UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


WASHINGTON,
DC 20549




FORM
10-K




(Mark
One)




x ANNUAL REPORT PURSUANT
TO SECTION 13 OR 15(d) OF THE SECURITIES


EXCHANGE
ACT OF 1934





For
the fiscal year ended December 31, 2009





o TRANSITION REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES


EXCHANGE
ACT OF 1934





For
the transition period from ______ to ______.




Commission
file number: 000-51553




PLATINUM
ENERGY RESOURCES, INC.


(Exact
name of registrant as specified in its charter)




Delaware
            
            14-1928384(State
      or other jurisdiction of incorporation or organization)
            
            (I.R.S.
      Employer Identification No.)




11490
      Westheimer Road, Suite 1000Houston,
      Texas
            77077(Address
      of principal executive offices)
            (zip
      code)Registrant’s
      telephone number, including area code
            (281)
      649-4500




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


None




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




Units,
each consisting of one share of common stock, par value


$0.0001
per share, and one warrant




Common
Stock, par value $0.0001 per share




Indicate by check mark if the
registrant is a well-known seasoned issuer, as defined in Rule 405 of the
Securities Act.


YesoNox





Indicate by check mark if the
registrant is not required to file reports pursuant to Section 13 or Section
15(d) of the Act.    Yeso
    Nox





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.


Yesx   Noo





Indicate by check mark whether the
registrant has submitted electronically and posted on its corporate Web site, if
any, every Interactive Data File required to be submitted and posted pursuant to
Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12
months (or for such shorter period that the registrant was required to submit
and post such files).    YesoNo  o





Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K (§ 229.405 of this Chapter) is not contained herein, and
will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K.o





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





Large accelerated
filero    Accelerated filero     Non-accelerated filer (Do not check
if a smaller reporting company)oSmaller
reporting companyx




Indicate by check mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act).    Yeso
   Nox





As
of June 30, 2009, the aggregate market value of the registrant’s common stock
held by non-affiliates of the registrant was $6,418,580 based on the closing
price as reported on the OTC Bulletin Board.





Indicate
the number of shares outstanding of each of the issuer’s classes of common
stock, as of the latest practicable date.





Class
            
            Outstanding at June 25,
      2010Common
      Stock, $0.0001 par value per share
            
            22,606,475 shares







PagePART
      IItem
      1.
                  Business.
                  
                  4Item
      1A.
                  Risk
      Factors.
                  
                  8Item
      1B.
                  Unresolved
      Staff Comments.
                  
                  14Item
      2.
                  Properties.
                  
                  14Item
      3.
                  Legal
      Proceedings.
                  
                  20Item
      4.
                  Reserved.
                  
                  22PART
      IIItem
      5.
                  Market For Registrant’s Common
      Equity, Related Stockholder Matters and Issuer Purchases of
       Equity
      Securities.
                  
                  23Item
      6.
                  Selected
      Financial Data.Item
      7.
                  Management’s Discussion and
      Analysis of Financial Condition and Results of
      Operations.
                  
                  23Item 7A.
                  Quantitative and Qualitative
      Disclosures About Market Risk.Item
      8.
                  Financial Statements and
      Supplementary Data.
                  
                  36Item
      9.
                  Changes
      in and Disagreements with Accountants on Accounting and Financial
      Disclosure.
                  
                  36Item 9A(T).
                  Controls and
      Procedures.
                  
                  36Item 9B.
                  Other
      Information.PART
      IIIItem
      10.
                  Directors, Executive Officers
      and Corporate Governance.
                  
                  37Item
      11.
                  Executive
      Compensation.
                  
                  39Item
      12.
                  Security
      Ownership of Certain Beneficial Owners and Management and Related
      Stockholder Matters.
                  
                  43Item
      13.
                  Certain
      Relationships and Related Transactions, and Director
      Independence.
                  
                  44Item
      14.
                  Principal Accounting Fees and
      Services.
                  
                  44PART
      IVItem
      15.
                  Exhibits,
      Financial Statement Schedules.
                  
                  46


2




FORWARD-LOOKING
STATEMENTS





The
statements contained in this report, other than statements of historical fact,
constitute forward-looking statements. Such statement include, without
limitation, all statements as to the production of natural gas and oil, product
price, natural gas and oil reserves, drilling and completion results, capital
expenditures and other such matters. These statements relate to events and/or
future financial performance, and involve known and unknown risks, uncertainties
and other factors that may cause our results, level of activity, performance or
achievements or the industry in which we operate to be materially different from
any future results, levels of activity, performance or achievements expressed or
implied by the forward-looking statements.  These risks and other
factors included those listed under “Risk Factors” and elsewhere in this
report.





In some
cases, you can identify forward-looking statements by terminology such as “may,”
“will,” “should,” “expects,” “intends,” “plans,” “anticipates,” “believes,”
“estimates,” “predicts,” “potential,” “continue” or the negative of these terms
or other comparable terminology. These statements are only predictions. Actual
events or results may differ materially. In evaluating these statements, you
should specifically consider various factors, including the risks outlined under
“Risk Factors.” These factors may cause our actual results to differ materially
from any forward-looking statement. Factors that could affect our actual results
and could cause actual results to differ materially from those in
forward-looking statements include, but are not limited to the
following:





·
              The
      volatility of realized natural gas and oil prices;


·
              The
      potential for additional impairment due to future decreases in natural gas
      and oil prices;


·
              Uncertainties
      about the estimated quantities of natural gas, and oil
      reserves;


·
              The
      discovery, estimation, development and replacement of natural gas and oil
      reserves;


·
              Our
      business and financial strategy;


·
              Our
      cash flow, liquidity and financial position;


·
              Our
      production volumes;


·
              Our
      operating expenses, general and administrative costs, and development
      costs;


·
              Our
      future operating results;


·
              Our
      prospect development and property acquisitions;


·
              The
      marketing of natural gas and oil;


·
              The
      impact of weather and the occurrence of natural disaster such as floods
      and hurricanes;


·
              Government
      regulation of the natural gas and oil industry;


·
              Environmental
      regulations;


·
              The
      effect of legislation, regulatory initiatives and litigation related to
      climate change;


·
              Developments
      in oil-producing and natural gas producing countries;
  and


·
            Our
      strategic plans, objectives, expectations and intentions for future
      operations.




Although
we believe that the expectations reflected in the forward-looking statements are
reasonable, we cannot guarantee future results, levels of activity, performance
or achievements.  Moreover, neither we nor any other person assumes
responsibility for the accuracy and completeness of these forward-looking
statements.  We do not intend to update any of the forward-looking
statements after the date of this report to confirm prior statements to actual
results.


3





PART
I




Item 1.  
 Business.





Platinum
Energy Resources, Inc. (which we refer to as “we,” “us,” “Platinum” or the
“Company”) is an independent oil and gas exploration and production ("E&P")
company. We have approximately 37,000 acres under lease in relatively long-lived
fields with well-established production histories.  Our properties are
concentrated primarily in the Gulf Coast region in Texas, the Permian Basin in
Texas and New Mexico, and the Fort Worth Basin in Texas.





Our
principal business strategy is to provide long-term growth in stockholder value
by drilling, developing and exploiting our oil and gas properties. We believe
there exists opportunities to exploit mature fields that may have substantial
remaining reserves. As the major, large independent oil and gas companies
focus on more costly and risky international and offshore prospects, the smaller
independents, such as Platinum, have an opportunity to take advantage
of the significant reserves left behind.




Our
exploration and production activities commenced in October 2007 upon our
acquisition of significantly all of the assets and liabilities of Tandem Energy
Corporation (“TEC”) including 21,000 acres under lease in Texas and New
Mexico.  Subsequent to the TEC acquisition we have completed a series
of low risk strategic acquisitions adding an additional 16,000 lease acres to
our portfolio, which we believe will complement our business plan.




In
addition we provide engineering and project management services to the oil and
gas industry and others, through our wholly owned subsidiary Maverick
Engineering Inc. (“Maverick”), which we acquired on April 29,
2008.  Following the consummation of this acquisition, we moved our
corporate headquarters to Maverick’s Houston office.




Business
Strategy





Platinum’s
long term strategy is to provide growth in stockholder value by drilling,
developing and exploiting our oil and gas properties.  The Company
maintains a large inventory of drilling and optimization projects to achieve
organic growth from its capital development program.  In general, we
seek to be the operator of wells in which we have a working interest. As
operator, we design and manage the development of a well and supervise operation
and maintenance activities on a day-to-day basis.   As of
December 31, 2009, we operated properties representing approximately 89
percent of our proved reserves. As the operator, we are able to better control
expenses, capital allocation, and the timing of exploitation and development
activities on our properties.   The number, types and location of
wells drilled varies depending on the Company’s capital budget, the cost of each
well, anticipated production and the estimated recoverable reserves attributable
to each well.





Due to
the recent downturn in the global economy as well as the decrease in natural gas
prices, we significantly reduced our capital expenditures and drilling activity
in 2009.   Our goal in 2010 will be to keep our exploration and
development capital expenditures within our cash flow from operations, while
maintaining our estimated proved reserve base and production, protecting against
lease expirations and non-consent penalties, and continuing to focus on cost
control.


4




Corporate
History





We
were incorporated in Delaware on April 25, 2005 as a blank check company for the
purpose of effecting a business combination with an unidentified operating
business in the global oil and natural gas industry. On October 28, 2005, we
consummated our IPO of 14,400,000 units with each unit consisting of one share
of our common stock, $0.0001 per share, and one warrant to purchase one share of
common stock at an exercise price of $6.00 per share. The units were sold at an
offering price of $8.00 per unit, generating gross proceeds of $115,200,000. In
October 2007, the Company acquired substantially all of the assets and assumed
all of the liabilities of TEC described below. Prior to the TEC
transaction, the Company had no operations other than conducting an initial
public offering and seeking a business combination. Effective on April 29, 2008,
Platinum acquired Maverick, an engineering services company.





