaknesses discovered through management’s assessments. We are required to
comply with Section 404 of the Sarbanes-Oxley Act of 2002. A material
weakness is a deficiency, or a combination of deficiencies, in internal control
over financial reporting, such that there is a reasonable possibility that a
material misstatement of our company’s annual or interim financial statements
will not be prevented or detected on a timely basis.  We will continue
to monitor the effectiveness of these and other processes, procedures and
controls and will make any further changes management determines appropriate,
including to effect compliance with Section 404 of the Sarbanes-Oxley Act
of 2002.





Any material weaknesses or other
deficiencies in our internal control over financial reporting may affect our
ability to comply with SEC reporting requirements and the NASDAQ Global Market,
listing standards or cause our financial statements to contain material
misstatements, which could negatively affect the market price and trading
liquidity of our common stock, cause investors to lose confidence in our
reported financial information, as well as subject us to civil or criminal
investigations and penalties.





We
may be unable to meet the standards established by the NASDAQ Global Market for
the continued listing of our common stock.





Our
common stock has been quoted on the NASDAQ Global Market under the symbol “STXX”
since October 31, 2007, and we must meet certain established standards for our
common stock to continue to be listed the NASDAQ Global Market. The standards
for continued listing on either market require, among other things, that the
minimum bid price for the listed securities be at least $1.00 per share. Our
common stock has recently been trading below $1.00 per share. On October 16,
2008, NASDAQ implemented a temporary suspension of the $1.00 minimum price bid
rule. This temporary suspension is currently scheduled to expire on
July 20, 2009. If our common stock were to be excluded from the NASDAQ
Global Market, the prices of our common stock and the ability of holders to sell
such stock would be adversely affected, and we would be required to comply with
the initial listing requirements to be relisted on the NASDAQ Global
Market.





The
price of our common stock may be volatile.





The
trading price of our common stock may be highly volatile and could be subject to
fluctuations in response to a number of factors beyond our control. Some of
these factors relating to volatility include:





·
            our
      results of operations and the performance of our
    competitors;


·
            the
      public’s reaction to our press releases, our other public announcements
      and our filings with the Securities and Exchange
    Commission;




27




·
            changes
      in earnings estimates or recommendations by research analysts who follow,
      or may follow, us or other companies in our
  industry;


·
            changes
      in general economic conditions;


·
            changes
      in market prices for oil and natural
gas;


·
            actions
      of our historical equity investors, including sales of common stock by our
      directors and executive officers;


·
            actions
      by institutional investors trading in our
stock;


·
            disruption
      of our operations;


·
            any
      major change in our management
team;


·
            other
      developments affecting us, our industry or our competitors;
      and


·
            U.S.
      and international economic, legal and regulatory factors unrelated to our
      performance.





In recent years the stock market has
experienced significant price and volume fluctuations. These fluctuations may be
unrelated to the operating performance of particular companies. These broad
market fluctuations may cause declines in the market price of our common stock.
The price of our common stock could fluctuate based upon factors that have
little or nothing to do with our company or our performance, and those
fluctuations could materially reduce our common stock price.





The
market for our common stock is limited and may not provide adequate
liquidity.





Our
common stock is currently thinly traded. In the year prior to December 31, 2008,
the actual daily trading volume in our common stock ranged from a low of zero
(0) shares of common stock traded to a high of 594,600 shares of common stock
traded, with only 22 days exceeding a trading volume of 50,000 shares. On most
days, this trading volume means there is limited liquidity in our shares of
common stock. Selling our shares is more difficult because smaller quantities of
shares are bought and sold and news media coverage about us is limited. These
factors result in a limited trading market for our common stock and therefore
holders of our stock may be unable to sell shares purchased, should they desire
to do so.





The
issuance of additional common and preferred stock would dilute existing
stockholders.





We are
authorized to issue up to 50,000,000 shares of common stock, and our
stockholders have recently approved, subject to SEC review of our Information
Statement on Schedule 14C, increasing the number of authorized shares available
for issuance to 200,000,000 shares. To the extent of such authorization,
our board of directors has the ability, without seeking stockholder approval, to
issue additional shares of common stock in the future for such consideration as
our board may consider sufficient.  The issuance of additional common stock
in the future would reduce the proportionate ownership and voting power of the
common stock now outstanding. During calendar year 2008, we approved the
grant of our common stock in the form of restricted stock awards under our
Equity Incentive Compensation Plan to our executive officers, to certain other
employees, to our directors and to a consultant engaged by our board of
directors. We plan to make similar awards under our Equity Incentive
Compensation Plan in current and future years.





We are
also authorized to issue up to 5,000,000 shares of preferred stock, the rights
and preferences of which may be designated in series by our board of
directors. Such designation of a new series of preferred stock may be made
without stockholder approval, and could create additional securities which would
have dividend and liquidation preferences over the common stock now outstanding.
Preferred stockholders could adversely affect the rights of holders of common
stock by:





·
            exercising
      voting, redemption and conversion rights to the detriment of the holders
      of common stock;


·
            receiving
      preferences over the holders of common stock regarding our surplus funds
      in the event of our dissolution, liquidation or the payment of dividends
      to preferred stockholders;


·
            delaying,
      deferring or preventing a change in control of our company;
      and


·
            discouraging
      bids for our common stock.





We
recently entered into a securities exchange agreement with The Longview Fund
L.P., pursuant to which the Company will 1.6 million shares of our Series A
Convertible Preferred stock in connection with our $26.1 debt restructuring and
non-core asset dispositions. These shares were not registered under the
Securities Act of 1933, and their resale was restricted. The holders of such
shares have certain registration rights and will be able to sell their shares in
the public market without restriction prior to such times if registration is
affected. These 1.6 million shares of Series A Convertible Preferred stock
convert into approximately 39 million shares of common stock at $0.50 per share.
The presence of this additional number of shares of common stock eligible for
trading in the public market may have an adverse effect on the market price of
our common stock.





28




Our
executive officers, directors and affiliates may be able to control the election
of our directors and all other matters submitted to our stockholders for
approval.





The
following share calculations treat shares issuable upon the exercise of options
or warrants as outstanding (both in the numerator and denominator for
percentages) and assume actual vesting. Our executive officers and directors, in
the aggregate, beneficially own or have the right to acquire approximately 2.4
million shares or approximately 12% of our fully diluted common stock, exclusive
of which The Longview Fund, L.P and Doud Oil & Gas Company LLC currently
owns or controls, directly or indirectly, approximately 7.8 million shares and
2.4 million shares, respectively, or approximately 44% and 12% of our fully
diluted common stock, respectively.  As a result, these holders, if they
were to act together, could exercise effective control over all matters
submitted to our stockholders for approval (including the election and removal
of directors and any merger, consolidation or sale of all or substantially all
of our assets). This concentration of ownership may have the effect of delaying,
deferring or preventing a change in control of our company, impede a merger,
consolidation, takeover or other business combination involving our company or
discourage a potential acquirer from making a tender offer or otherwise
attempting to obtain control of our company, which in turn could have an adverse
effect on the market price of our common stock or prevent our stockholders from
realizing a premium over the market price for their shares of common
stock.





If securities or industry analysts do
not publish research reports about our business or if they downgrade our stock,
the price of our common stock could decline.





Small,
relatively unknown companies can achieve visibility in the trading market
through research and reports that industry or securities analysts
publish. The lack of published reports by independent securities analysts
could limit the interest in our common stock and negatively affect our stock
price.  We do not have any control over the research and reports these
analysts publish or whether they will be published at all. If any analyst who
does cover us downgrades our stock, our stock price could decline.  If
analysts fail to regularly publish reports on us, we could lose visibility in
the financial markets, which in turn could cause our stock price to
decline.





ITEM
1B.       UNRESOLVED STAFF
COMMENTS





As of December 31, 2008, we did
not have any unresolved comments from the SEC staff that were received 180 or
more days prior to year-end.





ITEM
2.          PROPERTIES





Information
concerning proved reserves, production, wells, acreage and related matters are
contained in Part I.  Item 1. “Business.”




Our obligations under our credit
facility are secured by mortgages on our oil and natural gas
properties.  See Part II. Item 7. “Management’s Discussion
and Analysis of Financial Condition and Results of Operations” and Note 4
for additional information concerning the credit facility.





Offices




Our principal corporate office is
located at 300 East Sonterra Boulevard, Suite 1220, San Antonio, Texas 78258,
and we also maintain field an additional field office in Giddings,
Texas.  We believe that our facilities are adequate for our current
needs.





ITEM
3.            LEGAL
PROCEEDINGS





From time to time we are a party to
litigation in the normal course of business. While the outcome of lawsuits or
other proceedings against us cannot be predicted with certainty, management does
not believe that the adverse effect on our financial condition, results of
operations or cash flows, if any, will be material.





29




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





On December 19, 2008, the Company’s
stockholders elected Michael J. Pawelek, David P. Lieberman, Stanley A.
Hirschman, Bryce W. Rhodes and Doyle A. Valdez as directors.  Edward
Shaw and Owen Naccarato, both former directors, did not stand for
re-election.





PART
II





ITEM
5.            MARKET
FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES
OF EQUITY





Market
Information





Effective October 31, 2007, the Company
began trading on the NASDAQ Global Market under its current symbol
STXX.  Prior to that time, our stock had been trading on the OTCBB
under the same symbol since 2005.





The following sets forth the range of
the closing bid prices for our common stock for the period starting January 1,
2007 through December 31, 2008.  These quotations were obtained from
QuoteMedia and NASDAQ.com and do not necessarily reflect actual transactions,
retail mark-ups, mark-downs or commissions. The transactions include
inter-dealer transactions and have not been adjusted retroactively by any stock
split.





High Close
                        
                        
                        Low Close2008
      Fiscal Year, quarter ended:March
      31, 2008
                        
                        $
                        9.30
                        
                        
                        $
                        5.65June
      30, 2008
                        
                        $
                        6.95
                        
                        
                        $
                        2.68September
      30, 2008
                        
                        $
                        3.62
                        
                        
                        $
                        1.80December
      31, 2008
                        
                        $
                        1.96
                        
                        
                        $
                        0.472007
      Fiscal Year, quarter ended:March
      31, 2007
                        
                        $
                        9.77
                        
                        
                        $
                        7.20June
      30, 2007
                        
                        $
                        9.84
                        
                        
                        $
                        8.40September
      30, 2007
                        
                        $
                        9.74
                        
                        
                        $
                        8.75December
      31, 2007
                        
                        $
                        11.02
                        
                        
                        $
                        9.30





30




Performance
Graph




The following performance graph and
related information shall not be deemed “soliciting material” or to be “filed”
with the SEC, nor shall such information be incorporated by reference into any
future filing under the Securities Act of 1933 or Securities Exchange Act of
1934, each as amended, except to the extent that the Company specifically
incorporates it by reference into such filing.




The following graph compares the
cumulative 5-year total return to stockholders on our common stock relative to
the cumulative total returns of the Dow Jones Wilshire Microcap Exploration
& Production Index and the NASDAQ Composite Index:









An investment of $100 (with
reinvestment of all dividends) is assumed to have been made in our common stock,
in the index and in the peer group on December 31, 2003 and its relative
performance is tracked through December 31, 2008.




Fiscal Year Ended December 31
                  
                  2003
                  
                  
                  2004
                  
                  
                  2005
                  
                  
                  2006
                  
                  
                  2007
                  
                  
                  2008South
      Texas Oil Corporation
                  
                  $
                  100.00
                  
                  
                  $
                  227.27
                  
                  
                  $
                  154.55
                  
                  
                  $
                  7909.09
                  
                  
                  $
                  8681.82
                  
                  
                  $
                  499.91NASDAQ
      Composite Index
                  
                  
                  100.00
                  
                  
                  
                  109.96
                  
                  
                  
                  112.90
                  
                  
                  
                  126.64
                  
                  
                  
                  138.40
                  
                  
                  
                  80.76Dow
      Jones Wilshire Microcap E&P Index
                  
                  
                  100.00
                  
                  
                  
                  148.22
                  
                  
                  
                  177.20
                  
                  
                  
                  176.30
                  
                  
                  
                  141.37
                  
                  
                  
                  57.48





Holders





Our authorized capital stock consists
of 50,000,000 shares of common stock with a par value of $0.001and 5,000,000
shares of preferred stock at a par value of $0.001. Our stockholders have
recently approved, subject to SEC review of our Information Statement on
Schedule 14C, an increase of the authorized shares of common stock available for
issuance to 200,000,000 shares.





31




Common
Stock





The holders of the common stock are
entitled to one vote per share on each matter submitted to a vote at any meeting
of the stockholders. Shares of common stock do not carry cumulative voting
rights, and therefore a majority of the shares of outstanding common stock will
be able to elect the entire Board of Directors, and if they do so, minority
stockholders would not be able to elect any persons to the Board of Directors.
Our amended bylaws provide that a majority of the issued and outstanding shares
of the Company shall constitute a quorum for stockholders’ meeting except with
respect to certain matters for which a greater percentage quorum is required by
statute or our Articles of Incorporation or bylaws.  Stockholders of
the Company have no pre-emptive rights to acquire additional shares of our
common stock or other securities. The common stock is not subject to redemption
and carries no subscription or conversion rights.





Preferred  Stock





As of December 31, 2008, there were no
preferred shares issued or outstanding. Our Board of Directors is authorized by
the Articles of Incorporation to prescribe by resolution the voting powers,
designations, preferences, limitations, restrictions, reactive rights and
distinguishing designations of the preferred shares if issued.





Shares
Eligible for Future Sale




As of December 31, 2008, we had issued
16,730,529 shares of common stock issued and outstanding, of which 6,875,198
shares are restricted shares.  During 2008, we issued 403,499 shares
of common stock in settlement of $661,739 of certain subordinated demand
promissory notes and related accrued interest.  We also issued 78,000
shares to third parties as compensation for services valued at $303,800 during
the year. On May 15, 2008, we settled a lawsuit and counter lawsuit regarding
disputes arising under an agreement related to the acquisition of certain assets
in 2007 that called for us to issue shares of common stock to the counter
parties, 1,333,333 shares of which were delivered in 2007.  The May
2008 settlement agreement provided for the return of 1,333,333 shares of our
common stock previously issued, of which 1,008,333 shares were returned during
2008. As scheduled according to the terms of the settlement agreement, we have
committed to purchase the remaining 335,000 shares of common stock in three
remaining installments during 2009 and 2010.





There are no provisions in our bylaws
or Articles of Incorporation that would delay, defer or prevent a change in
control of the Company.





Our stock transfer agent is Transfer
Online, Inc., whose offices are located at 317 SW Alder Street, 2nd Floor,
Portland, Oregon 97204. Their telephone and fax numbers are respectively (503)
227-2950 and (503) 227-6874.





As of March 17, 2009, we had 16,788,862
shares of our common stock issued and outstanding, which were held by 2,623
stockholders of record. As of March 17, 2009, we have no preferred shares issued
and outstanding.





Dividends





We have not paid any dividends to date.
In addition, we do not anticipate paying dividends in the immediate
foreseeable  future. Our Board of Directors will review our dividend
policy from time to time to determine the desirability and feasibility of paying
dividends after giving consideration to our earnings, financial condition,
capital requirements and such other factors as the board may deem relevant.
There are no material restrictions in our Articles of Incorporation or bylaws
that restrict us from declaring dividends.





Securities
Authorized for Issuance Under Equity Compensation Plans





The following table shows information
with respect to each equity compensation plan under which our common stock is
authorized for issuance as of December 31, 2008:




32




Plan Category
                            
                            Number of securities to be
                              issued upon exercise of
                              outstanding options,
                              warrants and rights
                            
                            
                            Weighted average exercise
                              price of outstanding options,
                              warrants and rights
                            
                            
                            Number of securities
                              remaining available for
                              future issuance under equity
                              compensation plans
                              (excluding securities
                              reflected in column (a)(a)
                            
                            
                            (b)
                            
                            
                            (c)Equity
      compensation plans approved by security holders
                            
                            
                            530,000
                            
                            
                            $
                            0.47
                            
                            
                            
                            4,695,208Equity
      compensation plans not approved by security holders
                            
                            
                            245,500
                            
                            
                            $
                            9.45
                            
                            
                            Total
                            
                            
                            775,500
                            
                            
                            $
                            3.31
                            
                            
                            
                            4,695,208





Unregistered
Sales of Equity Securities and Use of Proceeds





Other then set forth below, the
information regarding our sales of our unregistered securities for the fiscal
year ended December 31, 2008 has been previously furnished in our Annual Reports
on Form 10-K or 10-KSB, Quarterly Reports on Form 10-Q or10-QSB and/or our
Current Reports on Form 8-K.





Issuance
of Unregistered Securities





None.





Purchases
of Equity Securities by the Issuer and Affiliated Purchasers.





None.





ITEM
6.       SELECTED FINANCIAL DATA





Not applicable to smaller reporting
companies.





ITEM
7.       MANAGEMENT DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS





Forward
Looking Statements





Please see Part I. Item 1. “Business”
of this Annual Report for “Information Regarding Forward Looking Statements”
appearing throughout this Annual Report.





Business
Overview





For this information please see Part I.
Item 1. “Business.”





Results
of Operations





Overview





We reported a net loss for the year
ended December 31, 2008, of approximately $19.7 million, or $1.23 per share.
This compares to a net loss for the year ended December 31, 2007, of
approximately $6.6 million, or $0.45 per share. Increased revenues were offset
with increased general and administrative expenses, increased production
expenses, increased interest expense, increased debt issuance costs amortization
and a 2008 loss from derivatives.  Refer to Item 7, Results of Operationsfor an
expanded discussion of these changes.





33


Liquidity Capital
Resources:At December 31, 2008, we had a working capital
deficit of $35.6 million, including $42.5 million currently due related to
long-term debt.  Our net working capital balance also included $4.3
million in cash, $3.1 million in accounts receivable, $9.5 million in assets
held for sale, and a total of $9.2 million in accounts payable and other accrued
liabilities.  If we are unable to pay, or otherwise resolve, our
accounts payable balances in a timely manner, the vendors to whom we owe unpaid
balances may cause liens to be filed against our properties.  We may
also suffer the refusal or withdrawal of trade credit from vendors as a
consequence of non-timely accounts payable payment.  These factors
could disrupt our ability to conduct operations on our properties and affect our
ability to initiate and/or complete the capital expenditure activities budgeted
for 2009. In order to obtain additional liquidity, we have initiated the pursuit
of potential debt and/or equity financing and the evaluation of other
alternatives, such as joint ventures with third parties or sales of interests in
certain of our assets.  Due to current capital and credit market
conditions in which numerous financial institutions have effectively restricted
current liquidity within the capital markets throughout the United States and
the world, we cannot be certain that funding will be available to us in required
amounts or on acceptable terms.  If we are not successful in obtaining
sufficient funding or completing an alternative transaction or transactions on a
timely basis on terms acceptable to us, we could be required to curtail our
expenditures or restructure our operations, and we would be unable to implement
our capital expenditure program, either of which could have a material adverse
affect on our business.