Drilling,
Exploration and Production Activities





Platinum’s
exploration efforts are focused on discovering new reserves by drilling and
completing wells under our existing leases, as well as leases we may acquire in
the future. The investment associated with drilling a well and future
development of our leasehold acreage depends principally upon whether any
problems are encountered in drilling the wells, whether the wells, in the case
of gas wells, can be timely connected to existing infrastructure or will require
additional investment in infrastructure, and, if applicable, the amount of water
encountered in the wells.





Due to
the recent downturn in the global economy as well as the decrease in natural gas
prices, we reduced our capital expenditures and drilling activity in 2009. Our
goal in 2010 is to keep our exploration and development capital expenditures
within our cash flow from operations, while maintaining our estimated proved
reserve base and production, protecting against lease expirations and
non-consent penalties, and continuing to focus on cost control.





Title
to Properties





We
believe that the title to our leasehold properties is good and defensible in
accordance with standards generally acceptable in the oil and gas industry,
subject to exceptions that are not material as to detract substantially from the
use of the properties. Our leasehold properties are subject to royalty,
overriding royalty and other outstanding interests customary in the industry.
The properties may be subject to burdens such as liens incident to operating
agreements and taxes, development obligations under oil and gas leases, and
other encumbrances, easements and restrictions. We do not believe any of these
burdens will materially interfere with our use of these properties. For a
description of our oil and gas leasehold properties, see “Properties
- Current Oil and Gas Activities”.




As is
customary in the oil and gas industry, only a preliminary title examination is
conducted at the time properties believed to be suitable for drilling operations
are acquired. We rely upon oil and gas land men to conduct the title
examination. We intend to perform necessary curative work with respect to any
significant defects in title prior to proceeding with drilling
operations.





Competition





The oil
and natural gas business is highly competitive. We compete with private and
public companies in all facets of the oil and gas business, including suppliers
of energy and fuel to industrial, commercial and individual customers. Numerous
independent oil and gas companies, oil and gas syndicates and major oil and gas
companies actively seek out and bid for oil and gas prospects and properties as
well as for the services of third-party providers, such as drilling companies,
upon which we rely. Many of these companies not only explore for, produce and
market oil and gas, but also carry out refining operations and market the
resultant products on a worldwide basis. A substantial number of our competitors
have longer operating histories and substantially greater financial and
personnel resources than us.





Competitive
conditions may be substantially affected by various forms of energy legislation
and regulation considered from time to time by the government of the United
States and the states in which we have operations, as well as factors that we
cannot control, including international political conditions, overall levels of
supply and demand for oil and gas, and the markets for synthetic fuels and
alternative energy sources. Intense competition occurs with respect to
marketing, particularly of natural gas.


5




Regulatory
Matters





General. The availability of
a ready market for oil and gas production depends upon numerous factors beyond
our control. These factors include local, state, federal and international
regulation of oil and gas production and transportation, as well as regulations
governing environmental quality and pollution control, state limits on allowable
rates of production by a well or proration unit, the amount of oil and gas
available for sale, the availability of adequate pipeline and other
transportation and processing facilities, and the marketing of competitive
fuels. For example, in the case of gas wells, a productive well may be “shut-in”
because of an over-supply of gas or lack of an available pipeline in the areas
in which we may conduct operations. State and federal regulations are generally
intended to prevent waste of oil and gas, protect rights to produce oil and gas
between owners in a common reservoir, and control contamination of the
environment. Pipelines and gas plants are also subject to the jurisdiction of
various federal, state and local agencies that may affect the rates at which
they are able to process or transport gas from our properties.





Applicable
legislation is under constant review for amendment or expansion. These efforts
frequently result in an increase in the regulatory burden on companies in the
oil and gas industry and a consequent increase in the cost of doing business and
decrease in profitability. Numerous federal and state departments and agencies
issue rules and regulations imposing additional burdens on the oil and gas
industry that are often costly to comply with and carry substantial penalties
for non-compliance. Our production operations may be affected by changing tax
and other laws relating to the petroleum industry, constantly changing
administrative regulations and possible interruptions or termination by
government authorities.





Sales of Oil and Natural Gas.
Sales of any oil that we produce will be affected by the availability, terms and
costs of transportation. The rates, terms and conditions applicable to the
interstate transportation of oil by pipelines are regulated by the Federal
Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act. FERC
has implemented a simplified and generally applicable ratemaking methodology for
interstate oil pipelines to fulfill the requirements of Title VIII of the Energy
Policy Act of 1992 comprised of an indexing system to establish ceilings on
interstate oil pipeline rates. FERC has announced several important
transportation-related policy statements and rule changes, including a statement
of policy and final rule issued February 25, 2000, concerning alternatives to
its traditional cost-of-serve rate-making methodology to establish the rates
interstate pipelines may charge for their services. The final rule revises
FERC’s pricing policy and current regulatory framework to improve the efficiency
of the market and further enhance competition in natural gas
markets.





Sales of
any natural gas that we produce will be affected by the availability, terms and
costs of transportation. The rates, terms and conditions applicable to the
interstate transportation of gas by pipelines are regulated by FERC under the
Natural Gas Acts, as well as under Section 311 of the Natural Gas Policy Act.
Since 1985, the FERC has implemented regulations intended to increase
competition within the gas industry by making gas transportation more accessible
to gas buyers and sellers on an open-access, non-discriminatory
basis.





Pipelines. Pipelines that we
use to gather and transport our oil and gas are subject to regulation by the
Department of Transportation (“DOT”) under the Hazardous Liquids Pipeline Safety
Act of 1979, as amended (“HLPSA”), relating to the design, installation,
testing, construction, operation, replacement and management of pipeline
facilities. The HLPSA requires pipeline operators to comply with regulations
issued pursuant to HLPSA designed to permit access to and allowing copying of
records and to make certain reports and provide information as required by the
Secretary of Transportation.





State Restrictions. State
regulatory authorities have established rules and regulations requiring permits
for drilling operations, drilling bonds and reports concerning operations. Many
states have statutes and regulations governing various environmental and
conservation matters, including the unitization or pooling of oil and gas
properties and establishment of maximum rates of production from oil and gas
wells, and restricting production to the market demand for oil and gas. Such
statutes and regulations may limit the rate at which oil and gas could otherwise
be produced from our properties.


6




Most
states impose a production or severance tax with respect to the production and
sale of crude oil, natural gas and natural gas liquids within their respective
jurisdictions. State production taxes are generally applied as a percentage of
production or sales. In addition, in the event we conduct operations on federal
or state oil and gas leases, such operations must comply with numerous
regulatory restrictions, including various nondiscrimination statutes, royalty
and related valuation requirements, and certain of such operations must be
conducted pursuant to certain on-site security regulations and other appropriate
permits issued by the Bureau of Land Management or the Minerals Management
Service or other appropriate federal or state agencies.





Other. Oil and gas rights may
be held by individuals and corporations, and, in certain circumstances, by
governments having jurisdiction over the area in which such rights are located.
As a general rule, parties holding such rights grant licenses or leases to third
parties, such as us, to facilitate the exploration and development of these
rights. The terms of the licenses and leases are generally established to
require timely development. Notwithstanding the ownership of oil and gas rights,
the government of the jurisdiction in which the rights are located generally
retains authority over the manner of development of those rights.




Environmental
Matters





General. Our activities are
subject to local, state and federal laws and regulations governing environmental
quality and pollution control in the United States. The exploration, drilling
and production from wells, natural gas facilities, including the operation and
construction of pipelines, plants and other facilities for transporting,
processing, treating or storing natural gas and other products, are subject to
stringent environmental regulation by state and federal authorities, including
the Environmental Protection Agency (“EPA”). Such regulation can increase our
cost of planning, designing, installing and operating such
facilities.




Significant
fines and penalties may be imposed for the failure to comply with environmental
laws and regulations. Some environmental laws provide for joint and several
strict liability for remediation of releases of hazardous substances, rendering
a person liable for environmental damage without regard to negligence or fault
on the part of such person. In addition, we may be subject to claims alleging
personal injury or property damage as a result of alleged exposure to hazardous
substances, such as oil and gas related products.





Waste Disposal. We may
generate wastes, including hazardous wastes, that are subject to the federal
Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes.
The EPA has limited the disposal options for certain wastes that are designated
as hazardous under RCRA (“Hazardous Wastes”). Furthermore, it is possible that
certain wastes generated by our oil and gas operations that are currently exempt
from treatment as Hazardous Wastes may in the future be designated as Hazardous
Wastes, and therefore be subject to more rigorous and costly operating and
disposal requirements.





CERCLA. The federal
Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”),
also known as the “Superfund” law, generally imposes joint and several liability
for costs of investigation and remediation and for natural resource damages,
without regard to fault or the legality of the original conduct, on certain
classes of persons with respect to the release into the environment of
substances designated under CERCLA as hazardous substances (“Hazardous
Substances”). These classes of persons or so-called potentially responsible
parties include the current and certain past owners and operators of a facility
where there is or has been a release or threat of release of a Hazardous
Substance and persons who disposed of or arranged for the disposal of the
Hazardous Substances found at such a facility. CERCLA also authorizes the EPA
and, in some cases, third parties to take action in response to threats to the
public health or the environment and to seek to recover from the potentially
responsible parties the costs of such action. Although CERCLA generally exempts
petroleum from the definition of Hazardous Substances, we may have generated and
may generate wastes that fall within CERCLA’s definition of Hazardous
Substances.


7




Air Emissions. Our operations
may be subject to local, state and federal regulations for the control of
emissions of air pollution. Major sources of air pollutants are subject to more
stringent, federally imposed permitting requirements, including additional
permits. Producing wells may generate volatile organic compounds and nitrogen
oxides. If ozone problems are not resolved by the deadlines imposed by the
federal Clean Air Act, or on schedule to meet the standards, even more
restrictive requirements may be imposed, including financial penalties based
upon the quantity of ozone producing emissions. If we fail to comply strictly
with applicable air pollution regulations or permits, we may be subject to
monetary fines and be required to correct any identified deficiencies.
Alternatively, regulatory agencies could require us to forego construction,
modification or operation of certain air emission sources.




We
believe that we are in substantial compliance with current applicable
environmental laws and regulations and that, absent the occurrence of an
extraordinary event, compliance with existing local, state, federal and
international laws, rules and regulations governing the release of materials in
the environment or otherwise relating to the protection of the environment will
not have a material effect upon our business, financial condition or results of
operations. However, since environmental costs and liabilities are inherent in
our operations and in the operations of companies engaged in similar businesses
and since regulatory requirements frequently change and may become more
stringent, there can be no assurance that material costs and liabilities will
not be incurred in the future. Such costs may result in increased costs of
operations and acquisitions and decreased production.





Engineering
Activities





Maverick
provides engineering and construction services primarily for three types of
clients: (1) upstream oil and gas, domestic oil and gas producers and pipeline
companies; (2) industrial, petrochemical and refining plants; and (3)
infrastructure, private and public sectors, including state municipalities,
cities, and port authorities. Most of the Company’s work is performed under time
and material projects. In accordance with industry practice, substantially all
of our contracts are subject to cancellation or termination at the discretion of
the client. In a situation where a client terminates a contract, we would
ordinarily be entitled to receive payment for work performed up to the date of
termination and, in certain instances, we may be entitled to allowable
termination and cancellation costs.





Employees





At
December 31, 2009, we had 162 full-time employees, none of whom were
subject to a collective bargaining agreement.





Website
Address





The
Company maintains an internet website at www.platenergy.com.  The
Company makes available, free of charge, on its website, its annual reports on
Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and
amendments to those reports, as soon as reasonably practicable after providing
such reports to the SEC.  The information contained in or incorporated
into its website is not part of this report.




Item 1A. Risk Factors.





We
are subject to a high degree of risk. You should consider the risks described
below carefully and all of the information contained in this report. If any of
these risks, as well as other risks and uncertainties that are not currently
known to us or that we currently believe are not material, actually occur, our
business, financial condition and results of operations may suffer
significantly.


8




Since
Tandem Energy Holdings, Inc. was a publicly-traded shell corporation, our
acquisition of all of the assets and substantially all liabilities
of  its operating subsidiary  may subject us to successor
liability for the shell corporation’s known and unknown
liabilities.





On
October 26, 2007, we acquired substantially all of the assets and assumed
substantially all of the liabilities of Tandem Energy Corporation, a Colorado
corporation (“Old TEC”), a wholly owned subsidiary of Tandem Energy Holdings,
Inc. (“TEHI”).  TEHI was originally incorporated in Nevada as Las
Vegas Major League Sports, Inc. (“LVMS”) on July 22, 1993 with the plan of
engaging in certain business activities associated with the Canadian Football
League. In April 1994, it completed an initial public offering and began trading
under the symbol LVTD. In 1996, LVMS filed for bankruptcy protection and ceased
being a reporting company and also ceased operations and was considered to be a
“shell” corporation. In 1998, LVMS changed its name to Pacific Medical Group,
Inc. (“Pacific Medical”) in connection with a share exchange transaction with a
privately-held company whose business plan was to engage in the manufacture and
sale of medical products. To our knowledge, that business was unsuccessful and,
again, the company ceased operations and was considered to be a “shell”
corporation. In February, 2005, Pacific Medical Group changed its name to Tandem
Energy Holdings, Inc. and changed its trading symbol to TDYH.PK. In June, 2005,
Old TEC became a wholly-owned subsidiary of TEHI.





The risks
and uncertainties that were involved in the acquisition of Old TEC include that
we may be deemed to be a successor to TEHI, Old TEC’s parent, and thus subject
to the existing liabilities, including undisclosed liabilities, of the prior
shell corporation arising out of its prior business operations, financial
activities and equity dealings.  There is also a risk of litigation by
third parties or governmental investigations or proceedings. These risks and
uncertainties are generally greater when a corporation is used as a shell
vehicle more than once.





In
addition, TEHI was unable to locate corporate records and other material
agreements and documents relating to itself and its predecessors in name, LVTD
and Pacific Medical, for periods prior to mid-March 2005.   As a
result, no assurance can be given that successor liability claims will
not be made that actions taken by TEHI or its predecessors in name were
without proper corporate authorization.  Furthermore, no assurance can
be given that additional shares had not been issued by TEHI’s predecessors in
name and that therefore TEHI capitalization at the time of the acquisition was
accurate.  TEHI has been informed of a claim of ownership of 2.7
million shares of TEHI common stock.  These shares were not included
in the outstanding shares of TEHI at the time of the TEC acquisition and
are the subject of outstanding litigation against TEHI.  Such claim
could result in a successor liability claim against us.


9


The
volatility of oil and natural gas prices due to factors beyond our control
greatly affects our profitability.




Our
revenues, operating results, profitability, future rate of growth and the
carrying value of our oil and natural gas properties depend primarily upon the
prevailing prices for oil and natural gas. Historically, oil and natural gas
prices have been volatile and are subject to fluctuations in response to changes
in supply and demand, market uncertainty and a variety of additional factors
that are beyond our control. Any significant decline in the price of oil and
natural gas or any other unfavorable market conditions could have a material
adverse effect on our operations, financial condition and level of expenditures
for the development of our oil and natural gas reserves, and may result in write
downs of our investments as a result of our use of the full cost accounting
method.





Prices
for natural gas and crude oil fluctuate widely. These fluctuations in oil and
natural gas prices may result from relatively minor changes in the supply of and
demand for oil and natural gas, market uncertainty and other factors that are
beyond our control, including:





·
              Worldwide
      and domestic supplies of oil and natural gas;


·
              Weather
      conditions;


·
              The
      level of consumer demand;


·
              The
      price and availability of alternative fuels;


·
              The
      availability of drilling rigs and completion equipment;


·
              The
      proximity to, and capacity of transportation
facilities;


·
              The
      price and level of foreign imports;


·
              The
      nature and extent of domestic and foreign governmental regulation and
      taxation;


·
              Worldwide
      economic and political conditions;


·
              The
      effect of worldwide energy conservation measures;


·
              Political
      instability or armed conflicts in oil-producing regions;
    and


·
            The
      overall economic environment.





These
factors and the volatility of the energy markets make it extremely difficult to
predict future oil and natural gas price movements with any certainty. Declines
in oil and natural gas prices would not only reduce revenue, but could reduce
the amount of oil and natural gas that we can produce economically and, as a
result, could have a material adverse effect on our financial condition, results
of operations and reserves.





Oil and natural gas prices
could decline to a point where it would be uneconomic for us to sell our oil and
gas at those prices, which could result in a decision to shut in production
until the prices increase.





Our oil
and natural gas properties will become uneconomic when oil and natural prices
decline to the point at which our revenues are insufficient to recover our
lifting costs. For example, in 2009, our average oil and gas lifting costs were
approximately $25.56  per Boe. A market price decline below our
lifting costs would result in our having to shut in certain production until
prices increase.





Hedging
activities may prevent us from benefiting from price increases and may expose us
to other risks.





Hedging
is a strategy that can help a company to mitigate the volatility of oil and gas
prices by limiting its losses if oil and gas prices decline; however, this
strategy may also limit the potential gains that a company could realize if oil
and gas prices increase. From time to time, we use derivative instruments
(primarily collars and price swaps) to hedge the impact of market fluctuations
on natural gas and crude oil prices and net income and cash flow. To the extent
that we engage in hedging activities, we may be prevented from realizing the
benefits of price increases above the levels of the hedges. Hedging activities
are subject to risks associated with differences in prices at different
locations, particularly where transportation constraints restrict a producer’s
ability to deliver oil and gas volumes to the delivery point to which the
hedging transaction is indexed. Additionally, hedging strategies are normally
more effective with companies with a certain volume of production, and our
current oil production levels may not be sufficient to be able to employ a
meaningful hedging strategy.


10




Our ability to
sell crude oil and natural gas production could be materially harmed by failure
to obtain adequate services such as transportation and
processing.





The sale
of crude oil and natural gas production depends on a number of factors beyond
our control, including the availability, proximity and capacity of pipelines,
natural gas gathering systems and processing facilities. Any significant change
in market factors affecting these infrastructure facilities or our failure to
obtain these services on acceptable terms could materially harm our business. We
deliver crude oil and natural gas through gathering systems and pipelines that
we do not own. These facilities may be temporarily unavailable due to market
conditions or mechanical reasons or may become unavailable in the
future.





Our
proved reserves will generally decline as reserves are produced and as such,
success will depend on acquiring or finding additional reserves.





Our
future success depends upon our ability to find, develop or acquire additional
oil and natural gas reserves that are economically recoverable. According to
reports of proved reserves prepared as of December 31, 2009 by Williamson
Petroleum Consultants Inc., independent petroleum consultants, and by our own
engineers, our proved reserves will decline at a significant rate as reserves
are produced and, except to the extent that we conduct successful exploration or
development activities or acquire properties containing proved reserves, or
both, such reserves will continue to decline. To increase reserves and
production, we must commence drilling, workover or acquisition activities. There
can be no assurance, however, that we will have sufficient resources to
undertake these actions, that our drilling and workover projects or other
replacement activities will result in significant additional reserves or that we
will have success drilling productive wells at low finding and development
costs. Furthermore, although our revenues may increase if prevailing oil and
natural gas prices increase significantly, our finding costs for additional
reserves may also increase.