Proved Oil and
Natural Gas Reserves:At December 31, 2008, our estimated
total proved oil and natural gas reserves were 5.1 MMBoe, a 778% increase over
the December 31, 2007 balance of 0.6 MMBoe.  Volumes produced during
2008 totaled 102.7 MBoe, and reserve additions, net of revisions, were 4.7 MMBoe
during 2008. Approximately 12% of our total reserve volumes at December 31,
2008, were classified as proved developed and the remaining 88% was classified
as proved undeveloped.  Contributing to the significant increase in
reported total proved reserves was a comprehensive evaluation program we
conducted for our properties during 2008.  Our evaluation program
included an extensive study of operational, geological and geophysical, and land
and title information related to our properties.





Results
of Operations





The following table presents
significant items from our Consolidated Statements of Operations in our Audited
Consolidated Financial Statements, and highlights the percentage change from
year to year for those items:





2008
                          
                          
                          2007
                          
                          
                          Change
                            2008 vs.
                            2007
                          
                          
                          Change
                            2008 vs.
                            2007 (1)Oil
      and gas sales
                          
                          $
                          9,259,130
                          
                          
                          $
                          5,351,595
                          
                          
                          $
                          3,907,535
                          
                          
                          
                          +73
                          %Drilling
      services revenue
                          
                          
                          -
                          
                          
                          
                          341,312
                          
                          
                          
                          (341,312
                          )
                          
                          
                          -100
                          %Production
      expenses
                          
                          
                          3,821,758
                          
                          
                          
                          1,921,091
                          
                          
                          
                          1,900,667
                          
                          
                          
                          +99
                          %Production
      taxes
                          
                          
                          348,649
                          
                          
                          
                          275,335
                          
                          
                          
                          73,314
                          
                          
                          
                          +27
                          %Drilling
      services costs
                          
                          
                          263,717
                          
                          
                          
                          281,051
                          
                          
                          
                          (17,334
                          )
                          
                          
                          -6
                          %General
      and administrative expenses
                          
                          
                          7,897,666
                          
                          
                          
                          2,092,243
                          
                          
                          
                          5,805,423
                          
                          
                          
                          +277
                          %Depreciation,
      depletion andAmortization
                          
                          
                          4,401,913
                          
                          
                          
                          4,881,975
                          
                          
                          
                          (480,062
                          )
                          
                          
                          -10
                          %Loss
      from derivatives
                          
                          
                          4,822,720
                          
                          
                          
                          -
                          
                          
                          
                          4,822,720
                          
                          
                          
                          n/mInterest
      expense
                          
                          
                          4,218,095
                          
                          
                          
                          967,695
                          
                          
                          
                          3,250,400
                          
                          
                          
                          +336
                          %Debt
      issuance costs amortization
                          
                          
                          2,776,834
                          
                          
                          
                          1,902,670
                          
                          
                          
                          874,164
                          
                          
                          
                          +46
                          %Net
      loss
                          
                          
                          (19,726,431
                          )
                          
                          
                          (6,601,224
                          )
                          
                          
                          13,125,207
                          
                          
                          
                          +199
                          %Net
      loss per common share
                          
                          
                          (1.23
                          )
                          
                          
                          (0.45
                          )
                          
                          
                          0.78
                          
                          
                          
                          +173
                          %


(1)
            “n/m”
      indicates that the calculated percentage change is not meaningful since
      there was no 2007 value to which the net change could be
      compared





The following table presents selected
operating items and highlights the percentage change from year to year for those
items:





2008
                      
                      
                      2007
                      
                      
                      Change
                        2008 vs.
                        2007
                      
                      
                      Change
                        2008 vs.
                        2007Oil
      sales volumes, Bbl except % change
                      
                      
                      77,062
                      
                      
                      
                      121,096
                      
                      
                      
                      (44,034
                      )
                      
                      
                      -36
                      %Gas
      sales volumes, Mcf except % change
                      
                      
                      153,917
                      
                      
                      
                      291,689
                      
                      
                      
                      (137,772
                      )
                      
                      
                      -47
                      %Combined
      sales volumes, Boe except % change
                      
                      
                      102,715
                      
                      
                      
                      169,711
                      
                      
                      
                      (66,996
                      )
                      
                      
                      -39
                      %Average
      oil sales price per Bbl
                      
                      $
                      99.61
                      
                      
                      $
                      35.99
                      
                      
                      $
                      63.62
                      
                      
                      
                      +177
                      %Average
      gas sales price per Mcf
                      
                      $
                      10.32
                      
                      
                      $
                      3.40
                      
                      
                      $
                      6.92
                      
                      
                      
                      +204
                      %




34




Year
Ended December 31, 2008 Compared to Year Ended December 31, 2007





Revenues





Oil and natural gas sales increased 73%
from $5,351,595 to $9,259,130 for the year ended December 31, 2007 and 2008,
respectively, as a result of higher average realized prices for oil and natural
gas, partially offset by decreased volumes during 2008. Realized prices for oil
and natural gas on an equivalent unit basis increased for 2008, compared to
2007, by approximately 186% and had a $6.0 million positive impact on
revenues.  The 39% decrease in volumes had a $2.1 million negative
impact on revenues.





Revenue generated by drilling services
was $341,312 for the year ended December 31, 2007, compared to zero for the same
period of 2008. Our drilling rigs were undergoing repair during 2008
and were not engaged in income generating activities.





Production
Costs





The 99% increase in production expenses
from $1,921,091 to $3,821,758 for the year ended December 31, 2007 and 2008,
respectively, resulted from the increase in the number of producing wells
associated with our property acquisitions completed in the second and third
quarters of 2007.





General
and Administrative Expenses





General and administrative expenses
(“G&A”) were $7,897,666 for year ended December 31, 2008
compared  $2,092,243 for the same period in 2007, an increase of 277%.
This increase resulted from $3.3 million of non-cash stock compensation expense
associated with the restricted stock granted to the new employees who joined our
management team as officers during the third quarter of 2008, and stock options
issued to employees and directors during the first and fourth quarters of 2008.
Stock compensation expense totaled $229,778 for 2007. Stock valued at fair
market value of $303,800 was issued in exchange to third parties during 2008 in
exchange for professional services.  Also contributing to the increase
in G&A were increases in payroll and related expense of approximately
$930,000 and consulting fees of approximately $1.2
million.  Additionally, legal expenses increased by approximately
$476,000 due primarily to costs recognized in the first and second quarters of
2008 related to the settlement of litigation, and secondarily to costs incurred
during the remainder of the year related to other legal
matters.  Finally, G&A for 2008 included contract operating fees
totaling $205,000 paid to a third party entity that provided management
services to us during April through June of 2008, including oversight over daily
operational and administrative matters. Concurrent with our hiring of our new
officers at the end of June, this contract operating arrangement with the third
party was terminated.





Certain components of our G&A for
2008 are not expected to be recurring in nature. These include (i) significant
legal expenses incurred in relation to the litigation settled during the period,
(ii) fees paid for contract management services for the period preceding the
addition of our new officers, and (iii) consulting fees paid to third parties
for the provision of certain professional services that will be performed by our
own management and staff in future periods. Salary and related costs and stock
compensation expense are expected to increase as a result of the addition of our
new officers and other employees at the end of June 2008 and in the third and
fourth quarters of 2008, and as may be required in future periods.





Depreciation, Depletion and
Amortization





The 10% decrease in DD&A to
$4,401,913 for the year ended December 31, 2008 from $4,881,975 for the same
period in 2007 is the net affect of a 39% decrease in combined sales volumes,
partially offset by increased costs subject to DD&A as a result the 2008
reclassification of approximately $23.0 million in costs from unproved oil and
natural gas properties to proved oil and natural gas properties.  This
reclassification is costs incurred as a result of proved, undeveloped reserves
that were added in 2008 and which are related to the costs
reclassified.





Loss from
Derivatives





A net loss from derivatives of $4.8
million was recognized during the year ended December 31, 2008, compared
to $0 for the same period in 2007.  We entered into a derivative
instrument covering the period January 1, 2008 to December 31,
2008.  For the contract period, the volumes under contract exceeded
our actual oil production volumes.  Therefore, the entire net loss we
realized on our derivative trading during the year was recognized as a
loss.  All derivative contracts were terminated and balances settled
with the contract counter-party by December 31, 2008. We did not engage in
derivative transactions during 2007.





35




Interest
Expense





Interest expense recognized for the
year ended December 31, 2008 was $4,218,095 compared to $967,695 for the same
period in 2007, an increase of 336%. This increase is a direct result of an
increase in debt outstanding under the Longview and Marquis credit facility and
the new senior secured note issued to Marquis during the third quarter of
2008 described in Note 4 to the financial statements. Borrowings were higher
during 2008 compared to 2007 because the facility was used to finance capital
spending and operating cash flow deficits during 2008. Additionally the facility
was used to provide financing during the second quarter of 2008 to finance the
net $4.8 million loss incurred from derivative transactions.





Debt Issuance Costs
Amortization





Debt issuance costs amortization
increased 46% for the year ended December 31, 2008 compared to the prior
year.  The $874,164 increase reflects the effect of debt issuance
costs incurred in the fourth quarter of 2007 which were only subject to
amortization for one quarter of 2007, and additional debt issuance costs
incurred during 2008 in connection with senior secured notes we issued in
September 2008.





Net Loss / Net Loss per
Share





We reported a net loss for the year
ended December 31, 2008, of $19,726,431, or $1.23 per share, compared to a net
loss for the year ended December 31, 2007, of $6,601,224, or $0.45 per
share.





Liquidity
and Capital Resources





We require cash to fund our exploration
and development activities and the acquisition of oil and natural gas
properties, to make payments required pursuant to our long-term debt and other
contractual obligations and fund our working capital requirements. At December
31, 2008, we had a working capital deficit of $35.6 million, including $42.5
million currently due related to long-term debt. Our net working capital balance
also included $4.3 million in cash, $3.1 million in accounts receivable, $9.5
million in assets held for sale, and a total of $9.2 million in accounts payable
and other accrued liabilities. As of December 31, 2007, our working capital
deficit was $38,336. The most significant components of change as of December
31, 2008, compared to the prior year was the reclassification to current assets
of the net book value of $9.5 million for assets held for sale, and the
reclassification to current liabilities of long-term debt totaling $40.9
million, and a $4.3 million increase in accounts payable and other accrued
liabilities. If we are unable to pay, or otherwise resolve, our accounts payable
balances in a timely manner, the vendors to whom we owe unpaid balances may
cause liens to be filed against our properties. We may also suffer the refusal
or withdrawal of trade credit from vendors as a consequence of non-timely
accounts payable payment. These factors could disrupt our ability to conduct
operations on our properties and affect our ability to initiate and/or complete
the capital expenditure activities budgeted for 2009.





Historically our revenues have not been
sufficient to provide all of our cash needs, and we have relied on borrowings
from private investors to provide the cash needed to meet both short and
long-term liquidity requirements. We do not believe that our current cash
balances and cash flows from operations during 2009 will be sufficient to fund
our cash requirements and we will need to raise additional capital. We intend to
pursue potential debt and/or equity financing and to evaluate other
alternatives, such as joint ventures with third parties or sales of interests in
certain of our assets. Due to current capital and credit market conditions in
which numerous financial institutions have effectively restricted current
liquidity within the capital markets throughout the United States and the world,
we cannot be certain that funding will be available to us in required amounts or
on acceptable terms. If we are not successful in obtaining sufficient funding or
completing an alternative transaction or transactions on a timely basis on terms
acceptable to us, we could be required to curtail our expenditures or
restructure our operations, and we would be unable to implement our capital
expenditure program, either of which could have a material adverse affect on our
business.




36




Credit Facility and Notes
Payable




Longview/Marquis
Facility





As of December 31, 2008, we had a $32.5
million credit facility with The Longview Fund, L.P. (“Longview”) and Longview
Marquis Master Fund, L.P. (“Marquis”) with a total of $34.3 million outstanding,
which included $1.9 million for interest accrued on the facility during the
second and third quarters of 2008 added to the principal of the underlying
notes. Borrowings under the facility accrue interest at a rate equal to
12.5%.




We originally obtained the credit
facility in January 2007, at which time the facility had an initial borrowing
limit of $15.0 million that was later increased to $30.0 million in September
2007. In connection with the increase in borrowing limit, we agreed to grant to
Longview a 4.0% perpetual overriding royalty interest in the oil and natural gas
production of certain of our properties, and we granted security and pledge
agreements that provided Longview with first priority security interests in
substantially all of our assets. In April
2008, we amended and restated the credit facility with Longview and Marquis. By
further amendment in April 2008, we agreed to grant to Longview and Marquis
certain mortgages in our oil and natural gas producing properties, and we
amended the amount of the perpetual overriding royalty interest to
reduce the overriding royalty interest to an aggregate 3.0% to
Longview and Marquis, effective September 2007, and expanded the perpetual
overriding royalty interest to include all of the oil and natural gas production
of our current and future interests in the real property then owned by
us.




On June 30, 2008, the Company, Longview
and Marquis entered into another amendment to the credit facility, which (i)
increased the aggregate maximum amount of senior secured notes from $32.0
million to $32.5 million and (ii) amended the senior secured notes to provide
that the interest amounts due and payable under the senior secured notes will be
capitalized and added to the principal amount of the senior secured notes for
all interest amounts payable prior to the earlier of (a) December 31, 2008 and
(b) the date on which we received an aggregate of at least $15.0 million in
gross proceeds in one or more transactions occurring after June 30, 2008 from
any sales of our debt and/or equity securities, any other debt or equity
financings, any farm-out financing transaction that does not include operating
obligations of the financing party as a material term of the transaction, and
any sales of our oil and natural gas assets.





In September 2008, the notes payable to
Longview under the facility were amended to provide for the payment-in-kind, or
adding to the principal amount of the notes, interest accrued during the fourth
quarter of 2008 through the January 2, 2009 scheduled interest payment date. On
January 2, 2009, approximately $807,059 was added to the principal of the
outstanding Longview notes to pay-in-kind interest accrued through that
date.





Additional
Marquis Debt





During April and May 2008, we obtained
an agreement from Marquis to provide funding for the payment of margin calls
made on us related to its derivative trading activities. Pursuant to this
agreement, we received from Marquis a total of $1,571,922 in exchange for the
issuance of subordinated demand promissory notes. As of June 30, 2008, Marquis
had made demand payment of, and we paid two of the notes totaling $934,307. On
September 19, 2008 in connection with entering into the Marquis Senior Secured
Debt, the final note balance plus unpaid accrued interest, a total of $661,739,
was converted into 403,499 shares of our common stock. The interest rate for
these notes was 10%.





Marquis
Senior Secured Debt





On September 19, 2008, we entered into
a Securities Purchase Agreement (the “Securities Purchase Agreement”) with
Marquis, pursuant to which on such date, among other things, we issued and sold
to Marquis a senior secured note in an original principal amount of $7,000,000
(the “Senior Secured Note”), for gross proceeds of $6,750,000, prior to our
payment of expenses incurred by us and Marquis in connection with the
transactions under the Securities Purchase Agreement. The Senior Secured Note
carries an interest rate of 12.5% per annum payable quarterly in cash and
matures in September 2009. Upon our prepayment of all or any portion of the
Senior Secured Note or at maturity, Marquis has the option to convert up to 50%
of the principal (and interest relating thereto) to be paid by us on such date
of prepayment or maturity, into shares of our common stock at a conversion rate
of $4.00 per share (subject to adjustment for stock splits and other
events).





37


The Senior Secured Note is secured by a
general security interest in all of the tangible and intangible current and
future assets owned or acquired by us and its subsidiaries (including mortgages
on our real property interests), which have guaranteed our obligations under the
Senior Secured Note and other transaction documents. Marquis’ secured position
in this transaction is senior to the rights of all other secured parties,
including the rights of Longview under that certain securities purchase
agreement, as amended (the “April 2008 Purchase Agreement”) dated as of April 1,
2008, among the Company, Marquis and Longview, pursuant to which we has issued
and sold secured notes in the aggregate principal amount of approximately
$34,288,374 (the “Existing Notes”), except for the previously secured rights of
Marquis, which continued to rank pari passu with the rights granted to Marquis
under the Senior Secured Note. In conjunction with the transactions described in
the Securities Purchase Agreement, we entered into a September 2008 Waiver and
Amendment with Marquis and Longview, pursuant to which the parties amended and
waived certain provisions and covenants, including a financial covenant,
contained in the Existing Notes issued to Longview and the April 2008 Purchase
Agreement that conflicted with the terms and conditions of the Securities
Purchase Agreement and the transactions contemplated thereby.





Additionally, under the terms of the
Securities Purchase Agreement, we retired the outstanding Marquis subordinated
demand notes held by Marquis, which demand notes had an aggregate principal
balance due of $637,615 plus accrued interest, in exchange for 403,499 shares of
our common stock. In addition, we conveyed to Marquis a 1.0% perpetual
overriding royalty interest in the oil and natural gas production of all of our
current and future interests in the real property then owned by us. Pursuant to
the terms of the overriding royalty conveyance, we have the conditional option,
beginning on September 19, 2009 and terminating on September 19, 2010, to
repurchase the overriding royalty interests conveyed in exchange for a number of
shares of our common stock equal to the adjusted fair market value of the
conveyed overriding royalty interests, based upon an independent appraisal at
the time the election is made by us, divided by a 20-day average trading price
of our common stock at the time of repurchase, and subject to certain
conditions, including without limitation, that (i) our average prior 20-day
trading volume is at least 125,000 shares, (ii) the prior 20-day average price
per share of its common stock is at least $3.00 per share, and (iii) the shares
to be exchanged are registered for public resale pursuant to an effective
registration statement.





The notes outstanding under the
Longview/Marquis Facility and the Senior Secured Note contain various
restrictive covenants, which, among other things, limit the incurrence of
additional debt, investments, liens, dividends, prepayments of indebtedness,
asset divestitures, mergers and consolidations, transactions with affiliates and
other matters customarily restricted in such agreements. Further these notes
require the maintenance of certain average daily rates of barrels of oil
equivalent production, measured on a calendar quarterly basis.





Other
Notes Payable





The total of our other notes payable
and long-term debt at December 31, 2008 was $2.1 million and comprised of
amounts due to various parties as a result of oil and natural gas and other
property purchases. Repayment of these obligations is due over a period ranging
from less than one year to greater than five years. Effective annual interest
rates for these obligations range from 4.9% to 12.25%.