Approximately
57% of our proved reserves are classified as proved
undeveloped.





Approximately
57% of our reserves are classified as proved undeveloped reserves. The future
development of these undeveloped reserves into proved developed reserves is
highly dependent upon our ability to fund estimated total capital development
cost of approximately $23.3 million, of which $4.0 million, $5.8 million and
$10.2 million are expected to be incurred in 2010, 2011 and 2012, respectively.
If such development costs are not incurred or are substantially reduced, our
proved undeveloped and total proved reserves could be substantially reduced. The
reduction in such reserves could have a materially negative impact on our
ability to produce profitable future operations. The successful conversion of
these proved undeveloped reserves into proved developed reserves is dependent
upon the following:





·
            The
      funding of the estimated proved undeveloped capital development costs is
      highly dependent upon our ability to generate sufficient working capital
      through operating cash flows, and our ability to borrow funds and/or raise
      equity capital.





·
            Our
      ability to generate sufficient operating cash flows is highly dependent
      upon successful and profitable future operations and cash flows which
      could be negatively impacted by fluctuating oil and gas prices and
      increased operating costs. No assurance can be given that we will have
      successful and profitable future operations and positive future cash
      flows.





·
            Our
      ability to borrow funds in the future is dependent upon the terms of
      future loan agreements, borrowing base calculations and other lending and
      operating conditions. No assurance can be given that we will be able to
      secure future borrowings at competitive borrowing rates and conditions, if
      at all.





·
            Projections
      for proved undeveloped reserves are largely based on their analogy to
      similar producing properties and to volumetric calculations. Reserves
      projections based on analogy are subject to change due to subsequent
      changes in the analogous properties. Volumetric calculations are often
      based upon limited log and/or core analysis data and incomplete reservoir
      fluid and formation rock data. Since these limited data must frequently be
      extrapolated over an assumed drainage area, subsequent production
      performance trends or material balance calculations may cause the need for
      significant revisions to the estimates of
  reserves.





Estimates
of oil and natural gas depend on many assumptions that may vary substantially
from actual production.





There are
numerous uncertainties inherent in estimating quantities of proved reserves and
in projecting future rates of production and timing of expenditures, including
many factors beyond our control. The reserve information relating to proved
reserves set forth in this report represents only estimates based on reports of
proved reserves prepared as of December 31, 2009 by Williamson Petroleum
Consultants, independent petroleum engineers, and by our own engineers.
Williamson Petroleum Consultants was not engaged to evaluate and prepare reports
relating to the probable reserves on our properties and interests as these are
more uncertain than evaluations of proved reserves. Petroleum engineering is not
an exact science. Information relating to our proved oil and natural gas
reserves is based upon engineering estimates. Estimating quantities of proved
crude oil and natural gas reserves is a complex process. It requires
interpretations of available technical data and various assumptions, including
assumptions relating to economic factors. Any significant inaccuracies in these
interpretations or assumptions or changes of conditions could cause the
quantities of our reserves to be overstated.


11




To
prepare estimates of economically recoverable crude oil and natural gas reserves
and future net cash flows, engineers analyze many variable factors, such as
historical production from the area compared with production rates from other
producing areas. It is also necessary to analyze available geological,
geophysical, production and engineering data, and the extent, quality and
reliability of this data can vary. The process also involves economic
assumptions relating to commodity prices, production costs, severance and excise
taxes, capital expenditures and workover and remedial costs. For these reasons,
estimates of the economically recoverable quantities of oil and natural gas
attributable to any particular group of properties, classifications of such
reserves based on risk of recovery and estimates of the future net cash flows
expected there from prepared by different engineers or by the same engineers at
different times may vary substantially. Actual production, revenues and
expenditures with respect to our reserves will likely vary from estimates, and
such variations may be material.





Our
operations entail inherent casualty risks which may not be covered by adequate
insurance.





We must
continually acquire, explore and develop new oil and natural gas reserves to
replace those produced and sold. Our hydrocarbon reserves and revenues will
decline if we are not successful in our drilling, acquisition or exploration
activities. We hope to maintain our reserve base primarily through successful
exploration and production operations, but we may not be successful in this
regard. Casualty risks and other operating risks could cause reserves and
revenues to decline.





Although
many of our properties are located across Texas and southeast New Mexico and are
not confined to one geographic area, our Tomball field, the largest producer in
our current portfolio, and much of our Maverick business are located in the Gulf
Coast region of Texas, an area that may be subject to catastrophic weather and
natural disasters such as floods, earthquakes and hurricanes. If such disaster
were to occur, it could severely disrupt our operations in that area and results
of operations could be materially and adversely affected.  Our
operations are subject to inherent casualty risks such as fires, blowouts,
cratering and explosions. Other risks include pollution, the uncontrollable
flows of oil, natural gas, brine or well fluids. These risks may result in
injury or loss of life, suspension of operations, environmental damage or
property and equipment damage, all of which would cause us to experience
substantial financial loss.





Our
drilling operations involve risks from high pressures and from mechanical
difficulties such as stuck pipes, collapsed casings and separated cables. In
accordance with customary industry practice, we maintain insurance against some,
but not all, of these risks. There can be no assurance that any insurance will
be adequate to cover any losses or liabilities. We cannot predict the continued
availability of insurance, or its availability at premium levels that justify
its purchase. In addition, we may be liable for environmental damages caused by
previous owners of properties that we purchased, which liabilities would not be
covered by our insurance. We are currently unaware of any material liability we
may have for environmental damages caused by previous owners of properties
purchased by us.





Many
of our wells produce at very low production rates while producing waste water
many times that rate.





Many of
our wells produce at production rates as low as one Boe per day and produce
waste water at many times the rate of production. Even a modest decrease in oil
and gas prices may render these wells uneconomic to produce, when compared to
wells which produce at higher rates. Consequently, these uneconomic wells could
cause a downward revision in our oil and gas reserves.





Our
operations also entail significant operating risks.





Our
drilling activities involve risks, such as drilling non-productive wells or dry
holes, which are beyond our control. The cost of drilling and operating wells
and of installing production facilities and pipelines is uncertain. Cost
overruns are common risks that often make a project uneconomical. The decision
to purchase and to exploit a property depends on the evaluations made by reserve
engineers, the results of which are often inconclusive or subject to multiple
interpretations. We may also decide to reduce or cease its drilling operations
due to title problems, weather conditions, noncompliance with governmental
requirements or shortages and delays in the delivery or availability of
equipment or fabrication yards.


12




Our
operations are subject to various governmental regulations that require
compliance that can be burdensome and expensive.





Our oil
and natural gas operations are subject to extensive federal, state and local
governmental regulations that may be changed from time to time in response to
economic and political conditions. Matters subject to regulation relate to the
general population’s health and safety and are associated with compliance and
permitting obligations including regulations related to discharge from drilling
operations, use, storage, handling, emission and disposal, drilling bonds,
reports concerning operations, the spacing of wells, unitization and pooling of
properties and taxation. From time to time, regulatory agencies have imposed
price controls and limitations on production by restricting the rate of flow of
oil and natural gas wells below actual production capacity to conserve supplies
of oil and natural gas. In addition, the production, handling, storage,
transportation and disposal of oil and natural gas, by-products thereof and
other substances and materials produced or used in connection with oil and
natural gas operations are subject to regulation under federal, state and local
laws and regulations primarily relating to protection of human health and the
environment. These laws and regulations have continually imposed increasingly
strict requirements for water and air pollution control and solid waste
management, and compliance with these laws may cause delays in the additional
drilling and development of our properties. Significant expenditures may be
required to comply with governmental laws and regulations applicable to us. We
believe the trend of more expansive and stricter environmental legislation and
regulations will continue. While, historically, we have not experienced any
material adverse effect from regulatory delays, there can be no assurance that
such delays will not occur for us in the future.





Price
declines have resulted in and may in the future result in write-downs of our
asset carrying values.





Commodity
prices have a significant impact on the present value of our proved
reserves.  Recent declines in oil and gas prices have resulted in
material downward revisions in the estimated present value of our proved
reserves.  Accounting rules require us to write down, as a non-cash
charge to earnings, the carrying value of our oil and gas properties for
impairments.  We are required to perform impairment tests on our
assets periodically and whenever events or changes in circumstances warrant a
review of our assets.  To the extent such tests indicate a reduction
of the estimated useful life or estimated future cash flows of our assets, the
carrying value may not be recoverable and therefore requires a
write-down.  We recorded impairments of property and equipment
totaling $16.6 million in 2009 and we may incur impairment charges in the
future, which could have a material adverse effect on our results of operations
in the period incurred.





Our method of
accounting for investments in oil and natural gas properties may result in
impairment of asset value, which could affect our stockholder equity and net
profit or loss.





We follow
the full cost method of accounting for our crude oil and natural gas properties.
Under this method, all direct costs and certain directly related internal costs
associated with acquisition of properties and successful, as well as
unsuccessful, exploration and development activities are capitalized.
Depreciation, depletion and amortization of capitalized crude oil and natural
gas properties and estimated future development costs, excluding unproved
properties, are based on the unit-of-production method based on proved reserves.
Net capitalized costs of crude and natural gas properties, as adjusted for asset
retirement obligations, net of salvage value, are limited, by country, to the
lower of unamortized cost or the cost ceiling, defined as the sum of the present
value of estimated future net revenues from proved reserves based on unescalated
average prices for the preceding 12 months, discounted at 10%, plus the cost of
properties not being amortized, if any, plus the lower of cost or estimated fair
value of unproved properties included in the costs being amortized, if any, less
related income taxes. Excess costs are charged to proved property impairment
expense. No gain or loss is recognized upon sale or disposition of crude oil and
natural gas properties, except in unusual circumstances.





Properties
that we acquire may not produce as projected, and we may be unable to identify
liabilities associated with the properties or obtain protection from sellers
against them.





As part
of our business strategy, we continually seek acquisitions of oil and gas
properties. The successful acquisition of oil and natural gas properties
requires assessment of many factors, which are inherently inexact and may be
inaccurate, including the following:





·
            future
      oil and natural gas prices;





·
            the
      amount of recoverable reserves;





·
            future
      operating costs;





·
            future
      development costs;





·
            failure
      of titles to properties;





·
            costs
      and timing of plugging and abandoning wells;
and





·
            potential
      environmental and other
liabilities.





Our
assessment will not necessarily reveal all existing or potential problems, nor
will it permit us to become familiar enough with the properties to assess fully
their capabilities and deficiencies. With respect to properties on which there
is current production, we may not inspect every well location, every potential
well location, or pipeline in the course of our due diligence. Inspections may
not reveal structural and environmental problems such as pipeline corrosion or
groundwater contamination. We may not be able to obtain or recover on
contractual indemnities from the seller for liabilities that it created. 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.


13




Oil
and gas drilling and producing operations can be hazardous and may expose us to
environmental liabilities.





Our oil
and gas operations will subject us to many risks, including well blowouts,
cratering and explosions, pipe failure, fires, formations with abnormal
pressures, uncontrollable flows of oil, natural gas, brine or well fluids, and
other environmental hazards and risks. If any of these risks occur, we could
sustain substantial losses as a result of:




·
              injury
      or loss of life;
 
 ·
              severe
      damage to or destruction of property, natural resources and
      equipment;
 
 ·
              pollution
      or other environmental damage;
 
 ·
              clean-up
      responsibilities;
 
 ·
              regulatory
      investigations and penalties; and
 
 ·
              Suspension
      of operations.




Our
liability for environmental hazards could include those created either by the
previous owners of properties that we purchase or lease or by acquired companies
prior to the date we acquire them. We expect to maintain insurance against some,
but not all, of the risks described above. Our insurance may not be adequate to
cover casualty losses or liabilities. Also, we may not be able to obtain
insurance at premium levels that justify its purchase.




Terrorist
activities and military and other actions could adversely affect our
business.





Terrorist
attacks and the threat of terrorist attacks, whether domestic or foreign, as
well as the military or other actions taken in response to these acts, cause
instability in the global financial and energy markets. The United States
government has issued public warnings that indicate that energy assets might be
specific targets of terrorist organizations. These actions could adversely
affect us, in unpredictable ways, including the disruption of fuel supplies and
markets, increased volatility in crude oil and natural gas prices, or the
possibility that the infrastructure on which we rely could be a direct target or
an indirect casualty of an act of terror.





Maverick,
our wholly owned subsidiary, is dependent upon a small number of customers for a
large portion of its net revenues, and a decline in sales to its major customers
could harm Maverick's results of operations.





During
2009 and 2008, Maverick’s six largest customers, accounted for approximately 68%
and 71%, respectively, of net revenues attributable to the engineering division
excluding intercompany revenues.  Maverick's customer concentration
could increase or decrease depending on future customer requirements, which will
depend in large part on business conditions in the market sectors in which
Maverick's customers participate. The loss of one or more major customers or a
decline in sales to Maverick’s major customers could significantly harm
Maverick's business and results of operations. If Maverick is not able to expand
its customer base, it will continue to depend upon a small number of customers
for a significant percentage of its sales. There can be no assurance that its
current customers will not reduce the amount of services for which Maverick is
retained or otherwise terminate their relationship with Maverick.




Risk
of Going Concern
 
 The
Company has a going concern risk, since its inception the Company has incurred
cumulative losses of $111,276,255 through December 31, 2009. The Company’s line
of credit, with Bank of Texas, matured on June 1, 2010. Through June 30, 2010,
there have been no notices of foreclosures on the Company’s assets that secure
the debt, however the company does not currently have sufficient liquid assets
pay the balance of the Senior Credit Facility. See Note 2 to the financial
statements for a further discussion.




Item 1B. Unresolved Staff
Comments.





Not
applicable.





Item 2.   Properties.





Platinum’s
principal executive offices are located at 11490 Westheimer Road, Suite 1000,
Houston, Texas 77077.   We also maintain division offices in
Victoria, Corpus Christi and Yoakum, Texas.





Current
Oil and Gas Activities





We own
core producing and non-producing oil and natural gas properties in Texas and New
Mexico.  The following is a summary of our major operating
areas.


14


Tomball Field. We own an
interest in, and are operator of, oil and natural gas properties in the Tomball
Field, which is located in Harris County, Texas, and is approximately 30 miles
northwest of Houston, Texas. The Tomball Field contains multiple productive
formations ranging in depth from 1,000 to 9,000 feet, including the Yegua,
Cockfield, and Wilcox. Current operations consist of 19 producing wells and 6
water disposal wells. At December 31, 2009, we held 7,000 acres and had an
inventory of 3 proved undeveloped locations in the Tomball Field. We own a 100%
working interest and net revenue interests ranging from 84.5% to 87.5%. TEC
began operating the Tomball field in 1996, but it has been producing
continuously since 1930. The current daily net production from the field is
approximately 251.6 Bbls of oil and 723.2 Mcf of gas per day. The field is also
producing approximately 16,000 Bbls of water per day.





Ira Field. We own an interest
in, and are operator of, an oil production unit in the Ira Field, which is
located in Scurry County, Texas, and is approximately 75 miles northeast of
Midland, Texas. The Ira Field production is from the San Andres formation at
approximately 1,800 feet. Current operations consist of 150 producing wells and
75 water injection wells. At December 31, 2009, we held 3,600 acres and had an
inventory of 76 proved undeveloped locations in the Ira Field. We own an 88%
working interest and 72% net revenue interest. TEC, through it predecessor in
interest, began operating the IRA Field in 2004, but the IRA Field has been
producing continuously since 1955. The current daily net production from the
field is approximately 105.3 Bbls of oil per day. The field is also producing
approximately 4,000 Bbls of water per day.





Ball Field. We own an
interest in, and are operator of, oil and natural gas properties in the Ball
Field, which is located in Palo Pinto County, Texas, and is approximately 75
miles west of Fort Worth, Texas. The Ball Field contains multiple productive
formations ranging in depth from 3,000 to 3,800 feet, including the Big Saline,
Duffer, and Barnett Shale. Current operations consist of 17 producing wells and
1 water disposal well. At December 31, 2009, we held 4,900 acres and had an
inventory of 17 proved undeveloped locations in the Ball Field. We own working
interests ranging from 50% to 100%, and net revenue interests ranging from 40.3%
to 87.5%. TEC began operating the Ball Field in 1993, but it has been producing
continuously since 1930. The current daily net production from the field is
approximately 416 Mcf of gas per day. The field is also producing approximately
495 Bbls of water per day.   On December 28, 2007 we acquired an additional
50% working interest in the Barnett Shale acreage for approximately $920,000.
This acquisition increased our net acreage position by 2,300 net acres and gave
us a 100% working interest in the Barnett. We have completed a 3 D seismic
program and plan to begin a horizontal drilling program in the Barnett as soon
as the economic climate improves.





Ballard Field. We own an
interest in, and are operator of, an oil production unit in the Ballard Field,
which is located in Eddy County, New Mexico, and is approximately 150 miles
northwest of Midland, Texas. The Ballard Field contains multiple productive
formations ranging in depth from 2,000 to 3,000 feet, including the Yates,
Grayburg, and San Andres. Current operations consist of 46 producing wells and
26 water injection wells. During 2008 we drilled and completed 6 proved
undeveloped locations.  All 6 wells are currently
producing.  At December 31, 2009, we held approximately 3,000 net
acres. We own an 86% working interest and 78.7% net revenue interest. TEC,
through its predecessor in interest, began operating the Ballard Field in 2004,
but it has been producing continuously since 1965. The current daily net
production from the field is approximately 86.9 Bbls of oil and 44.6 Mcf of gas
per day. The field is also producing approximately 1,300 Bbls of water per
day.





USM Field. We own an interest
in, and are operator of, oil and natural gas properties in the USM Field, which
is located in Pecos County, Texas, and is approximately 120 miles southwest of
Midland, Texas. The USM Field production is from the Yates and Queen formations
at approximately 3,200 feet. Current operations consist of 54 producing wells
and 4 water disposal wells. During 2008 we drilled and completed 4 proved
undeveloped locations.  All 4 wells are currently
producing.  At December 31, 2009, we held approximately 3,000 net
acres in the field. We own working interests ranging from 90% to 100%, and net
revenue interests ranging from 79.3% to 89.6%. TEC, through its predecessor in
interest, began operating the USM Field in 2004, but it has been producing
continuously since 1985. The current daily net production from the field is
approximately 44.9 Bbls of oil and 106.4  Mcf of gas per day. The
field is also producing approximately 80 Bbls of water per day.





Choate Field. We own an
interest in, and are operator of, oil and natural gas properties in the Choate
Field, which is located in Hardin County, Texas, and is approximately 35 miles
northwest of Beaumont, Texas. The Choate Field production is from sand lenses
flanking a salt dome ranging in depth from 1,000 to 2,500 feet. Current
operations consist of 23 producing wells. During 2008, we drilled 11 proved
undeveloped locations, 9 of which were successful and are currently
producing.  At December 31, 2009, we held 50 acres and had an
inventory of 6 proved undeveloped locations in the Choate Field. We own a 75%
working interest and 57% net revenue interest. TEC, through its predecessor in
interest, began operating the Choate Field in 2004, but it has been producing
continuously since 1960. The current daily net production from the field is
approximately 71.1 Bbls of oil per day. The field is also producing
approximately 200 Bbls of water per day.