Deferred
Liability





Settlement
Agreement





On May 15, 2008, we settled a lawsuit
and counter-lawsuit between Leexus Oil & Gas, LLP (“Leexus”), Mark Jaehne,
and Bennie Jaehne regarding disputes arising under a previously reported
Agreement and Plan of Merger dated April 20, 2007 (the “Merger Agreement”). The
Merger Agreement called for us to pay $4.0 million over time based on a
percentage of the production of certain oil and natural gas interests acquired
under the Merger Agreement and issue of 2,000,000 shares of our common stock to
the selling shareholders of Leexus, 1,333,333 shares of which were delivered to
the Jaehnes at closing.





The settlement agreement provided for
our payment on the settlement date of $2.0 million and future payments totaling
$2.0 million, payable in four future installments, which will extinguish all of
our past, current and future obligations due to the Jaehnes as selling
shareholders under the Merger Agreement. The settlement also provides for the
return of 1,333,333 shares of our common stock previously issued to the Jaehnes,
of which 900,000 shares were returned on the settlement date. The first of the
four installments was paid during the fourth quarter of 2008, and 108,333
additional shares of our common stock was returned to us. As of December 31,
2008, a total liability of $1.5 million is included on the Company’s balance
sheet as long-term debt, $1.0 million of which is classified as current, and
$500,000 of which is non-current.





38




2009 Capital
Requirements





For 2009, our estimated capital
expenditure budget totals $10.0 million. We intend to focus our capital program
on the drilling of horizontal wells in the Giddings Field. Additionally, we
expect to participate in joint venture projects in Texas and Louisiana, and we
plan to complete currently in-progress drilling activities in Matagorda Bay,
Texas. Our 2009 capital budget may be revised for several different reasons,
including capital availability constraints, industry conditions such as rig and
vendor availability, oil and natural gas price fluctuations and operational
developments including drilling results. Additionally, our Blue Moon Exploration
joint venture project may include activities operated by third parties and thus
we may not have direct control over when those activities occur.





Our total capital expenditure budget is
allocated as follows:


(in millions)
                
                
                Capital
                  Expenditure
                  Budget
                  AmountGiddings
      Field horizontal wells
                
                $
                5.5Blue
      Moon Exploration joint venture project
                
                
                4.0Matagorda
      Bay completion activities
                
                
                0.5Total
                
                $
                10.0





Sources
and Uses of Cash





The following table sets forth our
sources and uses of cash for the years ended December 31, 2008 and
2007:





2008
                    
                    
                    2007
                    
                    
                    Change
                      2008 vs.
                      2007
                    
                    
                    Change
                      2008 vs.
                      2007 (1)Net
      cash (used in) provided by operating activities
                    
                    $
                    (1,707,144
                    )
                    
                    $
                    1,505,660
                    
                    
                    $
                    (3,212,804
                    )
                    
                    
                    n/mNet
      cash used in investing activities
                    
                    
                    (9,506,371
                    )
                    
                    
                    (22,145,848
                    )
                    
                    
                    12,639,477
                    
                    
                    
                    +57
                    %Net
      cash provided by financing activities
                    
                    
                    13,281,729
                    
                    
                    
                    21,553,466
                    
                    
                    
                    (8,271,737
                    )
                    
                    
                    -38
                    %Net
      increase in cash and cash equivalents
                    
                    $
                    2,068,214
                    
                    
                    $
                    913,278
                    
                    
                    $
                    1,154,936
                    
                    
                    
                    +126
                    %


(1)  “n/m”
indicates that the calculated percentage change is not meaningful since there
was no 2007 value to which the net change could be compared





Net cash provided (used) in operating
activities for the year ended December, 2008 decreased by approximately $3.2
million compared to 2007.  This decrease was primarily due to a $13.1
million increase in net loss, partially offset by increased non-cash charges to
the income statement for DD&A; amortization of debt issuance costs, deferred
stock compensation; and compensatory stock and option issuances.  The
total amounts of these non-cash charges for 2008 was $11.3 million compared to
$7.4 million in 2007, a net increase of $3.9 million.  Additionally,
net cash provided (used) in operating activities in 2008 was increased by $6.6
million related to the total net changes of operating assets and
liabilities.  This compares to approximately $756,000 in 2007 for a
net increase of $5.9 million.





Net cash used by investing activities
for the year ended December 31, 2008 decreased $12.6 million compared to the
year ended December 31, 2007, primarily as a result of decreased spending in
2008 for oil and gas property purchases and development
activities.  The Company was not actively engaged in oil and gas
property acquisition activities during 2008, unlike 2007.  Further,
the Company conducted a limited drilling program in 2008.  During
2008, the Company invested approximately $432,000 in costs related to its
drilling rigs and peripheral equipment, and vehicles used by the Company in
conducting its field operations.





Net cash provided by financing
activities for the year ended December 31, 2008 decreased by $8.3 million
compared to the prior year. This results mainly from a $3.4 million increase in
payments of notes payable and long-term debt, $2.9 million used in 2008 for the
repurchase of shares of the Company’s common stock into treasury,
and  a $1.0 million decrease in proceeds from notes payable and
long-term debt.  In 2008 the Company relied on borrowings from lenders
to fund its capital activities and provide working capital as needed to cover
net operating losses.





Contractual
Obligations





The following table summarizes our
contractual obligations and commitments by payment period:




39




Payments Due by PeriodContractual Obligations
                
                Less than
                  1 Year
                
                
                1 – 3
                  Years
                
                
                3 – 5 Years
                
                
                More Than
                  5 Years
                
                
                TotalLong-term
      debt (1)
                
                $
                42,472,051
                
                
                $
                509,564
                
                
                $
                133,865
                
                
                $
                877,630
                
                
                $
                43,993,110Deferred
      liability
                
                
                1,000,000
                
                
                
                500,000
                
                
                
                -
                
                
                
                -
                
                
                
                1,500,000Operating
      lease obligations
                
                
                172,307
                
                
                
                118,349
                
                
                
                300
                
                
                
                -
                
                
                $
                290,956Total
      contractual obligations
                
                $
                43,644,358
                
                
                $
                1,127,913
                
                
                $
                134,165
                
                
                $
                877,630
                
                
                $
                45,784,066


(1)
            excludes
      interest payments on long-term debt





Off-Balance
Sheet Arrangements





At December 31, 2008, we did not have
any off-balance sheet arrangements and we did not have any during fiscal year
ended December 31, 2008.





Critical
Accounting Policies and Estimates





The discussion and analysis of our
financial condition and results of operations are based upon our consolidated
financial statements, which have been prepared in accordance with accounting
principles generally accepted in the United States of America. The preparation
of our consolidated financial statements requires us to make estimates and
assumptions that affect our reported results of operations and the amount of
reported assets, liabilities and proved oil and natural gas reserves. Some
accounting policies involve judgments and uncertainties to such an extent that
there is reasonable likelihood that materially different amounts could have been
reported under different conditions, or if different assumptions had been used.
Actual results may differ from the estimates and assumptions used in the
preparation of our consolidated financial statements. Described below are the
most significant policies we apply in preparing our consolidated financial
statements, some of which are subject to alternative treatments under accounting
principles generally accepted in the United States of America. We also describe
the most significant estimates and assumptions we make in applying these
policies. We discussed the development, selection and disclosure of each of
these with our audit committee. See Results of Operations above and Item 8.
Consolidated Financial Statements and Supplementary Data Note 1, Organization
and Summary of Significant Events and Accounting Policies, for a discussion of
additional accounting policies and estimates made by management.





Oil
and Natural Gas Activities





Accounting for oil and natural gas
activities is subject to special, unique rules. Two generally accepted methods
of accounting for oil and natural gas activities are available — successful
efforts and full cost. The most significant differences between these two
methods are the treatment of exploration costs and the manner in which the
carrying value of oil and natural gas properties are amortized and evaluated for
impairment. The successful efforts method requires exploration costs to be
expensed as they are incurred while the full cost method provides for the
capitalization of these costs. Both methods generally provide for the periodic
amortization of capitalized costs based on proved reserve quantities. Impairment
of oil and natural gas properties under the successful efforts method is based
on an evaluation of the carrying value of individual oil and natural gas
properties against their estimated fair value, while impairment under the full
cost method requires an evaluation of the carrying value of oil and natural gas
properties included in a cost center against the net present value of future
cash flows from the related proved reserves, using period-end prices and costs
and a 10% discount rate.





Successful
Efforts Method




We use
the successful efforts method of accounting for our oil and natural gas
properties.  Exploration costs such as exploratory geological and
geophysical costs and delay rentals are charged against earnings as
incurred   The costs to acquire, drill and equip exploratory
wells are capitalized pending determinations of whether proved reserves can be
attributed to our interests as a result of drilling the well.  If
management determines that commercial quantities of oil and natural gas have not
been discovered, costs associated with exploratory wells are charged to
exploration expense.  Costs to acquire mineral interests, to drill and
equip development wells, to drill and equip exploratory wells that find proved
reserves, and related costs to plug and abandon wells and costs of site
restoration are capitalized.




Depreciation,
depletion and amortization (“DD&A”) of oil and natural gas properties is
computed using the unit-of-production method based on recoverable reserves as
estimated by our independent reservoir engineers. Capitalized acquisition costs
are depleted based on total estimated proved developed and proved undeveloped
reserve quantities.  Capitalized costs to drill and equip wells are
depreciated and amortized based on total estimated proved developed reserve
quantities.  Investments in unproved properties are not amortized
until proved reserves associated with the prospects can be determined or until
impairment occurs. Oil and natural gas properties are periodically assessed for
impairment.  If the unamortized capitalized costs of proved properties
are in excess of estimated undiscounted future cash flows before income taxes,
the property is impaired. Estimated future cash flows are determined using
management’s best estimates and may be calculated using prices consistent with
management expectations for our future oil and natural gas
sales.  Unproved oil and natural gas properties are also periodically
assessed for impairment, and a valuation allowance is provided if impairment is
indicated. Impairment costs are included in exploration expense. Costs of
expired or abandoned leases are charged against the valuation allowance. Costs
of properties that become productive are transferred to proved oil and natural
gas properties.




40


Sales of entire interests in proved and
unproved properties, and sales of partial interests of proved properties result
in the recognition of gains or losses.  Sales of partial interests of
unproved properties are generally treated as a recovery of the cost of the
interests retained.
 
 Proved
Oil and Natural Gas Reserves
 
 Our engineering estimates of proved oil
and natural gas reserves directly impact financial accounting estimates,
including our depreciation, depletion and amortization expense. Proved oil and
natural gas reserves are the estimated quantities of oil and natural gas
reserves that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under
period-end economic and operating conditions. The process of estimating
quantities of proved reserves is very complex, requiring significant subjective
decisions in the evaluation of all geological, engineering and economic data for
each reservoir. The data for a given reservoir may change substantially over
time as a result of numerous factors including additional development activity,
evolving production history and continual reassessment of the viability of
production under varying economic conditions. Changes in oil and natural gas
prices, operating costs and expected performance from a given reservoir also
will result in revisions to the amount of our estimated proved
reserves.
 
 Our estimated proved reserves for the
year ended December 31, 2008 were prepared by Forrest A. Garb & Associates,
Inc., an independent oil and natural gas reservoir engineering consulting firm.
For more information regarding reserve estimation, including historical reserve
revisions, refer to Item 8. Consolidated Financial Statements and Supplementary
Data, Supplemental Oil and Gas Disclosure.
 
 Depreciation,
Depletion and Amortization
 
 The quantities of estimated proved oil
and natural gas reserves are a significant component of our calculation of
depletion expense and revisions in such estimates may alter the rate of future
expense. Holding all other factors constant, if reserves are revised upward,
earnings would increase due to lower depletion expense. Likewise, if reserves
are revised downward, earnings would decrease due to higher depletion
expense.
 
 Future
Development and Abandonment Costs
 
 Future development costs include costs
incurred to obtain access to proved reserves such as drilling costs and the
installation of production equipment. Future abandonment costs include costs to
dismantle and relocate or dispose of our production platforms, gathering systems
and related structures and restoration costs of land and seabed. We develop
estimates of these costs for each of our properties based upon their geographic
location, type of production structure, well depth and currently available
procedures. Because these costs typically extend many years into the future,
estimating these future costs is difficult and requires management to make
judgments that are subject to future revisions based upon numerous factors,
including changing technology and fluctuating prices for services and materials
required. We review our assumptions and estimates of future development and
future abandonment costs on an annual basis.
 
 Accounting standards require that a
liability for the discounted fair value of an asset retirement obligation be
recorded in the period in which it is incurred and the corresponding cost
capitalized by increasing the carrying amount of the related long-lived asset.
The liability is accreted to its present value each period, and the capitalized
cost is depreciated over the useful life of the related asset. Holding all other
factors constant, if our estimate of future abandonment and development costs is
revised upward, earnings would decrease due to higher depreciation, depletion
and amortization (DD&A) expense. Likewise, if these estimates are revised
downward, earnings would increase due to lower DD&A expense.
 
 Revenue
Recognition
 
 We recognize revenue when oil and
natural gas quantities are delivered to or collected by the respective
purchaser. We sell our oil and natural gas production to independent purchasers.
Title to the produced quantities transfers to the purchaser at the time the
purchaser collects or receives the quantities. Prices for such production are
defined in sales contracts and are readily determinable based on certain
publicly available indices. The purchasers of such production have historically
made payment for oil and natural gas purchases within thirty to sixty days of
the end of each production month. We periodically review the difference between
the dates of production and the dates we collect payment for such production to
ensure that receivables from those purchasers are collectible. All
transportation costs are accounted for as a reduction of oil and natural gas
sales revenue.
  41
 
 New
Accounting Standards
  FASB Statement of Accounting
Standard No. 157, “Fair Value Measurement” (“SFAS 157”):  SFAS
157, issued in September 2006, defines fair value, provides guidance for using
fair value to measure assets and liabilities. It applies whenever other
standards require or permit assets or liabilities to be measured at fair value
but it does not expand the use of fair value in any new circumstances. In
November 2007, the effective date was deferred for all non-financial assets and
liabilities, except those that are recognized or disclosed at fair value on a
recurring basis. The provisions of SFAS No. 157 that were not deferred are
effective for financial statements issued for fiscal years beginning after
November 15, 2007. The adoption of SFAS No. 157, effective January 1, 2008, did
not have a significant effect on our financial position or results of
operations.
 
 FASB Statement of Accounting
Standards No. 159, “The Fair Value Option for Financial Assets and Financial
Liabilities” (“SFAS 159”):SFAS 159, issued in February 2007,
allows entities the option to measure the eligible financial instruments at fair
value as of specified dates.  Such election, which may be applied on
an instrument by instrument basis, is typically irrevocable once
elected.  SFAS No. 159 is effective fiscal years beginning after
November 15, 2007, and early application is allowed under certain
circumstances.  The adoption of SFAS No. 159, effective January 1,
2008, did not have a significant effect on our financial position or results of
operations.
  FASB Statement of Accounting
Standards No. 141 (R), “Business Combinations” (“SFAS 141
(R)”): SFAS No. 141(R) was issued in December 2007 to replace
SFAS 141.  SFAS 141 (R) establishes principles and requirements for
how an acquirer recognizes and measures in its financial statements the
identifiable assets acquired, the liabilities assumed, any non-controlling
interest in the acquire and the goodwill acquired.  The Statement also
establishes disclosure requirements, which will enable users to evaluate the
nature and financial effects of the business combination.  SFAS 141
(R) is effective for fiscal years beginning after December 15,
2008.  The adoption of SFAS 141 (R) will have an impact on accounting
for business combinations, but the effect is dependent upon acquisitions at the
time they occur.
  FASB Statement of Accounting
Standards No. 160, “Noncontrolling Interests in Consolidated Financial
Statements – an amendment of Accounting Research Bulletin No. 51” (“SFAS 160”):SFAS 160, issued in December 2007, establishes accounting and reporting
standards for ownership interests in subsidiaries held by parties other than the
parent, the amount of consolidated net income attributable to the parent and to
the non-controlling interest, changes in a parent’s ownership interest and the
valuation of retained noncontrolling equity investments when a subsidiary is
deconsolidated.  The Statement also establishes reporting requirements
that provide sufficient disclosures that clearly identify and distinguish
between the interests of the parent and the interests of the non-controlling
owners.  SFAS 160 is effective for fiscal years beginning after
December 15, 2008.  We do not currently have any non-controlling
interests and do not believe that the adoption of SFAS No. 160 will have an
effect on its financial position or results of operations.
  FASB Statement of Accounting
Standards No. 161, “Disclosures about Derivative Instruments and Hedging
Activities – an amendment of FASB Statement No. 133” (“SFAS
161”):SFAS 161, issued in March 2008, requires new and
expanded disclosures regarding hedging activities. These disclosures include,
but are not limited to, a tabular presentation of derivative data; financial
statement presentation of fair values on a gross basis, including those that
currently qualify for netting under FASB Interpretation No. 39; and specific
footnote narrative regarding how and why derivatives are used. The disclosures
are required in all interim and annual reports. SFAS No. 161 is effective for
fiscal and interim periods beginning after November 15, 2008. The Company does
not believe that the adoption of SFAS No. 161 will have a material effect on its
financial position or results of operations
  FASB Statement of Accounting
Standards No. 162, “The Hierarchy of Generally Accepted Accounting Principles”
(“SFAS 162”):  SFAS 162, issued in May 2008, is intended to
improve financial reporting by identifying a consistent hierarchy for selecting
accounting principles to be used in preparing financial statements that are
presented in conformity with U.S. generally accepted accounting principles. SFAS
No. 162 is effective 60 days following the Security Exchange Commission's
approval of the Public Company Accounting Oversight Board Auditing amendments to
AU Section 411, The Meaning of "Present Fairly in Conformity with Generally
Accepted Accounting Principles."
  42
 
 Securities and Exchange Commission
(“SEC”) Release No. 33-8995, “Modernization of Oil and Gas
Reporting”:Issued December 31, 2008, SEC Release
No. 33-8995 revised disclosure requirements for oil and natural gas
companies. In addition to changing the definition and disclosure requirements
for oil and natural gas reserves, the new rules change the requirements for
determining oil and natural gas reserve quantities. These rules permit the use
of new technologies to determine proved reserves under certain criteria and
allow companies to disclose their probable and possible reserves. The new rules
also require companies to report the independence and qualifications of their
reserves preparer or auditor and file reports when a third party is relied upon
to prepare reserves estimates or conducts a reserves audit. The new rules also
require that oil and natural gas reserves be reported and the full cost ceiling
limitation be calculated using a twelve-month average price rather than
period-end prices. The use of a twelve-month average price could have an effect
on our depletion rates for its natural gas and crude oil properties. The new
rule is effective for annual reports on Form 10-K for fiscal years ending
on or after December 31, 2009, pending the potential alignment of certain
accounting standards by the FASB with the new rule.  The Company is
currently evaluating the impact of SEC Release No. 33-8995 on its consolidated
financial statements and related disclosures.
 
 ITEM
7A.             QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
 Not applicable to smaller reporting
companies.
 