Lothian Properties. In
December 2007 we purchased, for $6.2 million plus customary closing adjustments,
approximately 200 producing wells from Lothian Oil and Gas, Inc. The Lothian
assets acquired consist of oil and gas properties located in Chavez, Lea and
Eddy counties, New Mexico and are adjacent to or near our Ballard Field. The
current net production is approximately 80.7 Bbls of oil and 89.0 Mcf of gas per
day.  The field is also producing approximately 23 Bbls of water per
day.





Other. We own numerous small
mineral, royalty and non-operated working interests in various oil and natural
gas properties located in Texas, New Mexico, Louisiana, Montana, and North
Dakota.


15




Below is
a map indicating the locations of the Company’s significant operated properties
in Texas and New Mexico.









Natural
Gas and Oil Data




In January 2009 the SEC issued Release
No. 33-8995, “Modernization of Oil and Gas Reporting” (Release 33-8995),
amending oil and gas reporting requirements under Rule 4-10 of
Regulation S-X and Industry Guide 2 in Regulation S-K and bringing
full-cost accounting rules into alignment with the revised disclosure
requirements.  The new rules revised certain definitions and terms,
including the definition of proved reserves, which was revised to indicate that
entities must use the unweighted arithmetic average of the
first-day-of-the-month commodity price over the preceding 12-month period,
rather than the end-of-period price, when estimating whether reserve quantities
are economical to produce.  Likewise, the 12-month average price is
used to calculate cost center ceilings for impairment and to compute
depreciation, depletion, and amortization.  Another significant
provision of the new rules is a general requirement that, subject to limited
exceptions, proved undeveloped reserves may only be booked if they relate to
wells scheduled to be drilled within five years of booking.





In
January 2010 the Financial Accounting Standards Board (FASB) issued Accounting
Standards Update (ASU) No. 2010-03, “Oil and Gas Reserve
Estimation and Disclosures” (ASU 2010-03), which amends Accounting Standards
Codification (ASC) Topic 932, “Extractive Industries — Oil and Gas” to
align the guidance with the changes made by the SEC. The Company adopted Release
33-8995 and the amendments to ASC Topic 932 resulting from ASU 2010-03
(collectively, the Modernization Rules) effective December 31,
2009.




Estimated
Proved Reserves and Future Net Cash Flows




Proved
oil and gas reserves are the estimated quantities of natural gas, crude oil, and
condensate that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
conditions, operating conditions, and government regulations. Reserve estimates
are considered proved if they are economically producible and are 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 using reliable
technology establishes the reasonable certainty for the engineering analysis on
which the project or program is based. Economically producible means a resource
which generates revenue that exceeds, or is reasonably expected to exceed, the
costs of the operation. Reasonable certainty means a high degree of confidence
that the quantities will be recovered. Reliable technology is a grouping of one
or more technologies (including computational methods) that has been
field-tested and has been demonstrated to provide reasonably certain results
with consistency and repeatability in the formation being evaluated or in an
analogous formation. Estimated proved developed oil and gas reserves can be
expected to be recovered through existing wells with existing equipment and
operating methods.


16




Proved
undeveloped (PUD) reserves include those 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. Undeveloped reserves
may be classified as proved reserves on undrilled acreage directly offsetting
development areas that are reasonably certain of production when drilled, or
where reliable technology provides reasonable certainty of economic
productivity. Undrilled locations may be classified as having undeveloped
reserves only if a development plan has been adopted indicating that they are
scheduled to be drilled within five years, unless specific circumstances justify
a longer time period.





Qualifications
of Technical Persons and Internal Controls over Reserves Estimation
Process





Our
proved reserve information as of December 31, 2009, included in this Annual
Report was estimated by our independent petroleum engineers, Williamson
Petroleum Consultants, Inc., in accordance with generally accepted petroleum
engineering and evaluation principles and definitions and guidelines established
by the SEC.  The technical persons responsible
for  preparing the reserve estimates presented herein meet the
requirements qualifications, independence, objectivity, and confidentiality set
forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas
Reserves Information promulgated by the Society of Petroleum
Engineers.





We
maintain an internal staff of petroleum engineers who work closely with our
independent petroleum engineers to ensure the integrity, accuracy and timeliness
furnished to Williamson Petroleum Consultants, Inc. in their reserves estimation
process.  In the fourth quarter, our technical team met on a regular
basis with representatives of Williamson Petroleum Consultants, Inc. to review
properties and discuss methods and assumptions used in Williamson Petroleum
Consultant’s preparation  of year end reserves
estimates.  While we have no formal committee specifically designated
to review reserves reporting and the reserved estimation process, the Williamson
report is reviewed by our senior management and internal technical
staff.  Additionally, our senior management reviews and approves any
internally estimated significant changes to our proved reserves on a quarterly
basis.





Platinum’s
proved reserves are estimated at the property level and compiled for reporting
purposes by our operations staff. Our operations staff interacts with our field
managers and with accounting and production employees to obtain the necessary
data for projecting future production, costs, net revenues and ultimate
recoverable reserves. All relevant data is compiled in a computer database
application, to which only authorized personnel are given security access rights
consistent with their assigned job function. Reserves are reviewed internally
with senior management on a semi-annual basis. Annually, each property is
reviewed in detail by our operating managers to ensure forecasts of operating
expenses, netback prices, production trends and development timing are
reasonable.





Platinum
emphasizes that its reported reserves are reasonably certain estimates which, by
their very nature, are subject to revision. As additional geosciences,
engineering and economic data are obtained, proved reserve estimates are much
more likely to increase or remain constant than to decrease. These estimates are
reviewed throughout the year and revised either upward or downward, as
warranted.





Platinum’s
Operations Manager, Rusty Arnold, is the person primarily responsible for
overseeing the preparation of our internal reserve estimates and for
coordinating any reserves audits conducted by a third-party engineering firm.
Mr. Arnold is a graduate of Brigham Young University with Bachelor of
Science and Master of Science degrees in Electrical Engineering. He has over
28 years of industry experience.





The
estimate of reserves disclosed in this annual report on Form 10-K is
prepared by Williamson Petroleum Consultants, Inc. (Williamson). See the summary
of Williamson’s report as of December 31, 2009 included as an exhibit to
this Form 10-K.  Estimates of reserves as of year-end 2009 were
prepared using an average price equal to the unweighted arithmetic average of
hydrocarbon prices on the first day of each month within the 12-month period
ended December 31, 2009, in accordance with revised guidelines of the SEC,
first applicable to reserves estimates prepared as of year-end 2009. Estimates
of reserves as of year-end 2008 were prepared using constant prices and costs in
accordance with previous guidelines of the SEC, based on hydrocarbon prices
received on a field-by-field basis as of December 31,
2008.  Reserve estimates do not include any value for probable or
possible reserves that may exist, nor do they include any value for undeveloped
acreage. The reserve estimates represent our net revenue interest in our
properties.





Reserve
Technologies





Proved
reserves are those quantities of oil and natural gas, which, by analysis of
geosciences and engineering data, can be estimated with reasonable certainty to
be economically producible from a given date forward, from known reservoirs, and
under existing economic conditions, operating methods, and government
regulations.  The term “reasonable certainty” implies a high degree of
confidence that the quantities of oil and/or natural gas actually recovered will
equal or exceed the estimate.  To achieve reasonable certainty,
Williamson employed technologies that have been demonstrated to yield results
with consistency and repeatability.  The technical and economic data
used in the estimation of our proved reserves include, but are not limited to,
well logs, geologic maps, production data, seismic data, well test data,
historical price and cost information and property ownership
interest.


17




Proved
Reserves





The
following table shows proved oil and gas reserves by field as of
December 31, 2009, based on average commodity prices in effect on the first
day of each month in 2009, held flat for the life of the production, except
where future oil and gas sales are covered by physical contract
terms:




Oil
                          
                          
                          Gas
                          
                          
                          Total(MMbbls)
                          
                          
                          (MMcf)
                          
                          
                          (MMboe)Proved
      Developed:Ballard
                          
                          
                          132
                          
                          
                          
                          84
                          
                          
                          
                          146Ball
      – Bird
                          
                          
                          -
                          
                          
                          
                          1,282
                          
                          
                          
                          214Choate
      – Batson
                          
                          
                          142
                          
                          
                          
                          -
                          
                          
                          
                          142Ira
                          
                          
                          59
                          
                          
                          
                          -
                          
                          
                          
                          59Lothian
                          
                          
                          179
                          
                          
                          
                          119
                          
                          
                          
                          198Tomball
                          
                          
                          624
                          
                          
                          
                          912
                          
                          
                          
                          776USM
      – Ft. Stockton
                          
                          
                          83
                          
                          
                          
                          214
                          
                          
                          
                          118Other
                          
                          
                          66
                          
                          
                          
                          1,302
                          
                          
                          
                          284Proved
      Undeveloped:Ball
      – Bird
                          
                          
                          -
                          
                          
                          
                          1,761
                          
                          
                          
                          294Choate
      – Batson
                          
                          
                          27
                          
                          
                          
                          -
                          
                          
                          
                          27Ira
                          
                          
                          875
                          
                          
                          
                          -
                          
                          
                          
                          875Tomball
                          
                          
                          -
                          
                          
                          
                          8,005
                          
                          
                          
                          1,334TOTAL
      PROVED
                          
                          
                          2,187
                          
                          
                          
                          13,677
                          
                          
                          
                          4,467





All of
our reserves are located in the United States of America.  As of
December 31, 2009, Platinum had total estimated proved reserves of 2,188 MM
barrels of crude oil and 13,677 MMcf of natural gas As of December 31,
2009, the Company’s proved developed reserves totaled 1,938,128 Boe, and
estimated PUD reserves totaled 2,529,112 Boe, or approximately 57 percent
of total proved reserves. Platinum has elected not to disclose probable or
possible reserves in this filing.





The
Company’s estimates of proved reserves, proved developed reserves and proved
undeveloped reserves as of December 31, 2009 and 2008, changes in estimated
proved reserves during the last two years, and estimates of future net cash
flows from proved reserves are contained in Note 18 — Supplemental Oil
and Gas Disclosures in the Notes to Consolidated Financial Statements set forth
in Part IV, Item 18 of this Form 10-K. Estimated future net cash
flows as of December 31, 2009, were calculated using a discount rate of
10 percent per annum, end of period costs, and an unweighted arithmetic
average of commodity prices in effect on the first day of each month in 2009,
held flat for the life of the production, except where prices are defined by
contractual arrangements. Future net cash flows as of December 31, 2008
were estimated using commodity prices in effect at December 31, 2008, in
accordance with the SEC guidelines in effect prior to the issuance of the
Modernization Rules.





The
Company has elected not to disclose the probable and possible developed and
undeveloped reserves.





Proved
Undeveloped Reserves





During
the year, Platinum converted 33.5 Mboe of proved undeveloped reserves to proved
developed reserves through development drilling activity.





During
the year a total of $251,000 was spent on projects associated with reserves that
were carried as PUD reserves at the end of 2008.  All of those
expenditures resulted in a conversion from proved undeveloped to proved
developed reserves during the year. All of our PUD reserve development activity
occurred in North America.





Proved
Reserves





As of
December 31, 2009, we had 4.5 million Boe of proved oil and natural gas
reserves, including 2.2 million barrels of oil and 13.7 million Mcf of natural
gas.  Using same prices as prices used for the reserve report, the
estimated standardized measure of discounted future net cash flows was $38.9
million.  The following table sets forth a summary of our estimated
net proved reserve information as of December 31, 2009:


18




Proved
                  Developed
                  Producing
                
                
                Proved
                  Developed
                  Non-
                  producing
                
                
                Proved
                  Undeveloped
                
                
                Total ProvedCrude
      oil (MBbl)
                
                
                1,235
                
                
                
                51
                
                
                
                902
                
                
                
                2,188Natural
      gas (MMcf)
                
                
                3,308
                
                
                
                605
                
                
                
                9,766
                
                
                
                13,679Barrel
      of oil equivalent (MBoe)
                
                
                1,786
                
                
                
                152
                
                
                
                2,530
                
                
                
                4,468Undiscounted
      future net revenue  (before CapEx)
                
                $
                32,777
                
                
                $
                3,495
                
                
                $
                59,277
                
                
                $
                95,549Estimated
      future capital expenditures
                
                
                -
                
                
                $
                447
                
                
                $
                23,308
                
                
                $
                23,755Undiscounted
      future net revenue (net of CapEx)
                
                $
                32,777
                
                
                $
                3,048
                
                
                $
                35,969
                
                
                $
                71,794Discounted
      future net Revenue (net of CapEx)
                
                
                
                
                
                
                
                
                
                
                
                
                
                $
                25,506





Platinum’s
estimated recoverable proved reserves have been determined using standard
geological and engineering methods generally accepted by the petroleum industry
and in accordance with SEC financial accounting and reporting
standards.  The estimated present value of proved reserves does not
give effect to indirect expenses such as general and administrative expenses,
debt service, depletion, depreciation and amortization, and does not include any
economic impact that may result from our hedging activities.





We
engaged Williamson Petroleum Consultants, Inc. ("WPC"), independent petroleum
engineers, to estimate our net proved reserves, projected future
production, estimated future net revenue attributable to our proved reserves,
and the present value of such estimated future net revenue as of
December 31, 2009.  WPC’s estimates were based upon a review of
production histories and other geologic, economic, ownership and engineering
data, much of which is provided by the Company.   For example, we
provide to WPC the estimated amount and timing of future operating costs and
development costs which may in fact vary considerably from historical results.
In addition, as various economic parameters change from year to year the
estimate of proved reserves also may change.





In
accordance with applicable financial accounting and reporting standards of the
SEC, the estimates of our proved reserves and the present value of proved
reserves set forth herein are made using average oil and gas sales prices for
the preceding 12 months and are held constant throughout the life of the
properties. Estimated quantities of proved reserves and their present value are
affected by changes in oil and gas prices.  The adjusted average
prices utilized for the purposes of estimating our proved reserves and the
present value of proved reserves as of December 31, 2009 were $56.63 per
Bbl of oil and $3.25 per Mcf of gas, as compared to $41.92 per Bbl of oil and
$5.29 per Mcf of gas as of December 31, 2008.





The
reserve information shown is estimated.  The accuracy of any reserve
estimate is a function of the quality of available geological, geophysical,
engineering and economic data, the precision of the engineering and geological
interpretation and judgment.  The estimates of reserves, future cash
flows and present value are based on various assumptions, including those
prescribed by the SEC, and are inherently imprecise.  Although we
believe these estimates are reasonable, actual future production, cash flows,
taxes, development expenditures, operating expenses and quantities of
recoverable oil and natural gas reserves may vary substantially from these
estimates.  Also, the use of a 10% discount factor for reporting
purposes may not necessarily represent the most appropriate discount factor,
given actual interest rates and risks to which our business or the oil and
natural gas industry in general are subject.





Drilling
Activity





The
following table sets forth the number of gross development wells and net
development wells (based on our proportionate working interest) drilled in which
we participated during 2009 and 2008.  No exploratory wells were
drilled during the presented periods.





Developmental WellsGross
                
                
                NetProductive
                
                
                Dry
                
                
                Total
                
                
                Productive
                
                
                Dry
                
                
                Total2009
                
                
                1.0
                
                
                
                0.0
                
                
                
                1.0
                
                
                
                0.5
                
                
                
                0.0
                
                
                
                0.52008
                
                
                37.0
                
                
                
                2.0
                
                
                
                39.0
                
                
                
                17.8
                
                
                
                1.1
                
                
                
                18.9





The
information contained in the foregoing table should not be considered indicative
of our future drilling performance, nor should it be assumed that there is any
necessary correlation between the number of productive wells drilled and the
amount of oil and gas that may ultimately be recovered.


19




Volumes,
Prices and Production Costs





The
following table sets forth certain information regarding the production volumes,
average volume weighted sales prices received, and average production costs
associated with our sales of oil and gas for the periods indicated:





For the Period2009
                
                
                2008Oil
      and Gas Production Data:Oil
      (MBls)
                
                
                259.6
                
                
                
                281.4Gas
      (MMcfs)
                
                
                709.6
                
                
                
                811.1Total
      (MBoe)
                
                
                377.9
                
                
                
                416.6Average
      Realized Prices (a):Oil
      ($/Bbl)
                
                $
                56.49
                
                
                $
                97.14Gas
      ($/Mcf)
                
                $
                3.54
                
                
                $
                8.40Average
      Production Costs:Production
      ($/Boe) (b)
                
                $
                25.56
                
                
                $
                33.54




(a)
            No
      derivatives were designated as cash flow hedges in the table
      above.  All gains or losses on settled derivatives were included
      in change in fair value of
  commodity derivatives.





(b)
            Includes
      direct lifting costs (labor, repairs and maintenance, materials and
      supplies), workover costs, administrative costs of production offices,
      insurance and property and severance
taxes.





Total
revenues and operating expenses should be included in table above.





Item 3.   Legal
Proceedings.





Exxon Mobil Corporation
f/k/a Exxon Corporation v. Tandem Energy Corporation f/k/a Merit Energy
Corporation, et al





On January
16th, 2008, Exxon Mobil Corporation filed a petition in the 270 th
District Court of Harris County, Texas, naming us as a defendant along with TEC
and a third party, Merenco Realty, Inc., demanding environmental remediation of
certain properties in Tomball, Texas. In 1996, pursuant to an assignment
agreement, Exxon Mobil sold certain oil and gas leasehold interests and real
estate interests in Tomball, Texas to TEC’s predecessor in interest, Merit
Energy Corporation. In 1999, TEC assigned its 50% undivided interest in one of
the tracts in the acquired property to Merenco, an affiliate of TEC, owned 50%
by our Chairman of the Board, Tim Culp. In October 2007, the Texas Railroad
Commission notified Exxon Mobil of an environmental site assessment alleging
soil and groundwater contamination for a site in the area of Tomball, Texas.
Exxon Mobil believes that the site is one which was sold to TEC and claims that
TEC is obligated to remediate the site under the assignment agreement. Exxon
Mobil has requested that the court declare the defendants obligated to restore
and remediate the properties and has requested any actual damages arising from
breach and attorneys’ fees. We believe that Exxon Mobil’s claim that TEC is
responsible for any remediation of such site is without merit and we intend to
vigorously defend ourselves against this claim. However, no assurance can be
given that we will prevail in this matter. We acquired substantially all the
assets and liabilities of TEC in the TEC acquisition. Merenco was not acquired
by us in the TEC acquisition and our Chairman, Tim Culp, continues to have a 50%
ownership interest in Merenco.