 ITEM
8.                FINANCIAL
STATEMENTS AND SUPPLEMETARY DATA
 
 Our consolidated financial statements,
together with the independent registered public accounting firm’s report of
Causey Demgen & Moore Inc., begin on page F-1, immediately after the
signature page, and are incorporated herein by reference.
 
 ITEM
9.                CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
 
 None.
 
 ITEM
9A(T).        CONTROLS AND
PROCEDURES
 
 Evaluation
of Disclosure Controls and Procedures
  Under the supervision and with the
participation of our management, including our Chief Executive Officer and Chief
Financial Officer, we conducted an evaluation of the effectiveness of the design
and operation of our disclosure controls and procedures, as defined in Rules
13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended
(“Exchange Act”), as of December 31, 2008. Disclosure controls and procedures
are those controls and procedures designed to provide reasonable assurance that
the information required to be disclosed in our Exchange Act filings is (1)
recorded, processed, summarized and reported within the time periods specified
in Securities and Exchange Commission’s rules and forms, and (2) accumulated and
communicated to management, including our Chief Executive Officer and Chief
Financial Officer, as appropriate, to allow timely decisions regarding required
disclosure.
  Based on that evaluation, the Chief
Executive Officer and Chief Financial Officer concluded that, as of December 31,
2008, our disclosure controls and procedures were effective.
  Management’s
Annual Report on Internal Control Over Financial Reporting
 
 Management, including our Chief
Executive Officer and Chief Financial Officer, is responsible for establishing
and maintaining adequate internal control over financial reporting, as such term
is defined in Exchange Act Rule 13a – 15(f).  Management conducted an
assessment as of December 31, 2008 of the effectiveness of our internal control
over financial reporting based on the framework in Internal Control – Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (“COSO”).  Based on that evaluation, management
concluded that our internal control over financial reporting was effective as of
December 31, 2008, based on criteria inInternal Control – Integrated
Framework issued by the COSO.
 
 For the
year ended December 31, 2007, we identified certain material weaknesses of the
effectiveness of our internal controls over financial reporting that we have
remedied during our 2008 fiscal year, as follows:
  43
 
 2007
      Identified Material
                    Weakness
                
                2008
      RemediationAccounting
      and Executive Personnel
                
                In
      June 2008, a new management team was installed to run our operations,
      including a new Chief Executive Officer, Chief Financial Officer, Chief
      Operating Offices, as well as additional accounting and land management
      department personnel. In October 2008, an executive Corporate Development
      position was created and staffed.Effective
      Utilization of Accounting Systems
                
                We
      have transferred data to a more robust and centralized accounting system
      that will provide for effective and efficient integration of oil and
      natural gas specific tasks with generic financial reporting
      tasks.Effective
      Control in Certain Accounting Areas
                
                We
      have implemented appropriate controls over documentation of accounting
      protocols and separation of responsibilities, including payables, cash
      utilization, account structures and general ledger journal entries. We
      have improved our financial reporting controls by (i) establishing a
      procedure for changing account structures and restrict system access
      accordingly, (ii) implementing a process to review accounting entries
      posted into General Ledger, (iii) beginning the process of documenting all
      key financial reporting processes, and (iv) establishing an effective
      document control and retention procedure.Effective
      Control in Certain Operational Areas
                
                We
      have implemented (i) appropriate controls over documentation of operating
      protocols, including guidelines for authorization levels for entering into
      agreements, such as oil and natural gas leases, joint operating
      agreements, orders, non-disclosure agreements, sales and other contracts
      and (ii) a monitoring process to insure that all leases and material
      contracts are documented appropriately and represent the transfer of valid
      leasehold rights prior to execution.Segregation
      of Authority and Duties
                
                We
      have implemented appropriate internal controls at the highest executive
      and management levels of the Company, through (i) the segregation of
      authority and duties, (ii) majority of independent directors (iii)
      Executive Committee involvement in all material contacts and acquisitions,
      (iv) addition of key executive personnel.Documentation
      of Equity Transactions
                
                We
      have established procedures for the effective communication between legal
      counsel and our Chief Financial Officer to record and document all new
      equity transactions on a real time basis.Centralized,
      Indexed Filing System
                
                With
      additional management personnel resources, we have developed a system and
      protocol for the effective documentation of critical operative
      documents.Employee
      Handbook
                
                We
      have developed an employee handbook for employees that includes Company
      policies concerning standards of conduct, code of ethics,
      non-discrimination, harassment, Americans with Disabilities Act, conflict
      of interest, whistleblower program, insider trading and
      confidentiality.Employee
      Performance Evaluation
                
                We
      are a small company and have implemented a weekly “all hands” staff
      meeting, including executive management, to discuss upcoming events and
      needs of management, and to evaluate the progress of projects assigned to
      employees.
  Because of its inherent limitations,
internal control over financial reporting may not prevent or detect
misstatements should they occur. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions or that the degree of compliance
with the control procedure may deteriorate.
  44
 
 This Annual Report does not include an
attestation report of our registered public accounting firm regarding internal
control over financial reporting. Management’s report was not subject to
attestation by our registered public accounting firm pursuant to temporary rules
of the Securities and Exchange Commission that permit us to provide only
management’s report in this Annual Report.
  ITEM
9B.             OTHER INFORMATION
 
 None.
 
 PART
III
 
 ITEM
10.              DIRECTORS,
EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
  The information required to be
contained in this Item is incorporated by reference from Part I. Item 1.
“Business” of this report and by reference either to our definitive proxy
statement to be filed with respect to our 2009 annual meeting or via the filing
of an amendment to this Form 10-K.
 
 ITEM
11.              EXECUTIVE
COMPENSATION
 
 The information required to be
contained in this Item is incorporated either by reference to our definitive
proxy statement to be filed with respect to our 2009 annual meeting under the
heading “Executive Compensation” or via the filing of an amendment to this Form
10-K.
 
 ITEM
12.              SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
 
 This information required to be
contained in this Item is incorporated either by reference to our definitive
proxy statement to be filed with respect to our 2009 annual meeting under the
heading “Principal Stockholders and Security Ownership of Management” or via the
filing of an amendment to this Form 10-K.
  ITEM
13.              CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
 
 The information required to be
contained in this Item is incorporated either by reference to our definitive
proxy statement to be filed with respect to our 2009 annual meeting under the
heading “Certain Transactions” or via the filing of an amendment to this Form
10-K.
 
 ITEM
14.              PRINCIPAL
ACCOUNTANT FEES AND SERVICES
 
 The information required to be
contained in this Item is incorporated either by reference to our definitive
proxy statement to be filed with respect to our 2009 annual meeting or via the
filing of an amendment to this Form 10-K.
  45
  PART
IV
 
 ITEM
15.              EXHIBITS
AND FINANCIAL STATEMENT SCHEDULES
 
 The following documents are filed as a
part of this report or incorporated herein by reference:
 
 (1)
              Our
      Consolidated/Combined Financial Statements are listed on page F-1 of this
      Annual Report.(2)
              Financial
      Statement Schedules:
  None
  (3)
              Exhibits:
  The
following documents are included as exhibits to this Annual Report:
  Number
              
              Description
              Ref.3.1
              
              Articles
      of Incorporation (Nevada)
              (1)3.2
              
              By-laws
      (as amended February 6, 2009)
              *4.1
              
              Rights
      of securities holders – Common Stock (Articles of Incorporation, Sections
      5 and 6)
              (1)4.2
              
              Rights
      of securities holders – Common Stock (Amended By-laws, Sections II, VIII.
      IX and XII)
              **4.3
              
              Rights
      of securities holders – Certificate of Designations Series A Convertible
      Preferred Stock
              *10.1
              
              Employment
      Agreement - Michael J. Pawelek, CEO
              (2)10.2
              
              Employment
      Agreement - Wayne Psencik, COO
              (2)10.3
              
              Employment
      Agreement - Sherry L. Spurlock, CFO
              (2)10.4
              
              Employment
      Agreement – Theodore J. Wicks, EVP Corporate Development
              (3)10.5
              
              Securities
      Purchase Agreement, dated April 1, 2008, among the Company, Longview Fund,
      L.P. and Longview Marquis Master Fund, L.P.
              (4)10.6
              
              Amendment
      to Senior Notes and Purchase Agreement, dated June 30, 2008, among the
      Company, Longview Fund, L.P. and Longview Marquis Master Fund,
      L.P.
              (5)10.7
              
              Securities
      Purchase Agreement between the Company and Longview Marquis Master Fund,
      L.P, dated as of September 19, 2008
              (6)10.8
              
              Form
      of BridgeNote
              (6)10.9
              
              Form
      of Bridge Security Agreement
              (6)10.10
              
              Form
      of Bridge Mortgage
              (6)10.11
              
              Form
      of Bridge Account Control Agreements
              (6)10.12
              
              Form
      of Bridge Guaranty
              (6)10.13
              
              Form
      of Bridge Pledge Agreement
              (6)10.14
              
              Form
      of Conveyances of Limited Overriding Royalty Interests
              (6)10.15
              
              Form
      of Intercreditor Agreement
              (6)10.16
              
              Form
      of Omnibus Amendment to Security Documents
              (6)10.17
              
              September
      2008 Waiver and Amendment
              (6)10.18
              
              Securities
      Exchange Agreement (Equity and Assets for Debt Exchange), dated February
      20, 2009 between the Company and Longview Fund, L.P
              (7)10.19
              
              Asset
      Purchase and Sale Agreement dated February 20, 2009 between the Company
      and Longview Fund, L.P
              (7)10.20
              
              Asset
      Purchase Waiver and Consent, dated February 20, 2009 by Longview Marquis
      Master Fund, L.P
              (7)21.1
              
              Subsidiaries
      of the Company31.1
              
              Principal
      Executive Officer Certification Pursuant to Item 601(b)(31) of Regulation
      S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
      2002
              *31.2
              
              Principal
      Financial Officer Certification Pursuant to Item 601(b)(31) of Regulation
      S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
      2002
              *32.1
              
              Principal
      Executive Officer Certification Pursuant to Item 601(b)(32) of Regulation
      S-K, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002
              *32.2
              
              Principal
      Financial Officer Certification Pursuant to Item 601(b)(32) of Regulation
      S-K, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002
              **
 
 *
                Filed
      herewith**
                Included
      in Exhibit 3.2
 
 (1)  
      Previously filed with the Commission as an exhibit to the Company’s Form
      10-SB on April 30, 2004(2)  
      Previously filed with the Commission as an exhibit to the Company’s Form
      8-K on June 25, 2008(3)  
      Previously filed with the Commission as an exhibit to the Company’s Form
      8-K on October 2, 2008(4)  
      Previously filed with the Commission as an exhibit to the Company’s Form
      8-K on April 15, 2008(5)  
      Previously filed with the Commission as an exhibit to the Company’s Form
      8-K on July 2, 2008(6)  
      Previously filed with the Commission as an exhibit to the Company’s Form
      8-K on September 24, 2008(7)  
      Previously filed with the Commission as an exhibit to the Company’s Form
      8-K on February 23, 2009
  46
 
 SIGNATURES
  Pursuant to the requirements of Section
13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
  SOUTH
      TEXAS OIL COMPANYDate: March
      30, 2009
                  By:
                  /s/ Michael
      J. PawelekMichael
      J. PawelekPresident
      and Chief Executive Officer
                    (Principal Executive
  Officer)
  SOUTH
      TEXAS OIL COMPANYDate: March
      30, 2009
                  By:
                  /s/ Sherry
      L. SpurlockSherry
      L. SpurlockExecutive
      Vice President and Chief Financial Officer
                    (Principal Financial and Accounting
      Officer)
  Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
 
 Signature
                          
                          Title
                          
                          Date/s/Michael J.
      Pawelek
                          
                          Chairman
      of the Board, President
                          
                          March
      30, 2009Michael
      J. Pawelek
                          
                          and
      Chief Executive Officer/s/David P.
      Lieberman
                          
                          Director
                          
                          March
      30, 2009David
      P. Lieberman/s/Stanley A.
      Hirschman
                          
                          Director
                          
                          March
      30, 2009Stanley
      A. Hirschman/s/Bryce W.
      Rhodes
                          
                          Director
                          
                          March
      30, 2009Bryce
      W. Rhodes/s/Doyle A.
      Valdez
                          
                          Director
                          
                          March
      30, 2009Doyle
      A. Valdez
  
  SOUTH
TEXAS OIL COMPANY
  INDEX
TO FINANCIAL STATEMENTS
 
 PageReport
      of Independent Registered Public Accounting Firm
                                    
                                    F-2Consolidated
      Balance Sheets as of December 31, 2008 and 2007
                                    
                                    F-3Consolidated
      Statements of Operations for the Years Ended December 31, 2008 and
      2007
                                    
                                    F-4Consolidated
      Statements of Stockholders’ Equity for the Years Ended December 31, 2008
      and 2007
                                    
                                    F-5Consolidated
      Statements of Cash Flows for the Years Ended December 31, 2008 and
      2007
                                    
                                    F-6Notes
      to the Consolidated Financial Statements
                                    
                                    F-7Supplemental
      Oil and Gas Information (Unaudited)
                                    
                                    F-20
  F-1
  REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
  To the
Board of Directors and Stockholders
 SOUTH
TEXAS OIL COMPANY and Subsidiaries
 San
Antonio, Texas
 
 We have
audited the consolidated balance sheet of South Texas Oil Company and
subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related
consolidated statements of operations, stockholders’ equity, and cash flows for
the years then ended.  These consolidated financial statements are the
responsibility of the Company’s management.  Our responsibility is to
express an opinion on these consolidated financial statements based on our
audits.
 
 We
conducted our audits in accordance with 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 misstatements.  The
Company is not required to have, nor were we engaged to perform, an audit of its
internal control over financial reporting.  Our audit included
consideration of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of the Company’s
internal control over financial reporting.  Accordingly, we express no
such opinion.  An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements.  An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation.  We believe
that our audits provide a reasonable basis for our opinion.
 
 In our
opinion, the financial statements referred to above present fairly, in all
material respects, the consolidated financial position of South Texas Oil
Company and subsidiaries, as of December 31, 2008 and 2007, and the consolidated
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/
      Causey Demgen & Moore
Inc.
  Causey
Demgen & Moore Inc.
 Denver,
Colorado
 March 30,
2009
  F-2
 
 SOUTH
      TEXAS OIL COMPANYConsolidated
      Balance Sheets
 
 December 31,2008
                                            
                                            
                                            2007ASSETSCurrent
      AssetsCash
      and equivalents
                                            
                                            $
                                            4,254,642
                                            
                                            
                                            $
                                            2,186,428Accounts
      receivable
                                            
                                            
                                            3,084,498
                                            
                                            
                                            
                                            4,226,171Prepaid
      expenses and other
                                            
                                            
                                            279,574
                                            
                                            
                                            
                                            4,249Assets
      held for sale
                                            
                                            
                                            9,520,109
                                            
                                            
                                            
                                            -Total
      current assets
                                            
                                            
                                            17,138,823
                                            
                                            
                                            
                                            6,416,848Property
      and Equipment:Oil
      and gas properties, successful efforts methodProved
      properties
                                            
                                            
                                            49,489,536
                                            
                                            
                                            
                                            23,383,575Unproved
      properties
                                            
                                            
                                            5,868,754
                                            
                                            
                                            
                                            30,757,344Less
      accumulated depreciation, depletion and amortization
                                            
                                            
                                            (9,656,545
                                            )
                                            
                                            
                                            (5,727,612
                                            )45,701,745
                                            
                                            
                                            
                                            48,413,307Other
      property and equipmentDrilling
      equipment
                                            
                                            
                                            1,300,000
                                            
                                            
                                            
                                            3,138,258Vehicles
                                            
                                            
                                            288,632
                                            
                                            
                                            
                                            172,608Other
                                            
                                            
                                            189,811
                                            
                                            
                                            
                                            119,495Less
      accumulated depreciation and amortization
                                            
                                            
                                            (173,522
                                            )
                                            
                                            
                                            (130,397
                                            )Total
      other property and equipment, net
                                            
                                            
                                            1,604,921
                                            
                                            
                                            
                                            3,299,964Total
      property and equipment, net
                                            
                                            
                                            47,306,666
                                            
                                            
                                            
                                            51,713,271Debt
      issuance costs, net of amortization
                                            
                                            
                                            3,456,094
                                            
                                            
                                            
                                            5,298,274Total
      Assets
                                            
                                            $
                                            67,901,583
                                            
                                            
                                            $
                                            63,428,393LIABILITIES
      AND STOCKHOLDERS’ EQUITYCurrent
      LiabilitiesAccounts
      payable, trade
                                            
                                            $
                                            7,628,453
                                            
                                            
                                            $
                                            1,564,243Other
      payables and accrued liabilities
                                            
                                            
                                            1,598,994
                                            
                                            
                                            
                                            3,349,067Participant
      advances received
                                            
                                            
                                            69,313
                                            
                                            
                                            
                                            120,622Current
      maturities of notes payable and long-term debt
                                            
                                            
                                            17,146,710
                                            
                                            
                                            
                                            1,404,185Current
      maturities of notes payable, related parties
                                            
                                            
                                            25,325,341
                                            
                                            
                                            
                                            17,067Current
      portion of deferred liability
                                            
                                            
                                            1,000,000
                                            
                                            
                                            
                                            -Total
      current liabilities
                                            
                                            
                                            52,768,811
                                            
                                            
                                            
                                            6,455,184Noncurrent
      LiabilitiesNotes
      payable and long-term debt
                                            
                                            
                                            727,128
                                            
                                            
                                            
                                            24,986,861Asset
      retirement obligation, net of current portion
                                            
                                            
                                            948,821
                                            
                                            
                                            
                                            801,941Deferred
      liability, net of current portion
                                            
                                            
                                            500,000
                                            
                                            
                                            
                                            -Total
      noncurrent liabilities
                                            
                                            
                                            2,175,949
                                            
                                            
                                            
                                            25,788,802Stockholders'
      EquityPreferred
      stock, $0.001 par value, 5,000,000 sharesauthorized,
      none issued or outstanding
                                            
                                            
                                            -
                                            
                                            
                                            
                                            -Common
      stock, $0.001 par value, 50,000,000 shares authorized,17,738,862
      shares issued, 16,730,529 shares outstanding (2008)and
      16,482,571 shares issued and outstanding (2007)
                                            
                                            
                                            17,740
                                            
                                            
                                            
                                            16,483Additional
      paid-in capital
                                            
                                            
                                            44,321,215
                                            
                                            
                                            
                                            39,921,615Accumulated
      deficit
                                            
                                            
                                            (28,480,122
                                            )
                                            
                                            
                                            (8,753,691
                                            )Less
      treasury stock, at cost, 1,008,333 shares
                                            
                                            
                                            (2,902,010
                                            )
                                            
                                            
                                            -Total
      stockholders' equity
                                            
                                            
                                            12,956,823
                                            
                                            
                                            
                                            31,184,407Total
      Liabilities and Stockholders' Equity
                                            
                                            $
                                            67,901,583
                                            
                                            
                                            $
                                            63,428,393
 
 See
notes to audited consolidated financial statements.
  F-3
 
 SOUTH
      TEXAS OIL COMPANYConsolidated
      Statements of Operations
 
 Year Ended December 31,2008
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            2007RevenuesOil
      and gas sales
                                                                                                                                                                                            
                                                                                                                                                                                            $
                                                                                                                                                                                            9,259,130
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            $
                                                                                                                                                                                            5,351,595Drilling
      services
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            -
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            341,312Total
      revenues
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            9,259,130
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            5,692,907Costs
      and ExpensesProduction
      expenses
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            3,821,758
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            1,921,091Production
      taxes
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            348,649
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            275,335Drilling
      services costs
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            263,717
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            281,051Exploration
      expenses
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            342,387
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            -General
      and administrative expenses
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            7,897,666
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            2,092,243Depreciation,
      depletion and amortization
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            4,401,913
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            4,881,975Total
      costs and expenses
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            17,076,090
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            9,451,695Loss
      from Operations
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            (7,816,960
                                                                                                                                                                                            )
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            (3,758,788
                                                                                                                                                                                            )Other
      Income (Expense)Interest
      income
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            21,158
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            27,929Loss
      from derivatives
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            (4,822,720
                                                                                                                                                                                            )
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            -Interest
      expense
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            (4,218,095
                                                                                                                                                                                            )
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            (967,695
                                                                                                                                                                                            )Debt
      issuance costs amortization
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            (2,776,834
                                                                                                                                                                                            )
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            (1,902,670
                                                                                                                                                                                            )Loss
      on conversion of debt
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            (112,980
                                                                                                                                                                                            )
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            -Other
      income (expense), net
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            (11,909,471
                                                                                                                                                                                            )
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            (2,842,436
                                                                                                                                                                                            )Net
      Loss Before Tax
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            (19,726,431
                                                                                                                                                                                            )
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            (6,601,224
                                                                                                                                                                                            )Income
      tax expense (benefit)
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            -
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            -Net
      Loss
                                                                                                                                                                                            
                                                                                                                                                                                            $
                                                                                                                                                                                            (19,726,431
                                                                                                                                                                                            )
                                                                                                                                                                                            
                                                                                                                                                                                            $
                                                                                                                                                                                            (6,601,224
                                                                                                                                                                                            )Loss
      Per Common Share:Basic
      and Diluted
                                                                                                                                                                                            
                                                                                                                                                                                            $
                                                                                                                                                                                            (1.23
                                                                                                                                                                                            )
                                                                                                                                                                                            
                                                                                                                                                                                            $
                                                                                                                                                                                            (0.45
                                                                                                                                                                                            )Weighted average number of common shares
      outstanding:Basic
      and Diluted
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            16,028,
      178
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            
                                                                                                                                                                                            14,679,659
 
 See
notes to audited consolidated financial statements.
  F-4
 
 SOUTH
      TEXAS OIL COMPANYConsolidated
      Statements of Stockholders' Equity
 
 Additional
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    TotalCommon
      Stock
                    
                    
                    Paid-In
                    
                    
                    Subscription
                    
                    
                    Accumulated
                    
                    
                    Treasury
                    
                    
                    Stockholders'Shares
                    
                    
                    Amount
                    
                    
                    Capital
                    
                    
                    Receivable
                    
                    
                    Deficit
                    
                    
                    Stock
                    
                    
                    EquityBalance,
      December 31, 2006
                    
                    
                    13,444,743
                    
                    
                    $
                    13,445
                    
                    
                    $
                    13,580,620
                    
                    
                    $
                    (7,500,000
                    )
                    
                    $
                    (2,152,467
                    )
                    
                    $
                    -
                    
                    
                    $
                    3,941,598Shares
      issued in payment of royalties
                    
                    
                    13,098
                    
                    
                    
                    13
                    
                    
                    
                    74,146
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    74,159Cashless
      exercise of stock options
                    
                    
                    787,652
                    
                    
                    
                    788
                    
                    
                    
                    (788
                    )
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -Warrants
      issued in connection with loan agreement
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    5,700,945
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    5,700,945Vehicle
      contributed by related party
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    2,151
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    2,151Shares
      issued for asset acquisitions:Colorado
      leases
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    7,500,000
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    7,500,000Leexus
      Operating Company
                    
                    
                    2,000,000
                    
                    
                    
                    2,000
                    
                    
                    
                    18,978,000
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    18,980,000Oil
      and gas interests of Diversity Petroleum, LLP
                    
                    
                    105,820
                    
                    
                    
                    106
                    
                    
                    
                    999,894
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    1,000,000Drilling
      rig from Granite Energy, Inc.
                    
                    
                    32,258
                    
                    
                    
                    32
                    
                    
                    
                    299,968
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    300,000Issued
      to escrow for drilling rig purchase
                    
                    
                    93,000
                    
                    
                    
                    93
                    
                    
                    
                    (93
                    )
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -Stock
      options issued in exchange for services
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    229,778
                    
                    
                    
                    -
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    229,778Shares
      issued in exchange for services
                    
                    
                    6,000
                    
                    
                    
                    6
                    
                    
                    
                    56,994
                    
                    
                    
                    -
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    57,000Net
      loss for the year
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    (6,601,224
                    )
                    
                    
                    -
                    
                    
                    
                    (6,601,224
                    )Balance,
      December 31, 2007
                    
                    
                    16,482,571
                    
                    
                    
                    16,483
                    
                    
                    
                    39,921,615
                    
                    
                    
                    -
                    
                    
                    
                    (8,753,691
                    )
                    
                    
                    -
                    
                    
                    $
                    31,184,407Stock
      grants
                    
                    
                    774,792
                    
                    
                    
                    775
                    
                    
                    
                    2,843,393
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    2,844,168Non-cash
      stock compensation
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    478,170
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    478,170Shares
      repurchased into treasury
                    
                    
                    (1,008,333
                    )
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    (2,902,010
                    )
                    
                    
                    (2,902,010
                    )Shares
      issued in exchange for debt
                    
                    
                    403,499
                    
                    
                    
                    404
                    
                    
                    
                    774,315
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    774,719Shares
      issued in exchange for services
                    
                    
                    78,000
                    
                    
                    
                    78
                    
                    
                    
                    303,722
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    303,800Net
      loss for the year
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    (19,726,431
                    )
                    
                    
                    -
                    
                    
                    
                    (19,726,431
                    )Balance,
      December 31, 2008
                    
                    
                    16,730,529
                    
                    
                    $
                    17,740
                    
                    
                    $
                    44,321,215
                    
                    
                    $
                    -
                    
                    
                    $
                    (28,480,122
                    )
                    
                    $
                    (2,902,010
                    )
                    
                    $
                    12,956,823
 
 See
notes to audited consolidated financial statements.
  F-5
 
 SOUTH
      TEXAS OIL COMPANYConsolidated
      Statements of Cash Flows
 
 Years Ended December 31,2008
                                
                                
                                2007Operating
      ActivitiesNet
      loss
                                
                                $
                                (19,726,431
                                )
                                
                                $
                                (6,601,224
                                )Adjustments
      to reconcile net loss tonet
      cash provided by (used in) operating activities:Depreciation,
      depletion and amortization
                                
                                
                                4,401,913
                                
                                
                                
                                4,881,975Amortization
      of debt issuance costs
                                
                                
                                2,776,834
                                
                                
                                
                                1,902,670Amortization
      of deferred stock compensation
                                
                                
                                3,322,338
                                
                                
                                
                                286,778Amortization
      of debt discount
                                
                                
                                334,413
                                
                                
                                
                                205,345Compensatory
      common stock and option issuances
                                
                                
                                303,800
                                
                                
                                
                                -Common
      stock issued for royalties
                                
                                
                                -
                                
                                
                                
                                74,159Accretion
      of discount on asset retirement obligation
                                
                                
                                135,944
                                
                                
                                
                                -Loss
      on conversion of debt to equity
                                
                                
                                112,980
                                
                                
                                
                                -Loss
      on sale of other property and equipment
                                
                                
                                1,889
                                
                                
                                
                                -Changes
      in operating assets and liabilities:Accounts
      receivable
                                
                                
                                1,141,673
                                
                                
                                
                                (4,185,941
                                )Prepaid
      expenses and other
                                
                                
                                (275,325
                                )
                                
                                
                                5,500Accounts
      payable
                                
                                
                                6,064,210
                                
                                
                                
                                1,546,991Accrued
      liabilities
                                
                                
                                (1,750,073
                                )
                                
                                
                                3,389,407Participant
      advances received
                                
                                
                                (51,309
                                )
                                
                                
                                -Deferred
      liability
                                
                                
                                1,500,000
                                
                                
                                
                                -Net
      cash provided by (used in) operating activities
                                
                                
                                (1,707,144
                                )
                                
                                
                                1,505,660Investing
      ActivitiesPurchases
      and development of oil and gasproperties
                                
                                
                                (9,152,895
                                )
                                
                                
                                (22,145,848
                                )Proceeds
      from disposition of other property and equipment
                                
                                
                                78,949
                                
                                
                                
                                -Purchase
      of other property and equipment
                                
                                
                                (432,425
                                )
                                
                                
                                -Net
      cash used in investing activities
                                
                                
                                (9,506,371
                                )
                                
                                
                                (22,145,848
                                )Financing
      ActivitiesProceeds
      from notes payable and long-term debt
                                
                                
                                13,380,292
                                
                                
                                
                                21,877,350Proceeds
      from notes payable, related party
                                
                                
                                7,500,000
                                
                                
                                -Payments
      of notes payable and long-term debt
                                
                                
                                (3,744,832
                                )
                                
                                
                                (272,970
                                )Debt
      issuance costs incurred
                                
                                
                                (934,654
                                )
                                
                                
                                -Payments
      of related party notes payable
                                
                                
                                (17,067
                                )
                                
                                
                                (50,914
                                )Purchase
      of treasury shares
                                
                                
                                (2,902,010
                                )
                                
                                
                                -Net
      cash provided by financing activities
                                
                                
                                13,281,729
                                
                                
                                
                                21,553,466Net
      Increase in Cash and Equivalents
                                
                                
                                2,068,214
                                
                                
                                
                                913,278Cash
      and equivalents at beginning of period
                                
                                
                                2,186,428
                                
                                
                                
                                1,273,150Cash
      and Equivalents at End of Period
                                
                                $
                                4,254,642
                                
                                
                                $
                                2,186,428Supplemental
      Disclosures:Cash
      paid for interest
                                
                                $
                                1,231,292
                                
                                
                                $
                                207,361Non-cash
      investing and financing activities:Purchase
      of property, plant and equipment with directly related
debt
                                
                                $
                                -
                                
                                
                                $
                                4,581,321Purchase
      of property, plant and equipment with common stock
                                
                                
                                -
                                
                                
                                
                                27,780,000Increase
      in property, plant and equipment for asset retirement
      obligation
                                
                                
                                10,936
                                
                                
                                
                                424,165Warrants
      issued for debt origination
                                
                                
                                -
                                
                                
                                
                                5,700,945Vehicle
      contributed by a related party
                                
                                
                                -
                                
                                
                                
                                2,151Overriding
      royalty interests granted for debt origination
                                
                                
                                375,000
                                
                                
                                
                                1,500,000
 
 See
notes to audited consolidated financial statements.
  F-6
 
 SOUTH
TEXAS OIL COMPANY
 Notes
to the Consolidated Financial Statements
 December
31, 2008
  NOTE
1 – DESCRIPTION OF BUSINESS
  South
Texas Oil Company was incorporated under the laws of the State of Nevada on July
31, 2001 as Nutek Oil, Inc., a wholly owned subsidiary of Nutek, Inc., a Texas
corporation (“Nutek”). The Company’s Articles of Incorporation presently
authorize 50,000,000 shares of common stock at $.001 par value and 5,000,000
shares of preferred stock at $.001 par value. On August 1, 2001 and January 8,
2004, Nutek made distributions of the Company’s common stock to its stockholders
pursuant to a planned “spin-off” that resulted in all of the outstanding shares
of the Company’s common stock being held by the stockholders of Nutek. On April
1, 2005, the Company’s name was changed from Nutek Oil, Inc. to South Texas Oil
Company.  Our business activities are primarily conducted through our
wholly owned subsidiaries, Southern Texas Oil Company, STO Drilling Company, STO
Operating Company, and STO Properties LLC, a wholly owned subsidiary of STO
Operating Company. The Company operates in one reportable segment engaged in the
exploration, development and production of oil and natural gas
properties.
 
 At
December 31, 2008, the Company had a working capital deficit of $35.6 million,
including $42.5 million currently due related to long-term
debt.  Long-term debt repayment scheduled for 2009 includes $7.0
million in senior notes payable due in September 2009, and $34.3 in notes
payable under the credit facility due in December 2009.  Additionally,
the Company has accounts payable and accrued liabilities outstanding at December
31, 2008, of $9.2 million.  If the Company is unable to service its
debt, it may be required, but unable to refinance all or part of its existing
debt.  If the Company is unable to pay, or otherwise resolve, its
accounts payable balances in a timely manner, the vendors to whom the Company
owes unpaid balances may cause liens to be filed against the Company’s oil and
natural gas properties. The Company may also suffer the refusal or withdrawal of
trade credit from vendors as a consequence of non-timely accounts payable
payment.  These factors could disrupt the Company’s ability to conduct
operations on its properties and affect the ability to initiate and/or complete
the capital expenditure activities budgeted for 2009.  Historically
the Company’s revenues have not been sufficient to provide all of its cash
needs, and the Company has relied on borrowings from private investors to
provide the cash needed to meet both short and long-term liquidity
requirements.  Management does not believe that current cash balances
and cash flows from operations during 2009 will be sufficient to fund the
Company’s cash requirements, and additional capital will be
required.
 
 Management
is engaged in the pursuit of potential debt and/or equity financing and in the
evaluation of other alternatives, such as joint ventures with third parties or
sales of interests in certain of the Company’s assets.   As part
of management’s strategy for addressing the Company’s liquidity and capital
resources needs, subsequent to year end the Company entered into a definitive
agreement with one of its lenders providing for comprehensive debt restructuring
and a non-core asset divestiture.  These transactions have not yet
closed pending SEC review of our Information Statement on Form 14C, and are
subject to customary closing conditions.  The agreement provides for
the issuance of shares of  Series A Convertible Preferred Stock in
exchange for approximately $16.3 million of the notes payable under the credit
facility with a maturity date of December 2008, and an exchange of certain of
the Company’s non-core assets for the extinguishment of approximately $9.8
million of additional notes payable under the credit facility maturing in
December 2008.  Refer to Note 11 – Subsequent Events for additional
information regarding these transactions.
 
 At
December 31, 2008, the Company reported substantial growth over the prior year
end in estimated total proved oil and natural gas
reserves.  Management believes this contributes to the Company’s
ability to pursue new sources of debt and/or equity financing for the
development of the Company’s reserves.
  Due to
current capital and credit market conditions in which numerous financial
institutions have effectively restricted current liquidity within the capital
markets throughout the United States and the world, management cannot be certain
that funding will be available to us in required amounts or on acceptable
terms.  If the Company is not successful in obtaining sufficient
funding or completing an alternative transaction or transactions on a timely
basis on acceptable terms, the Company could be required to curtail expenditures
or restructure operations, and it would be unable to implement the 2009 capital
expenditure program, either of which could have a material adverse affect on the
business.
  NOTE
2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
 Use of
Estimates:  The preparation of financial statements in
conformity with generally accepted accounting principles requires that
management make estimates and assumptions which affect the reported amounts of
assets and liabilities as of the date of the financial statements and reported
amounts of revenues and expenses during the reporting period.  The
most significant estimates relate to proved oil and natural gas reserve volumes,
future development costs, oil and natural gas revenues and expenses and deferred
income taxes.  Actual results could materially differ from these
estimates. Estimates that may significantly impact the Company financial
statements include reserves, depletion, and impairment on oil and natural gas
properties.
  F-7
 
 Consolidation:The
accompanying financial statements include the accounts of South Texas Oil
Company and its wholly owned subsidiaries, collectively referred to as the
“Company.”  All significant intercompany accounts and transactions
have been eliminated.
  Revenue Recognition: Oil and
natural gas revenue is recognized from the Company’s interest in producing wells
as the oil and natural gas is produced and sold from those wells to third
parties. Oil and gas sold by the Company is not significantly different from the
Company’s share of production in its producing wells.
  Reclassifications:  Certain
amounts for 2007, none of which were significant, have been reclassified to
conform to the 2008 presentation.
  Cash and Equivalents:The
Company considers all highly liquid investments with an original maturity of
three months or less to be cash equivalents.
  Accounts
Receivable:  Accounts receivable are reported at outstanding
principal net of allowance for doubtful accounts of $0 at December 31,
2008.  The allowance for doubtful accounts is determined based on the
Company’s historical losses, as well as review of specific
accounts.  Accounts are charged off when collection efforts have
failed and the account is deemed uncollectible.  The Company does not
charge interest on accounts receivable. Accounts receivable greater than 90 days
past due at December 31, 2008 and 2007 were $77,354 and $45,616,
respectively.
  Oil and Natural Gas Properties:The Company uses the successful efforts method of accounting for its oil
and natural gas properties.  Exploration costs such as exploratory
geological and geophysical costs and delay rentals are charged against earnings
as incurred   The costs to acquire, drill and equip exploratory
wells are capitalized pending determinations of whether proved reserves can be
attributed to the Company’s interests as a result of drilling the
well.  If management determines that commercial quantities of oil and
natural gas have not been discovered, costs associated with exploratory wells
are charged to exploration expense.  Costs to acquire mineral
interests, to drill and equip development wells, to drill and equip exploratory
wells that find proved reserves, and related costs to plug and abandon wells and
costs of site restoration are capitalized.
  Depreciation,
depletion and amortization (“DD&A”) of oil and gas properties is computed
using the unit-of-production method based on recoverable reserves as estimated
by the Company’s independent reservoir engineers.   Capitalized
acquisition costs are depleted based on total estimated proved developed and
proved undeveloped reserve quantities.  Capitalized costs to drill and
equip wells are depreciated and amortized based on total estimated proved
developed reserve quantities.  Investments in unproved
properties are not amortized until proved reserves associated with the prospects
can be determined or until impairment occurs.Oil and natural
gas properties are periodically assessed for impairment.  If the
unamortized capitalized costs of proved properties are in excess of estimated
undiscounted future cash flows before income taxes, the property is
impaired.  Estimated future cash flows are determined using
management’s best estimates and may be calculated using prices consistent with
management expectations for the Company’s future oil and natural gas
sales.  Unproved oil and natural gas properties are also periodically
assessed for impairment, and a valuation allowance is provided if impairment is
indicated.  Impairment costs are included in exploration
expense.  Costs of expired or abandoned leases are charged against the
valuation allowance.  Costs of properties that become productive are
transferred to proved oil and natural gas properties.
  Sales of
entire interests in proved and unproved properties, and sales of partial
interests of proved properties result in the recognition of gains or
losses.  Sales of partial interests in unproved properties are
generally treated as a recovery of the cost of the interests
retained.
  Other Property and
Equipment:  Other property and equipment is recorded at
historical cost.  Depreciation is computed using the straight-line
method over the useful lives of the assets ranging from five years for office
equipment and vehicles to twenty years for drilling rigs.  Major
renewals and betterments are capitalized while repairs are expensed as
incurred.
  Debt Issuance Costs: Costs
incurred in connection with obtaining debt financing are capitalized and
amortized over the term of the related debt.
  F-8
  Asset Retirement
Obligation:  The fair value of a liability for an asset
retirement obligation is recognized when it is probable an obligation has been
incurred and the obligation can be reasonably estimated.  This
generally occurs when a well is completed for production.  The
liability is accreted to its present value each reporting period, and the
corresponding capitalized cost is depreciated over the estimated useful life of
the related asset.  Gain or loss is recognized at the time the asset
retirement obligation is settled, if settlement occurs for an amount other than
the recorded liability.
  Treasury
Stock:Treasury stock purchases are recorded at
cost.
  Stock Based
Compensation:The Company records stock based compensation
based on the estimated fair value of the awards on the date of grant.
Forfeitures of awards are estimated based on the Company’s experience, and
recognizes compensation only for those awards expected to vest. Compensation
expense is amortized over the estimated service period, which is the shorter of
the period required for the award to vest or the derived service period implied
by special accelerated vesting provisions, when they might exist as a feature of
the award granted.
  Derivative Instruments and Hedging
Activities:The Company from time to time enters into
derivative contracts, including price swaps, caps and floors, to manage the
risks associated with changes in commodity prices related to the sale of its
future oil and natural gas production.  These contracts require
payments to (or receipts from) counter parties based on the differential between
a fixed price and a variable price for a fixed quantity of oil or natural gas
without the actual exchange of the underlying volumes.  The accounting
for these transactions is determined on a contract by contract basis, depending
on the terms of the contract.
  During
2008, the Company entered into derivative instruments covering the period
January 1, 2008 through December 31, 2008.  As of December 31, 2008,
no open contracts remained and no related balances were reported on the balance
sheet.  All amounts realized as a result of the 2008 derivative
instruments and hedging activities were fully recognized as a component of net
income in the statement of operations for the period.
  Income Taxes: Deferred tax
assets and liabilities are determined based on the temporary differences between
the financial statement and tax basis of assets and liabilities, using enacted
tax rates in effect for the year in which the differences are expected to
reverse.  The effect of changes in tax rates of deferred tax assets
and liabilities is recognized in the period of enactment.  Deferred
tax assets are reduced by a valuation allowance when management expects it is
more likely than not that a portion or all of the deferred tax assets will not
be realized.
  Earnings (Loss) Per Common
Share:  Basic earnings (loss) per common share is computed on
the basis of the weighted average number of common shares outstanding during
each year.  Diluted earnings per share are computed on the basis of
the weighted average number of shares of common stock plus common stock
equivalents for dilutive securities outstanding.  The treasury stock
method is used to calculate the effect of outstanding stock options and
warrants. Dilutive securities or common stock equivalents having an
anti-dilutive effect on diluted earnings (loss) per share are excluded from the
calculation of earnings per share for the period in which the security is
anti-dilutive.
  Comprehensive
Income:Comprehensive income is defined as the change in
equity during a reporting period resulting from transactions and other events
and circumstances from non-owner sources, and is comprised of net income and
other comprehensive income. The Company’s financial statements do not include
any sources of other comprehensive income for the years ended December 31, 2008
and 2007.
  Concentrations of Credit
Risk:  Credit risk represents the accounting loss that would be
recognized if counter parties to the Company’s transactions failed completely to
perform as contracted.  Concentrations of credit risk that arise from
financial instruments exist for groups of customers or counter parties when they
have similar economic characteristics that would cause their ability to meet
contractual obligation to be similarly affected by changes in economic or other
conditions.
  The
Company’s financial instruments that are exposed to concentrations of credit
risk consist primarily of cash and equivalents, and accounts
receivable.  The Company places its cash with major financial
institutions, which from time to time, may exceed federally insured limits.
Generally, these deposits may be redeemed upon demand, and, therefore,
management believes the risk of loss is minimal.  Substantially all of
the Company’s accounts receivable is from oil and gas sales and joint interest
billings to third parties in the oil and natural gas
industry.  Collateral is generally not required.  This
concentration of customers and joint working interest owners may affect the
Company’s credit risk because these parties may be similarly affected by changes
in economic or other conditions.  Historically, the Company has not
experienced credit losses on receivables.
  For the
years ended December 31, 2008 and 2007, the Company’s single largest customer
accounted for 70% and 69%, respectively, of the Company’s total oil and gas
revenues.  Management does not believe the loss of the Company’s
largest customer would materially affect the Company’s ability to sell its oil
production.
  Fair Value of Financial
Instruments:  Current assets and current liabilities are
reflected in the accompanying financial statements at cost, which approximates
fair value because of the short-term maturity of these
instruments.  Long-term debt is based on secondary market
indices.  Since it is not quoted, estimates are based on obligations’
characteristics, including maturities, interest rates, credit rating,
collateral, amortization schedule and liquidity.  The carrying amount
approximates fair value.
  F-9
  Recent
Accounting Pronouncements:
  FASB Statement of Accounting
Standard No. 157, “Fair Value Measurement” (“SFAS 157”):  SFAS
157, issued in September 2006, defines fair value, provides guidance for using
fair value to measure assets and liabilities. It applies whenever other
standards require or permit assets or liabilities to be measured at fair value
but it does not expand the use of fair value in any new circumstances. In
November 2007, the effective date was deferred for all non-financial assets and
liabilities, except those that are recognized or disclosed at fair value on a
recurring basis. The provisions of SFAS No. 157 that were not deferred are
effective for financial statements issued for fiscal years beginning after
November 15, 2007. The adoption of SFAS No. 157, effective January 1, 2008, did
not have a significant effect on our financial position or results of
operations.
 
 FASB Statement of Accounting
Standards No. 159, “The Fair Value Option for Financial Assets and Financial
Liabilities” (“SFAS 159”):SFAS 159, issued in February 2007,
allows entities the option to measure the eligible financial instruments at fair
value as of specified dates.  Such election, which may be applied on
an instrument by instrument basis, is typically irrevocable once
elected.  SFAS No. 159 is effective fiscal years beginning after
November 15, 2007, and early application is allowed under certain
circumstances.  The adoption of SFAS No. 159, effective January 1,
2008, did not have a significant effect on our financial position or results of
operations.
  FASB Statement of Accounting
Standards No. 141 (R), “Business Combinations” (“SFAS 141
(R)”): SFAS No. 141(R) was issued in December 2007 to replace
SFAS 141.  SFAS 141 (R) establishes principles and requirements for
how an acquirer recognizes and measures in its financial statements the
identifiable assets acquired, the liabilities assumed, any non-controlling
interest in the acquire and the goodwill acquired.  The Statement also
establishes disclosure requirements, which will enable users to evaluate the
nature and financial effects of the business combination.  SFAS 141
(R) is effective for fiscal years beginning after December 15,
2008.  The adoption of SFAS 141 (R) will have an impact on accounting
for business combinations once adopted, but the effect is dependent upon
acquisitions at that time.
  FASB Statement of Accounting
Standards No. 160, “Noncontrolling Interests in Consolidated Financial
Statements – an amendment of Accounting Research Bulletin No. 51” (“SFAS 160”):SFAS 160, issued in December 2007, establishes accounting and reporting
standards for ownership interests in subsidiaries held by parties other than the
parent, the amount of consolidated net income attributable to the parent and to
the non-controlling interest, changes in a parent’s ownership interest and the
valuation of retained noncontrolling equity investments when a subsidiary is
deconsolidated.  The Statement also establishes reporting requirements
that provide sufficient disclosures that clearly identify and distinguish
between the interests of the parent and the interests of the non-controlling
owners.  SFAS 160 is effective for fiscal years beginning after
December 15, 2008.  The Company does not currently have any
non-controlling interests and does not believe that the adoption of SFAS No. 160
will have a material effect on its financial position or results of
operations.
  FASB Statement of Accounting
Standards No. 161, “Disclosures about Derivative Instruments and Hedging
Activities – an amendment of FASB Statement No. 133” (“SFAS
161”):SFAS 161, issued in March 2008, requires new and
expanded disclosures regarding hedging activities. These disclosures include,
but are not limited to, a tabular presentation of derivative data; financial
statement presentation of fair values on a gross basis, including those that
currently qualify for netting under FASB Interpretation No. 39; and specific
footnote narrative regarding how and why derivatives are used. The disclosures
are required in all interim and annual reports. SFAS No. 161 is effective for
fiscal and interim periods beginning after November 15, 2008. The Company does
not believe that the adoption of SFAS No. 161 will have a material effect on its
financial position or results of operations
  FASB Statement of Accounting
Standards No. 162, “The Hierarchy of Generally Accepted Accounting Principles”
(“SFAS 162”):  SFAS 162, issued in May 2008, is intended to
improve financial reporting by identifying a consistent hierarchy for selecting
accounting principles to be used in preparing financial statements that are
presented in conformity with U.S. generally accepted accounting principles. SFAS
No. 162 is effective 60 days following the Security Exchange Commission's
approval of the Public Company Accounting Oversight Board Auditing amendments to
AU Section 411, The Meaning of "Present Fairly in Conformity with Generally
Accepted Accounting Principles."
  F-10
  Securities and Exchange Commission
(“SEC”) Release No. 33-8995, “Modernization of Oil and Gas
Reporting”:Issued December 31, 2008, SEC Release
No. 33-8995 revised disclosure requirements for oil and gas companies. In
addition to changing the definition and disclosure requirements for oil and gas
reserves, the new rules change the requirements for determining oil and gas
reserve quantities. These rules permit the use of new technologies to determine
proved reserves under certain criteria and allow companies to disclose their
probable and possible reserves. The new rules also require companies to report
the independence and qualifications of their reserves preparer or auditor and
file reports when a third party is relied upon to prepare reserves estimates or
conducts a reserves audit. The new rules also require that oil and gas reserves
be reported and the full cost ceiling limitation be calculated using a 12-month
average price rather than period-end prices. The use of a 12-month average price
could have an effect on the Company’s depletion rates for its natural gas and
crude oil properties. The new rule is effective for annual reports on Form 10-K
for fiscal years ending on or after December 31, 2009, pending the
potential alignment of certain accounting standards by the FASB with the new
rule.  The Company is currently evaluating the impact of SEC Release
No. 33-8995 on its consolidated financial statements and related
disclosures.
  NOTE
3 – PROPERTY AND EQUIPMENT
  Property
and equipment are summarized as follows:
 
 December 31,2008
                  
                  
                  2007Oil
      and gas properties
                  
                  $
                  55,358,290
                  
                  
                  $
                  54,140,919Accumulated
      DD&A
                  
                  
                  (9,656,545
                  )
                  
                  
                  (5,727,612
                  )45,701,745
                  
                  
                  
                  48,413,307Other
      property and equipment
                  
                  
                  1,778,443
                  
                  
                  
                  3,430,361Accumulated
      depreciation
                  
                  
                  (173,522
                  )
                  
                  
                  (130,397
                  )1,604,921
                  
                  
                  
                  3,299,964$
                  47,306,666
                  
                  
                  $
                  51,713,271
 
 Assets
Held for Sale
 
 Assets
held for sale at December 31, 2008 include the Colorado DJ Basin oil and gas
properties and one of the Company’s drilling rigs and associated assets in
connection with the pending transaction that includes an agreement to sell the
Company’s interest in these assets in exchange for the discharge of a portion of
the Company’s outstanding debt.  Refer to Note 11 – Subsequent Events
for a description of the pending transaction.
 
 As of
December 31, 2008, assets held for sale includes the following
balances:
 
 Property
      and Equipment:Oil
      and gas properties, successful efforts methodProved
      properties
                          
                          $
                          828,850Unproved
      properties
                          
                          
                          7,117,610Less
      accumulated depreciation, depletion and amortization
                          
                          
                          (267,922
                          )Total
      oil and gas properties, net
                          
                          
                          7,678,538Other
      property and equipmentDrilling
      equipment
                          
                          
                          1,980,004Less
      accumulated depreciation and amortization
                          
                          
                          (138,433
                          )Total
      other property and equipment, net
                          
                          
                          1,841,571Total
      property and equipment, net
                          
                          $
                          9,520,109
 
 2008
Acquisition Activities
 
 The
Company did not complete any significant oil and gas property acquisition
transactions during 2008.
 
 2007
Acquisition Activities
 
 During
2007, the Company completed several oil and gas property acquisition
transactions as follows:
  F-11
 
 ·
              In
      April 2007, the Company entered into a merger agreement under which Leexus
      Operating Company was acquired from the selling shareholders of Leexus
      Properties Corp. (the “Sellers”).  The Company received
      approximately $6.1 million in proved oil and gas properties and
      approximately $18.2 million in unproved oil and gas properties in exchange
      for cash of $3.0 million, a note payable to the Sellers with a discounted
      value at closing of $2.3 million and 2 million shares of the Company’s
      common stock with a fair market value on the date of issuance at $19.0
      million.  The note payable was issued with an adjusted principal
      amount of $4.5 million before discount, an annual effective interest rate
      of 12.5% and a repayment calculated based on the production rates of the
      oil and gas properties underlying the transaction.  A portion of
      the common stock issued in this transaction was returned to the Company
      and the balance of the note payable to the Sellers was reduced during 2008
      pursuant to a settlement agreement entered into by the Company and certain
      of the parties comprising the Sellers.  Refer to description at
      Note 4 – Long-Term Debt.
 
 ·
              In
      April 2007, the Company entered into an equipment purchase agreement to
      acquire a drilling rig and related equipment for a total purchase price of
      $1.1 million.  The Company paid $885,418 in cash and issued an
      $180,000 non-interest bearing note to the seller.  The note was
      recorded on the date of acquisition with a discounted value of $152,794 to
      yield an effective annual interest rate of 12.25%.  During 2007,
      the value of the note was decreased by $62,683 as a purchase price
      adjustment related to repair costs incurred by the Company during the
      seller’s warranty period.
 
 ·
              During
      June and August 2007, the Company acquired additional interests from
      selling parties in oil and gas properties located in the fields in which
      the Company originally acquired interests via Leexus Operating Company.
      The cumulative purchase price in these transactions was $2.1 million and
      was paid to the selling parties in cash.  The entire purchase
      price was allocated to proved oil and gas
  properties.
 
 ·
              In
      September 2007, the Company acquired a second drilling rig for a total
      purchase price of $1.3 million.  The Company paid to the seller
      $300,000 in cash, issued to the seller a note payable for $700,000 bearing
      interest at 7% annually, payable over two years, and issued 32,258 shares
      of common stock with a fair market value of $300,000 on the date of
      issuance.
  ·
              Also
      in September 2007, the Company purchased oil and gas properties with a
      total purchase price of $10.0 million.  The Company paid to the
      seller $7.5 million in cash, issued a promissory note payable for $1.5
      million bearing interest at 10% per year (only in the event of default on
      the note), payable over two years, and issued 105,820 shares of common
      stock with a fair market value of $1.0 million on the date of
      issuance.  The note was recorded on the date of acquisition with
      a discounted value of $1,331,010 to yield an effective annual interest
      rate of 11.75% until maturity of the
note.
  NOTE
4 - LONG-TERM DEBT
 
 As of
December 31, 2008, the Company’s notes payable and long-term debt consists of
the following:
 
 December 31,2008
                    
                    
                    2007Junior
      notes payable under credit facility
                    
                    $
                    25,325,341
                    
                    
                    $
                    -Senior
      notes payable under credit facility
                    
                    
                    8,963,033
                    
                    
                    
                    21,877,351Senior
      notes payable under 2008 bridge loan
                    
                    
                    7,000,000
                    
                    
                    
                    -Discount
      on senior notes payable under 2008 bridge loan
                    
                    
                    (187,501
                    )
                    
                    
                    -Installment
      and promissory notes to finance purchases of certain oil and gas assets
      andrelated
      equipment
                    
                    
                    2,595,054
                    
                    
                    
                    6,632,125Installment
      notes to finance purchase of company vehicles
                    
                    
                    109,682
                    
                    
                    
                    55,437Discount
      on other notes payable related to certain asset purchases
                    
                    
                    (606,430
                    )
                    
                    
                    (2,156,800
                    )43,199,179
                    
                    
                    
                    26,408,113Less
      Current Maturities
                    
                    
                    42,472,051
                    
                    
                    
                    1,421,252Long-Term
      Debt
                    
                    $
                    727,128
                    
                    
                    $
                    24,986,861
  F-12
  Longview/Marquis
Facility
 
 As of
December 31, 2008, the Company had a $32.5 million credit facility with The
Longview Fund, L.P. (“Longview”) and Longview Marquis Master Fund, L.P.
(“Marquis”) with a total of $34.3 million outstanding, which included $1.9
million for interest accrued on the facility during the second and third
quarters of 2008 added to the principal of the underlying
notes.  Borrowings under the facility accrue interest at a rate equal
to 12.5%.
  The
Company originally obtained the credit facility in January 2007, at which time
the facility had an initial borrowing limit of $15.0 million that was later
increased to $30.0 million in September 2007. In connection with the increase in
borrowing limit, the Company agreed to grant to Longview a perpetual overriding
royalty interest in the oil and gas production of certain of the Company’s
properties, and the Company granted security and pledge agreements that provided
Longview with first priority security interests in substantially all of the
Company’s assets.
  In April
2008, the Company amended and restated the credit facility with Longview and
Marquis. By further amendment in April 2008, the Company agreed to grant to
Longview and Marquis certain mortgages in the Company’s oil and gas producing
properties and a perpetual overriding royalty interest in the oil and gas
production of all of the Company’s current and future interests in the real
property then owned by the Company.
  On June
30, 2008, the Company, Longview and Marquis entered into another amendment to
the credit facility, which (i) increased the aggregate maximum amount of senior
secured notes from $32.0 million to $32.5 million and (ii) amended the senior
secured notes to provide that the interest amounts due and payable under the
senior secured notes will be capitalized and added to the principal amount of
the senior secured notes for all interest amounts payable prior to the earlier
of (a) December 31, 2008 and (b) the date on which the Company has received an
aggregate of at least $15.0 million in gross proceeds in one or more
transactions occurring after June 30, 2008 from any sales of debt and/or equity
securities of the Company, any other debt or equity financings, any farm-out
financing transaction that does not include operating obligations of the
financing party as a material term of the transaction, and any sales of the
Company’s oil and gas assets.
 
 In
September 2008, the notes payable to Longview under the facility were amended to
provide for the payment-in-kind, or adding to the principal amount of the notes,
interest accrued during the fourth quarter of 2008 through the January 2, 2009
scheduled interest payment date. On January 2, 2009, approximately $807,059
was added to the principal of the outstanding Longview notes to pay-in-kind
interest accrued through that date.
 
 Refer to
Note 8 regarding related parties for a description of Longview as a related
party to the Company.
 
 Additional
Marquis Debt
 
 During
April and May 2008, the Company obtained an agreement from Marquis to provide
funding for the payment of margin calls made on the Company related to its
derivative trading activities. Pursuant to this agreement, the Company received
from Marquis a total of $1,571,922 in exchange for the issuance of subordinated
demand promissory notes. As of June 30, 2008, Marquis had made demand payment
of, and the Company paid two of the notes totaling $934,307. On September 19,
2008 in connection with entering into the Marquis Senior Secured Debt, the final
note balance plus unpaid accrued interest, a total of $661,739, was converted
into 403,499 shares of the Company’s common stock. The interest rate for these
notes was 10%.
 
 Marquis
Senior Secured Debt
 
 On
September 19, 2008, the Company entered into a Securities Purchase Agreement
(the “Securities Purchase Agreement”) with Marquis, pursuant to which on such
date, among other things, the Company issued and sold to Marquis a senior
secured note in an original principal amount of $7,000,000 (the “Senior Secured
Note”), for gross proceeds of $6,750,000, prior to the Company’s payment of
expenses incurred by the Company and Marquis in connection with the transactions
under the Securities Purchase Agreement. The Senior Secured Note carries an
interest rate of 12.5% per annum payable quarterly in cash and matures in
September 2009. Upon the Company’s prepayment of all or any portion of the
Senior Secured Note or at maturity, Marquis has the option to convert up to 50%
of the principal (and interest relating thereto) to be paid by the Company on
such date of prepayment or maturity, into shares of the Company’s common stock
at a conversion rate of $4.00 per share (subject to adjustment for stock splits
and other events).
  F-13





The
Senior Secured Note is secured by a general security interest in all of the
tangible and intangible current and future assets owned or acquired by the
Company and its subsidiaries (including mortgages on the Company’s and its
subsidiaries’ real property interests), which have guaranteed the obligations of
the Company under the Senior Secured Note and other transaction documents.
Marquis’ secured position in this transaction is senior to the rights of all
other secured parties, including the rights of Longview under that certain
securities purchase agreement, as amended (the “April 2008 Purchase Agreement”)
dated as of April 1, 2008, among the Company, Marquis and Longview, pursuant to
which the Company has issued and sold secured notes in the aggregate principal
amount of approximately $34,288,374 (the “Existing Notes”), except for the
previously secured rights of Marquis, which continued to rank pari passu with
the rights granted to Marquis under the Senior Secured Note. In conjunction with
the transactions described in the Securities Purchase Agreement, the Company
entered into a September 2008 Waiver and Amendment with Marquis and Longview,
pursuant to which the parties amended and waived certain provisions and
covenants, including a financial covenant, contained in the Existing Notes
issued to Longview and the April 2008 Purchase Agreement that conflicted with
the terms and conditions of the Securities Purchase Agreement and the
transactions contemplated thereby.





Additionally,
under the terms of the Securities Purchase Agreement, the Company retired the
outstanding Marquis subordinated demand notes held by Marquis, which demand
notes had an aggregate principal balance due of $637,615 plus accrued interest,
in exchange for 403,499 shares of the Company’s common stock. In addition, the
Company conveyed to Marquis a 1.0% perpetual overriding royalty interest in the
oil and gas production of all of the Company’s current and future interests in
the real property then owned by the Company. Pursuant to the terms of the
overriding royalty conveyance, the Company has the conditional option, beginning
on September 19, 2009 and terminating on September 19, 2010, to repurchase the
overriding royalty interests conveyed in exchange for a number of shares of the
Company’s common stock equal to the adjusted fair market value of the conveyed
overriding royalty interests, based upon an independent appraisal at the time
the election is made by the Company, divided by a 20-day average trading price
of the Company’s common stock at the time of repurchase, and subject to certain
conditions, including without limitation, that (i) the Company’s average prior
20-day trading volume is at least 125,000 shares, (ii) the prior 20-day average
price per share of its common stock is at least $3.00 per share, and (iii) the
shares to be exchanged are registered for public resale pursuant to an effective
registration statement.





The notes
outstanding under the Longview/Marquis Facility and the Senior Secured Note
contain various restrictive covenants, which, among other things, limit the
incurrence of additional debt, investments, liens, dividends, prepayments of
indebtedness, asset divestitures, mergers and consolidations, transactions with
affiliates and other matters customarily restricted in such
agreements.  Further these notes require the maintenance of certain
average daily rates of barrels of oil equivalent production, measured on a
calendar quarterly basis.





Other
Notes Payable





The total
of the Company’s other notes payable and long-term debt at December 31, 2008 was
$2.1 million and comprised of amounts due to various parties as a result of oil
and gas and other property purchases. Repayment of these obligations is due over
a period ranging from less than one year to greater than five years. Effective
annual interest rates for these obligations range from 4.9% to
12.25%.





The
following is a schedule of principal maturities of debt as of December 31,
2008:





Year
      Ended December 31,2009
                    
                    $
                    42,472,0512010
                    
                    
                    209,5362011
                    
                    
                    149,0982012
                    
                    
                    150,9302013
                    
                    
                    133,865Thereafter
                    
                    
                    877,630Total
                    
                    $
                    43,993,110





The above
schedule of debt maturities includes $25,325,341 related to notes payable to
Longview maturing in 2009.





NOTE
5 – DEFERRED LIABILITY





Settlement
Agreement





On May
15, 2008, the Company settled a lawsuit and counter-lawsuit between Leexus Oil
& Gas, LLP, Mark Jaehne, and Bennie Jaehne regarding disputes arising under
a previously reported Agreement and Plan of Merger dated April 20, 2007 (the
“Merger Agreement”). The Merger Agreement called for us to pay $4.0 million over
time based on a percentage of the production of certain oil and gas interests
acquired under the Merger Agreement and issue of 2,000,000 shares of the
Company’s common stock to the selling shareholders of Leexus, 1,333,333 shares
of which were delivered to the Jaehnes at closing.





F-14





The
settlement agreement provided for the Company’s payment on the settlement date
of $2.0 million and future payments totaling $2.0 million, payable in four
future installments, which will extinguish all of the Company’s past, current
and future obligations due to the Jaehnes as selling shareholders under the
Merger Agreement. The settlement also provides for the return of 1,333,333
shares of the Company’s common stock previously issued to the Jaehnes, of which
900,000 shares were returned on the settlement date.  The first of the
four installments was paid during the fourth quarter of 2008, and 108,333
additional shares of our common stock was returned to us.  As of
December 31, 2008, a total liability of $1.5 million is included on the
Company’s balance sheet as long-term debt, $1.0 million of which is classified
as current, and $500,000 of which is non-current. As scheduled according to the
terms of the settlement agreement, the Company has committed to purchase the
remaining 325,000 shares of common stocks in three remaining installments during
2009 and 2010.




NOTE
6 – ASSET RETIREMENT COSTS AND OBLIGATIONS




An asset
retirement obligation is provided to reflect the Company’s legal obligations
related to future plugging and abandonment of its wells.  The
following is a reconciliation of the asset retirement obligation for the years
ended December 31, 2008 and 2007:





Year Ended December 31,2008
                
                
                2007Balance,
      beginning of period
                
                $
                854,941
                
                
                $
                459,060Liabilities
      incurred
                
                
                57,073
                
                
                
                349,183Liabilities,
      change in estimate
                
                
                (58,949
                )
                
                
                -Liabilities
      settled
                
                
                -
                
                
                
                -Accretion
      of obligation
                
                
                135,944
                
                
                
                46,698Balance,
      end of period
                
                
                989,009
                
                
                
                854,941Current
      Portion Asset Retirement Obligation
                
                
                40,188
                
                
                
                53,000Deferred
      Asset Retirement Obligation
                
                $
                948,821
                
                
                $
                801,941




NOTE
7 – STOCKHOLDERS’ EQUITY




Common
Stock




During
2008, the Company issued 403,499 shares of common stock in settlement of
$661,739 of certain subordinated demand promissory notes and related accrued
interest.  The Company issued 78,000 shares to third parties as
compensation for services valued at $303,800 during the year.




On May
15, 2008, the Company settled a lawsuit and counter lawsuit regarding disputes
arising under an agreement related to the acquisition of certain assets in 2007
that called for the Company to issue shares of common stock to the counter
parties, 1,333,333 shares of which were delivered in 2007.  The May
2008 settlement agreement provided for the return of 1,333,333 shares of the
Company’s common stock previously issued, of which 1,008,333 shares were
returned during 2008. As scheduled according to the terms of the settlement
agreement, the Company has committed to purchase the remaining 325,000 shares of
common stock in three remaining installments during 2009 and 2010.




Refer to
Note 3 – Property and Equipment, for a description of 2007 acquisition
transactions involving the issuance of shares of the Company’s common
stock.




Preferred
Stock




The
Company has authorized 5 million shares of preferred stock.  As of
December 31, 2008 and 2007, there were no shares of preferred stock issued and
outstanding.





F-15




Stock
Warrants




During
2007, the Company granted warrants to purchase 1,000,000 shares of common stock
in connection with the origination of debt issued to Longview as described in
Note 4. The value assigned to these warrants on the date of issuance was
$5,700,945 and was calculated using the Black-Scholes valuation model with the
following assumptions:  risk free interest rate, 5% expected dividend
yield, 0% expected volatility, 180% and expected weighted average life, five
years. This cost was accounted for as capitalized debt issuance costs and is
amortized over the life of the related notes payable.





The
following table summarizes activity relating to the Company’s stock
warrants:





Shares
                  Under
                  Warrant
                
                
                Exercise
                  Price
                
                
                Weighted
                  Average
                  Exercise
                  PriceOutstanding,
      December 31, 2006
                
                
                -
                
                
                
                -
                
                
                
                -Granted
                
                
                1,000,000
                
                
                $
                10.00
                
                
                $
                10.00Outstanding,
      December 31, 2007
                
                
                1,000,000
                
                
                $
                10.00
                
                
                $
                10.00Granted
                
                
                -
                
                
                
                -
                
                
                
                -Outstanding,
      December 31, 2008
                
                
                1,000,000
                
                
                $
                10.00
                
                
                $
                10.00




The
following table summarizes information about stock warrants outstanding at
December 31, 2008:





Warrants Outstanding
                          
                          
                          Warrants ExercisableExercise
                            Price
                          
                          Number
                            Outstanding
                          
                          Wt. Avg.
                            Remaining
                            Contractual
                            Life
                          
                          Wt. Avg.
                            Exercise Price
                          
                          
                          Number
                            Exercisable
                          
                          
                          Wt. Avg.
                            Exercisable
                            Price$
                          10.00
                          
                          
                          1,000,000
                          
                          3.1
      years
                          
                          $
                          10.00
                          
                          
                          
                          1,000,000
                          
                          
                          $
                          10.00




Stock
Options





In
October 2007, the Company adopted the 2007 Stock Compensation
Plan.  This plan provided for the issuance of 650,000 shares of
common stock upon the exercise of options granted to management, employees and
directors of the Company.  This plan has not been approved by the
Company’s stockholders.  Pursuant to this plan, a total of 651,000
options were granted in 2007 with an exercise price of $9.45 per
share.  At December 31, 2008, 245,500 of these options remain
outstanding, of which 154,125 are unvested.




In June
2007, the Company adopted the Equity Incentive Compensation
Plan.  This stock incentive plan provides for the issuance of
up to 6,000,000 shares of common stock awards to Company employees, directors
and officers, and consultants and directors who may not be employees of the
Company.  The Plan provides for the grant of incentive stock options
within the meaning of Section 422 of the Internal Revenue Code of 1986, as
amended, nonqualified stock options, stock appreciation rights and capital stock
of the Company which may be subject to contingencies or
restrictions.  The shareholders of the Company approved this plan in
September 2008.  At December 31, 2008, 530,000 incentive stock options
had been granted pursuant to this plan, all of which were outstanding and
unvested.




In
December 2008, stock options were issued to employees, excluding officers, under
the Company’s Equity Incentive Compensation Plan adopted in June
2008.  These options were issued with a 10-year life and will vest and
become fully exercisable in one-third increments on each of the first, second
and third anniversaries of the date of issuance.  They were issued
with an exercise price of $0.47 per share.  Additionally in December
2008, and under the same plan, stock options were issued to the Company’s
outside directors.  These options were issued with a 10-year life and
will vest and become fully exercisable one-half on March 31, 2009, and one-half
on the day preceding the Company’s next annual stockholder meeting, scheduled to
occur in May 2009.  These options were issued at market price on date
of grant with an exercise price of $0.47 per share.





F-16




The
following table summarizes the Company’s stock option activity:





Shares Under
                      Option
                    
                    
                    Exercise Price
                    
                    
                    Weighted
                      Average
                      Exercise Price
                    
                    
                    Weighted
                      Average
                      Fair Value
                      Grants
                      During YearOutstanding,
      December 31, 2006
                    
                    
                    825,000
                    
                    
                    $
                    0.46
      – 0.50
                    
                    
                    $
                    0.48Granted
      to Directors
                    
                    
                    60,000
                    
                    
                    $
                    9.45
                    
                    
                    $
                    9.45
                    
                    
                    $
                    5.50Granted
      to Officers and Employees
                    
                    
                    621,000
                    
                    
                    $
                    9.45
                    
                    
                    $
                    9.45
                    
                    
                    $
                    5.50Exercised
                    
                    
                    (787,652
                    )
                    
                    $
                    0.46
      – 0.50
                    
                    
                    $
                    0.48Surrendered
      in cashless exercise
                    
                    
                    (37,348
                    )
                    
                    $
                    0.46
      – 0.50
                    
                    
                    $
                    0.48Forfeited
                    
                    
                    (30,000
                    )
                    
                    $
                    9.45
                    
                    
                    $
                    7.69Outstanding,
      December 31, 2007
                    
                    
                    651,000
                    
                    
                    $
                    9.45
                    
                    
                    $
                    9.45Granted
      to Directors
                    
                    
                    80,000
                    
                    
                    $
                    0.47
                    
                    
                    $
                    0.47
                    
                    
                    $
                    0.47Granted
      to Employees
                    
                    
                    450,000
                    
                    
                    $
                    0.47
                    
                    
                    $
                    0.47
                    
                    
                    $
                    0.47Forfeited
                    
                    
                    (405,500
                    )
                    
                    $
                    9.45
                    
                    
                    $
                    9.45Outstanding,
      December 31, 2008
                    
                    
                    775,500
                    
                    
                    $
                    9.45
                    
                    
                    $
                    3.31




The
following table summarizes information about stock options outstanding at
December 31, 2008:
 
 Options Outstanding
                                        
                                        
                                        Options ExercisableExercise
                                          Price
                                        
                                        Number
                                          Outstanding
                                        
                                        Wt. Avg.
                                          Remaining
                                          Contractual
                                          Life
                                        
                                        Wt. Avg.
                                          Exercise Price
                                        
                                        
                                        Number
                                          Exercisable
                                        
                                        
                                        Wt. Avg.
                                          Exercisable
                                          Price$
                                        9.45
                                        
                                        
                                        245,500
                                        
                                        3.75
      years
                                        
                                        $
                                        9.45
                                        
                                        
                                        
                                        91,375
                                        
                                        
                                        $
                                        9.45$
                                        0.47
                                        
                                        
                                        530,000
                                        
                                        10
      years
                                        
                                        $
                                        0.47
                                        
                                        
                                        
                                        -
                                        
                                        
                                        $
                                        0.47775,500
                                        
                                        
                                        
                                        $
                                        3.31
                                        
                                        
                                        
                                        91,375
                                        
                                        
                                        $
                                        9.45
  In
accordance with Statement of Financial Accounting Standards 123R, the Company
measures the value of the stock based compensation granted to it employees by
use of a Black-Scholes valuation model in the case of stock options. That value
is recognized as stock compensation expense over the expected life of the
underlying options. Total stock-based compensation expense related to stock
options was reported as part of the Company’s general and administrative
expenses, and was $478,166 and $286,778 for the years ended December 31, 2008
and 2007, respectively.
 
 The fair
value for options granted was estimated on the grant date using the following
weighted average assumptions:
 
 2008
                  
                  
                  2007Risk-free
      interest rate
                  
                  
                  2.67
                  %
                  
                  
                  4.05
                  %Expected
      dividend yield
                  
                  
                  0
                  %
                  
                  
                  0
                  %Expected
      volatility of common stock
                  
                  
                  100
                  %
                  
                  
                  81
                  %Expected
      weighted average life of option
                  
                  5.19
      years
                  
                  
                  3.5
      years




F-17




Restricted
Stock




On June
30, 2008, pursuant to the Equity Incentive Compensation Plan of South Texas Oil
Company, the Company granted Stock Award Rights and Performance Option Rights
under the Equity Incentive Compensation Plan, to provide for the issuance of
stock grants and incentive stock options as compensation to its officers who
joined the Company in June 2008. The Stock Awards Rights provide for the
granting of restricted shares of the Company’s common stock at specified
intervals and in amounts equal to specified values on the issuance dates. The
Performance Option Rights provide for the issuance of stock options pursuant to
the terms of the Equity Incentive Compensation Plan, which provide for the
issuance of stock options upon achievement of certain Company performance goals.
The first of three tranches of shares of common stock were issued in 2008 and
were restricted at time of issuance.




In
accordance with Statement of Financial Accounting Standards 123R, the Company
measures the value of the stock based compensation granted to it employees in
the case of stock grants based on the number of shares issued and the per share
value of the Company’s stock on the date of issuance. That value is recognized
as stock compensation expense over the period between the issuance of restricted
shares and the lapse of the restrictions. The per share weighted average value
of the date of grant for the June 2008 issuances was $3.69. Total stock-based
compensation expense related to employee stock grants was reported as part of
the Company’s general and administrative expenses, and was $2,844,168 for the
year ended December 31, 2008.





NOTE
8 – RELATED PARTIES





The
Company is deemed to have a related party relationship with Longview because
Longview is the beneficial owner of an amount in excess of 10% of the Company’s
issued and outstanding common stock at December 31, 2008.  Refer to
Note 4 – Long-Term Debt for a description of the Company’s credit facility with
Longview and the related notes payable.  Interest paid during the year
ended December 31, 2008 and 2007, by the Company on notes payable to Longview
was $899,106 and $414,631, respectively.





The
Company is deemed to have a related party relationship with a third party who
operates and is a joint interest owner in the Company’s oil and gas properties
located in the DJ Basin in Colorado.   This party is the
beneficial owner of an amount in excess of 10% of the Company’s issued and
outstanding common stock at December 31, 2008.  The Company acquired
its interests in these properties from the operator in a transaction which
closed during 2007, whereby the Company exchanged 2,419,335 shares of its common
stock, then valued at $7.5 million, for a 37.5% interest in the oil and gas
properties.   The Company received approximately $338,089 and
$129,713 in net oil and gas revenue distributions for the properties from the
related party during the years ended December 31, 2008 and 2007,
respectively.  The Company paid to the related party approximately $
23,587 and $202,074 for capital expenditures and lease operating expenses,
respectively, in 2008, and approximately $453,056 and $72,134 for capital
expenditures and lease operating expense, respectively, in 2007.




The
Company had notes payable of $17,067 payable to former executive officers of the
Company at December 31, 2007. Those notes were no longer outstanding at
December 31, 2008.
 
 During a
portion of 2008 and all of 2007, the Company leased for $750 per month
approximately four acres of land from a former executive officer of the Company
to use for a field office and to store certain vehicles and equipment belonging
to the Company.  Also during a portion of 2008 and all of 2007, the
Company paid $1,286 per month for the use of equipment belonging to former
executive officer.  Both of these arrangements were terminated during
the second and third quarters of 2008.





F-18




NOTE
9 – COMMITMENTS AND CONTINGENCIES




In June
2008, the Company relocated its corporate headquarters from Bastrop, Texas to
San Antonio, Texas.  The San Antonio office location is now the
Company’s primary office space and is leased through September
2010.  The Bastrop office was used as a field office from July 2008
through January 2009, the date of termination of the Bastrop office
lease.  Upon termination of that lease, the Company entered into a
lease for a field office in Giddings, Texas, expiring January
2010.  Additionally, the Company has entered into rental agreements
for certain storage spaces and certain office equipment.  Total rent
expense was $154,338 in 2008 and $18,250 in 2007.  Future minimum
rentals for the next five years under all non-cancelable leases and contracts
are as follows:





Year
      Ended December 31,2009
                
                $
                172,3072010
                
                
                118,3492011
                
                
                3002012
                
                
                -2013
                
                
                -




Pending
or Threatened Litigation:




In the
ordinary course of business, the Company is involved in various claims and legal
proceedings.  Management believes that it is unlikely that any of the
proceedings to which the Company is a party at December 31, 2008, will be
finally resolved in a manner that would have a material adverse effect on the
Company.  Accordingly, no contingent liabilities have been recognized
at December 31, 2008 related to these matters.




NOTE
10 - INCOME TAXES




On
January 1, 2007, the Company adopted the provisions of Financial Accounting
Standards Board Interpretation No. 48, which provides that the tax effects from
an uncertain tax position can be recognized in the financial statements only if
the position is more likely than not of being sustained if the position were to
be challenged by a taxing authority.  In 2007, the tax positions taken
by the Company in its returns were examined.  It was determined that
the Company does not have an asset or a liability for uncertain tax
positions.  Accordingly, the Company has not recognized other tax
assets or liabilities in its consolidated balance sheet.




Significant
components of the Company’s deferred federal income tax assets and liabilities
are composed of the following:




December 31,2008
                      
                      
                      2007Deferred
      tax assets:Tax
      net operating loss carryforward
                      
                      $
                      9,500,810
                      
                      
                      $
                      2,898,186Stock
      compensation
                      
                      
                      1,204,396
                      
                      
                      
                      78,125Gross
      deferred assets
                      
                      
                      10,705,206
                      
                      
                      
                      2,976,311Deferred
      tax liabilities:IDC
      and depreciation
                      
                      
                      (2,714,842
                      )
                      
                      
                      (1,095,271
                      )Net
      deferred tax asset
                      
                      
                      7,990,364
                      
                      
                      
                      1,881,040Less
      valuation allowance
                      
                      
                      (7,990,364
                      )
                      
                      
                      (1,881,040
                      )Deferred
      tax asset recorded
                      
                      $
                      —
                      
                      
                      $
                      —




In
assessing the reliability of deferred tax assets, management considers whether
it is more likely than not that some portion or all of the deferred income tax
assets will not be realized. The ultimate realization of deferred income tax
assets is dependent upon the generation of future taxable income during the
periods in which those temporary differences become deductible. Management
considers the scheduled reversal of deferred income tax liabilities, projected
future taxable income, and tax planning strategies in making this assessment.
Based on consideration of these items, management has determined that enough
uncertainty exists relative to the realization of the net deferred income tax
asset to warrant the application of a full valuation allowance as of December
31, 2008.





F-19




At
December 31, 2008, the Company had unused federal net operating loss
carryforwards of approximately $28.0 million which expire 2021 through
2029.  Following is a reconciliation of the Company’s effective income
tax rate to the federal statutory rate:





Year Ended December 31,2008
                
                
                2007Income
      tax benefit at federal statutory rate
                
                $
                6,706,987
                
                
                
                34
                %
                
                $
                2,244,416
                
                
                
                34
                %Non-deductible
      interest expense
                
                
                (591,465
                )
                
                
                (3
                )%
                
                
                (646,908
                )
                
                
                (10
                )%Other
      non-deductible expenses
                
                
                (6,198
                )
                
                
                -
                
                
                
                (1,932
                )
                
                
                -Change
      in valuation allowance
                
                
                (6,109,324
                )
                
                
                (31
                )%
                
                
                (1,595,576
                )
                
                
                (24
                )%Current
      and deferred provision for income taxes
                
                $
                -
                
                
                
                -
                
                
                $
                -
                
                
                
                -




NOTE
11 – SUBSEQUENT EVENTS





On
February 23, 2009, the Company announced a comprehensive debt restructuring and
related agreements with Longview.  The agreements with Longview
provide that Longview will restructure $26.1 million of debt (plus accrued
interest) through (i) the payment of $16.3 million in debt (plus accrued
interest) held by Longview in exchange for 1.6 million shares of the Company’s
Series A Convertible Preferred Stock and (ii) a debt/non-core asset exchange
between us and Longview valued at $9.8 million.





Pursuant
to a securities exchange agreement, the Company will issue to Longview
approximately 1.6 million shares of Series A Convertible Preferred Stock in
exchange for the surrender and cancellation of approximately $16.3 million of
notes held by Longview. Each share of Series A Convertible Preferred Stock has a
stated value equal to $10.00 per share, has no coupon rate, does not pay
dividends, and has no voting rights. The shares of Series A Convertible
Preferred Stock are convertible into shares of our common stock at any time
subsequent to 90 days after the issuance of the shares at a conversion price of
$0.50 per share of common stock. Stockholders holding more than a majority of
the Company’s outstanding common stock (approximately 59.36%) have approved the
creation and issuance of the shares of Series A Preferred Stock to Longview, and
an information statement has been filed with the Securities and Exchange
Commission (the “SEC”), which is subject to SEC review. Following SEC review,
notice will be provided to all of the Company’s stockholders that did not
consent to such action, by delivery of an Information Statement prepared
pursuant to Section 14 of the Securities Exchange Act of 1934 (the “Exchange
Act”), and the exchange will close a minimum of 20 days following the mailing of
the Information Statement to the stockholders.





The
Company also entered into an asset purchase and sale agreement with Longview to
sell the Company’s interest Colorado DJ Basin oil and gas properties and one of
its drilling rigs and associated assets to Longview for a combined total of $9.8
million. Subject to the terms and conditions of the purchase and sale agreement,
on the closing date, these assets will be conveyed to Longview in exchange for
Longview’s discharge and satisfaction of $9.8 million in debt.  The
Colorado property disposition includes approximately 217,000 Boe of proved
reserves and an estimated 18 barrels of oil equivalent per day of net
production.  Closing of both transactions is subject to customary
closing conditions and SEC review of our Information Statement on Schedule
14C.





NOTE
12 – OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES




The
estimates of the Company’s proved reserves and related future net cash flows
that are presented in the following tables are based upon estimates made by
independent petroleum engineering consultants. The reserve information was
prepared as of December 31, 2008. There are many inherent uncertainties in
estimating proved reserve quantities, projecting future production rates, and
timing of development expenditures. Accordingly, these estimates are likely to
change as future information becomes available. Proved developed reserves are
the estimated quantities of crude oil, condensate, natural gas and natural gas
liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.





F-20




Costs
Incurred and Capitalized Costs




The
Company’s investment in oil and gas properties is as follows:




December
      31,2008
                  
                  
                  2007Proved
      properties
                  
                  $
                  49,489,536
                  
                  
                  $
                  23,383,575Less
      accumulated depreciation, depletion and amortization
                  
                  
                  (9,656,545
                  )
                  
                  
                  (5,727,612
                  )Net
      proved properties
                  
                  
                  39,832,991
                  
                  
                  
                  17,655,963Unproved
      properties:Oil
      and gas leasehold costs
                  
                  
                  944,359
                  
                  
                  
                  30,757,344Drilling
      in progress
                  
                  
                  4,924,395
                  
                  
                  
                  —Total
      unproved properties
                  
                  
                  5,868,754
                  
                  
                  
                  30,757,344Net
      capitalized costs
                  
                  $
                  45,701,745
                  
                  
                  $
                  48,413,307




The costs
incurred in oil and gas acquisition, exploration and development activities are
as follows:





Period
      Ended December 31,2008
                      
                      
                      2007Property
      acquisition costs, proved
                      
                      $
                      15,850,500
                      
                      
                      $
                      11,933,621Property
      acquisition costs, unproved
                      
                      
                      (17,770,980
                      )
                      
                      
                      29,518,394Exploration
      costs
                      
                      
                      2,062,329
                      
                      
                      
                      —Development
      costs
                      
                      
                      9,011,046
                      
                      
                      
                      8,585,879$
                      9,152,895
                      
                      
                      $
                      50,037,894




The
following costs of unproved properties are capitalized as part of the Company’s
oil and gas properties.  These costs are excluded from the calculation
of DD&A until such time the related drilling programs are completed and the
costs can be evaluated as proved, or until the costs are determined to be
impaired.


December
      31,2008
                  
                  
                  2007Unproved
      properties:Oil
      and gas leasehold acreage acquisition costs
                  
                  $
                  944,359
                  
                  
                  $
                  30,757,344Drilling
      in progress
                  
                  
                  4,924,395
                  
                  
                  
                  —$
                  5,868,754
                  
                  
                  $
                  30,757,344




Oil
and Gas Reserves and Related Financial Data (Unaudited)




Changes
in estimated net quantities of conventional oil and gas reserves, all of which
are located within the United States, are as follows:


Oil
                    
                    
                    Gas(Bbls)
                    
                    
                    (Mcf)Proved developed and undeveloped
      reserves:Proved
      reserves, December 31, 2006
                    
                    
                    58,647
                    
                    
                    
                    —Extensions
      and discoveries
                    
                    
                    —
                    
                    
                    
                    —Reserves
      purchased
                    
                    
                    447,316
                    
                    
                    
                    1,448,133Sales
      volumes
                    
                    
                    (121,096
                    )
                    
                    
                    (291,689
                    )Revisions
      of previous engineering estimates
                    
                    
                    3,790
                    
                    
                    
                    —Reserves
      transferred
                    
                    
                    —
                    
                    
                    
                    —Proved
      reserves, December 31, 2007
                    
                    
                    388,657
                    
                    
                    
                    1,156,444Extensions
      and discoveries
                    
                    
                    2,772,680
                    
                    
                    
                    11,653,660Reserves
      purchased
                    
                    
                    —
                    
                    
                    
                    —Sales
      volumes
                    
                    
                    (77,062
                    )
                    
                    
                    (153,917
                    )Revisions
      of previous engineering estimates
                    
                    
                    (6,455
                    )
                    
                    
                    (575,587
                    )Reserves
      transferred
                    
                    
                    —
                    
                    
                    
                    —Proved
      reserves, December 31, 2008
                    
                    
                    3,077,820
                    
                    
                    
                    12,080,600Proved developed reserves:Proved
      developed reserves, December 31, 2008
                    
                    
                    350,290
                    
                    
                    
                    1,615,350Proved
      developed reserves, December 31, 2007
                    
                    
                    338,657
                    
                    
                    
                    1,156,444Proved
      developed reserves, December 31, 2006
                    
                    
                    58,647
                    
                    
                    
                    —




F-21




The
following table sets forth a standardized measure of the estimated discounted
future net cash flows attributable to the Company’s proved developed and
undeveloped oil and gas reserves. Prices used to determine future cash inflows
were based on the December 31, 2008 period end price for the proved developed
reserves of $5.71 per mcf of gas and $44.60 per barrel of oil. The future
production and development costs represent the estimated future expenditures to
be incurred in developing and producing the proved reserves, assuming
continuation of existing economic conditions. Future income tax expense was
estimated at 34% for combined federal and state rate, after giving consideration
to the Company’s net operating loss carryforward and other tax
attributes.





2008
                  
                  
                  2007Future
      cash inflows
                  
                  $
                  206,061,190
                  
                  
                  $
                  45,940,000Future
      production costs
                  
                  
                  (38,515,230
                  )
                  
                  
                  (16,352,400
                  )Future
      development costs
                  
                  
                  (24,114,680
                  )
                  
                  
                  (2,619,600
                  )Future
      income tax expense
                  
                  
                  (51,499,632
                  )
                  
                  
                  (8,591,000
                  )Future
      net cash flows
                  
                  
                  91,931,648
                  
                  
                  
                  18,377,00010%
      annual discount to reflect timing of net cash flows
                  
                  
                  (46,856,548
                  )
                  
                  
                  (5,702,000
                  )Standardized
      measure of discounted future net cash flows relating to proved
      reserves
                  
                  $
                  45,075,100
                  
                  
                  $
                  12,675,000




The
principal factors comprising the changes in the standardized measure of
discounted future net cash flows are as follows for the years ended December
31:





2008
                        
                        
                        
                        2007Standardized
      measure, beginning of year
                        
                        $
                        12,675,000
                        
                        
                        $
                        860,200Extensions
      and discoveries
                        
                        
                        64,230,640
                        
                        
                        
                        -Reserves
      purchased
                        
                        
                        -
                        
                        
                        
                        14,701,100Development
      costs incurred
                        
                        
                        205,752
                        
                        
                        
                        -Sales
      and transfers, net of production costs
                        
                        
                        (5,088,723
                        )
                        
                        
                        (3,155,200
                        )Revisions
      in quantity and price estimates
                        
                        
                        (9,091,739
                        )
                        
                        
                        268,900Net
      change in income taxes
                        
                        
                        (19,680,300
                        )
                        
                        
                        -Accretion
      of discount
                        
                        
                        1,824,470
                        
                        
                        
                        -Standardized
      measure, end of year
                        
                        $
                        45,075,100
                        
                        
                        $
                        12,675,000




F-22





Exhibit
Index




Number
            
            Description
            Ref.3.1
            
            Articles
      of Incorporation (Nevada)
            (1)3.2
            
            By-laws
      (as amended February 6, 2009)
            *4.1
            
            Rights
      of securities holders – Common Stock (Articles of Incorporation, Sections
      5 and 6)
            (1)4.2
            
            Rights
      of securities holders – Common Stock (Amended By-laws, Sections II, VIII.
      IX and XII)
            **4.3
            
            Rights
      of securities holders – Certificate of Designations Series A Convertible
      Preferred Stock
            *10.1
            
            Employment
      Agreement - Michael J. Pawelek, CEO
            (2)10.2
            
            Employment
      Agreement - Wayne Psencik, COO
            (2)10.3
            
            Employment
      Agreement - Sherry L. Spurlock, CFO
            (2)10.4
            
            Employment
      Agreement – Theodore J. Wicks, EVP Corporate Development
            (3)10.5
            
            Securities
      Purchase Agreement, dated April 1, 2008, among the Company, Longview Fund,
      L.P. and Longview Marquis Master Fund, L.P.
            (4)10.6
            
            Amendment
      to Senior Notes and Purchase Agreement, dated June 30, 2008, among the
      Company, Longview Fund, L.P. and Longview Marquis Master Fund,
      L.P.
            (5)10.7
            
            Securities
      Purchase Agreement between the Company and Longview Marquis Master Fund,
      L.P, dated as of September 19, 2008
            (6)10.8
            
            Form
      of BridgeNote
            (6)10.9
            
            Form
      of Bridge Security Agreement
            (6)10.10
            
            Form
      of Bridge Mortgage
            (6)10.11
            
            Form
      of Bridge Account Control Agreements
            (6)10.12
            
            Form
      of Bridge Guaranty
            (6)10.13
            
            Form
      of Bridge Pledge Agreement
            (6)10.14
            
            Form
      of Conveyances of Limited Overriding Royalty Interests
            (6)10.15
            
            Form
      of Intercreditor Agreement
            (6)10.16
            
            Form
      of Omnibus Amendment to Security Documents
            (6)10.17
            
            September
      2008 Waiver and Amendment
            (6)10.18
            
            Securities
      Exchange Agreement (Equity and Assets for Debt Exchange), dated February
      20, 2009 between the Company and Longview Fund, L.P
            (7)10.19
            
            Asset
      Purchase and Sale Agreement dated February 20, 2009 between the Company
      and Longview Fund, L.P
            (7)10.20
            
            Asset
      Purchase Waiver and Consent, dated February 20, 2009 by Longview Marquis
      Master Fund, L.P
            (7)21.1
            
            Subsidiaries
      of the Company31.1
            
            Principal
      Executive Officer Certification Pursuant to Item 601(b)(31) of Regulation
      S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
      2002
            *31.2
            
            Principal
      Financial Officer Certification Pursuant to Item 601(b)(31) of Regulation
      S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
      2002
            *32.1
            
            Principal
      Executive Officer Certification Pursuant to Item 601(b)(32) of Regulation
      S-K, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002
            *32.2
            
            Principal
      Financial Officer Certification Pursuant to Item 601(b)(32) of Regulation
      S-K, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002
            **


*
              Filed
      herewith
 **
              Included in Exhibit
      3.2
 (1)
              Previously
      filed with the Commission as an exhibit to the Company’s Form 10-SB on
      April 30, 2004
 (2)
              Previously
      filed with the Commission as an exhibit to the Company’s Form 8-K on June
      25, 2008
 (3)
              Previously
      filed with the Commission as an exhibit to the Company’s Form 8-K on
      October 2, 2008
 (4)
              Previously
      filed with the Commission as an exhibit to the Company’s Form 8-K on April
      15, 2008
 (5)
              Previously
      filed with the Commission as an exhibit to the Company’s Form 8-K on July
      2, 2008
 (6)
              Previously
      filed with the Commission as an exhibit to the Company’s Form 8-K on
      September 24, 2008
 (7)
              Previously
      filed with the Commission as an exhibit to the Company’s Form 8-K on
      February 23, 2009