20




Miles Hyman v. KDR, et
al





On
November 11, 2008, Mr. Hyman, a former employee of KD Resources, filed a claim
against KD Resources and Platinum Energy stating that he was discharged from KD
Resources in violation of the Sarbanes-Oxley Act of 2002, Section 806,
Protection for Employees of Publicly Traded Companies Who Provide Evidence of
Fraud.  In December, 2008, the Department of Labor (“DOL”) dismissed
the complaint as not being timely filed.  On or about January 8, 2009, Mr.
Hyman appealed the ruling of the DOL. On January 16, 2009, the DOL filed an
Order to Show Cause whereby Mr. Hyman was ordered to show why his case should
not have been dismissed.  On February 14, 2009, Mr. Hyman filed his
response to the Order to Show Cause stating that he failed to file within the
required time because he was engaged in negotiations with the Respondents. 
On March 18, 2009, the Department of Labor dismissed Mr. Hyman’s claim for
failure to file within the 90-day filing period.   Mr. Hyman
filed a Petition for Review of the Decision and Order Dismissing Complaint
issued March 18, 2009.  A Notice of the Appeal was filed April 10, 2009
which was granted.  On March 31, 2010, in a split decision, the
Administrative Review Board Reversed the decision of the Administrative Law
Judge and Remanded the case for further consideration.  It is the Company's
contention that Mr. Hyman did not file his complaint within the time required by
Sarbanes-Oxley, and in any case, was never an employee of Platinum Energy
Resources or any of its subsidiaries; as such we are not liable for any issues
between Mr. Hyman and his employer, KD Resources.  It is the Company's
further contention that the only reason Platinum Energy is listed in this action
is because it is a public company and Mr. Hyman needs a public company in order
to obtain his status under the Sarbanes-Oxley Act.





Robert L. Kovar v. Platinum
Energy Resources





On
December 3, 2008, Robert Kovar filed suit against Platinum alleging that he
“Resigned for Good Reason” according to his employment contract.  Mr.
Kovar is seeking a Declaration Judgment that he had “Good Reason” to resign his
employment at Platinum Energy and Maverick Engineering.  Mr. Kovar is
also requesting payment of the severance package, accelerated vesting of options
and accelerated payment of the Cash Flow Note (as described in the Platinum
Energy, Maverick Engineering Merger Agreement) as described in his employment
agreement, plus attorney fees and court costs.  It is our contention
that Mr. Kovar resigned his position without good reason and is therefore, not
entitled to severance or accelerated vesting of options.  It is our
additional conviction that the Cash Flow Note has been cancelled and that
Platinum Energy in no longer obligated to make any payments there under,
pursuant to the terms of Mr. Kovar’s employment agreement. We are currently in
the discovery phase of this matter.  We believe that Mr. Kovar’s claim
that he resigned with “Good Reason” is without merit and we intend to vigorously
defend ourselves against this claim.





Platinum v. Robert L. Kovar
Services, et al





On April
16, 2009, the Company received a written notice of acceleration from Robert L.
Kovar Services, LLC, as the stockholder representative, claiming that the
Company failed to make timely mandatory prepayments in the amount of $110,381
due under the terms of the Cash Flow Notes.  On April 29, 2009,
Maverick received a notice of acceleration (the “Acceleration Letter”) with
respect to the Notes governed by a Loan Agreement and related Security Agreement
originally dated April 30, 2005 and April 29, 2005, respectively. The
Acceleration Letter alleges that Maverick failed to comply with certain
covenants under the terms of the Loan Agreement and that Maverick failed to make
payments due under the Notes. The outstanding principal, accrued interest and
late charges alleged to be owed by Maverick in the Acceleration Letter total
$4,659,227. The Acceleration Letter also contends that interest continues to
accrue at the default rate of 18% per annum. In a separate letter, dated May 1,
2009, Robert L. Kovar Services, LLC, as the stockholder representative for the
sellers, purported to terminate the revolving credit facility under the Loan
Agreement and demanded turnover of all collateral securing indebtedness under
the Loan Agreement, including the Notes. The Company and Maverick have asserted
claims in litigation against the holders of the Notes, Robert L. Kovar Services,
LLC, Robert L. Kovar, individually, and others. These litigations are in
its early stages and, accordingly, the Company cannot predict the outcome of
these matters.





On May 3.
2009, Platinum and Maverick Engineering. Inc. filed suit against Robert L.
Kovar Services. LLC (“RKS”), Robert L. Kovar (“Kovar”), Rick J. Guerra
(“Guerra”), and Walker, Keeling, & Carroll. L.L.P. (“WKC”)
collectively (the Defendants”) alleging, among other things, a
suit for declaratory judgment asking the court to declare that Platinum and
Maverick are entitled to indemnification from the former Maverick
stockholders, including Guerra and Kovar, for any damages they suffer as a
result of a default on any note contained in the Maverick and PermSUB
Merger Agreement. In addition, Platinum and Maverick have asked the Court
to declare that WKC has breached the merger agreement by not stepping down
as the Merger Escrow Agent.  Platinum and Maverick
have also sued to recover costs of court and attorneys’ fees.





In
October, 2009, Platinum and Maverick Engineering filed a Second Amended Petition
with the following Causes of Action against the Defendants:  Kovar
fraudulently induced Platinum to enter into the Merger Agreement; Common-Law
Fraud; Statutory Fraud; Breach of Fiduciary Duty; Tortious Interference with
Merger Agreement; Civil Conspiracy; and Breach of Contract.   As
this case is still in the discovery phase of litigation, at this time, it is
impossible for us to provide an informed assessment of the likelihood of a
favorable or unfavorable outcome in this case.





SNP Associates, Inc. D/B/A
Maverick Engineering v. Maverick Engineering, Inc.





On July
14, 2009, SNP Associates filed suit in the 333rd
District Court of Harris County, Texas against Maverick Engineering, Inc,
Platinum Energy Resources’ wholly owned subsidiary.  SNP is seeking a
Declaratory Judgment, Permanent Injunction, and damages for alleged “trade name
infringement.”  The suit claims that SNP has the legal right to the
name “Maverick Engineering” and that SNP has suffered damages as a result of two
engineering firms having the same name.  We do not believe that any of
SNP’s claims have merit and we intend to vigorously defend ourselves against
these claims.


21




Maverick Engineering, Inc.
v. CITGO Refining & Chemicals Company, L.P.





On
October 14, 2009, Maverick Engineering filed suit in Harris County against CITGO
Refining & Chemical Company, LP for Breach of Contract.  According
to the Petition, Maverick provided engineering services to CITGO and CITGO has
refused to pay for those services.  Maverick is suing for $357,538.16
plus damages, costs, attorney fees, interest, and other relief.  While
Maverick has performed all terms, conditions, and covenants required under its
contract with CITGO, it is too early in this litigation to be able to predict
outcome.





Lisa Meier v. Platinum
Energy Resources, Inc.





On
October 20, 2009, Lisa Meier filed suit for breach of her employment
contract.  According to the Petition, Ms. Meier resigned for “good
cause” and she is seeking severance pay.  On June 10, 2009, Ms. Meier
delivered to the Board of Directors of Platinum Energy Resources, her second
notice of intent to resign for “Good Reason.” Ms. Meier’s first notice was
submitted on October 23, 2008, less than three months after entering into her
employment agreement, and subsequently withdrawn.





The Board
of Directors accepted Ms. Meier’s resignation, but stated that “good reason” did
not exist.  This matter is currently is the early phase of
litigation.  We believe that Ms. Meier’s claims are without merit and
we intend to vigorously defend ourselves against these claims.





Item 4.   Reserved


22




PART
II





Item 5.   Market For Registrant’s Common
Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities.





Platinum
consummated its Initial Public Offering on October 28, 2005. In the Initial
Public Offering, we sold 14,400,000 units. Each unit consists of one share of
Platinum’s common stock and one redeemable common stock purchase warrant.
Platinum common stock, warrants and units are quoted on the OTCBB under the
symbols “PGRI”, “PGRIW” and “PGRIU”, respectively. Platinum’s units commenced
public trading on October 28, 2005 and its common stock and warrants commenced
separate public trading on December 9, 2005.   Both the units and
warrants expired on October 23, 2009.  The high and low bid prices of
our units, common stock and warrants as reported by the OTCBB for the
quarters in the past two fiscal years are set forth below. Such
inter-dealer quotations do not necessarily represent actual transactions and do
not reflect retail mark-ups, mark-downs or commissions:




Units
                
                
                Common Stock
                
                
                WarrantsHigh
                
                
                Low
                
                
                High
                
                
                Low
                
                
                High
                
                
                Low2009:Fourth
      Quarter
                
                $
                n/a
                1
                
                $
                n/a
                1
                
                $
                0.73
                
                
                $
                0.30
                
                
                $
                0.025
                
                
                $
                0.004Third
      Quarter
                
                $
                n/a
                1
                
                $
                n/a
                1
                
                $
                0.75
                
                
                $
                0.33
                
                
                $
                0.060
                
                
                $
                0.007Second
      Quarter
                
                $
                n/a
                1
                
                $
                n/a
                1
                
                $
                0.75
                
                
                $
                0.35
                
                
                $
                0.058
                
                
                $
                0.003First
      Quarter
                
                $
                0.51
                
                
                $
                0.51
                
                
                $
                0.78
                
                
                $
                0.42
                
                
                $
                0.050
                
                
                $
                0.0032008:Fourth
      Quarter
                
                $
                3.00
                
                
                $
                0.55
                
                
                $
                1.80
                
                
                $
                0.53
                
                
                $
                0.35
                
                
                $
                0.02Third
      Quarter
                
                $
                6.39
                
                
                $
                3.00
                
                
                $
                4.70
                
                
                $
                1.65
                
                
                $
                0.96
                
                
                $
                0.20Second
      Quarter
                
                $
                6.39
                
                
                $
                5.50
                
                
                $
                5.15
                
                
                $
                4.40
                
                
                $
                1.10
                
                
                $
                0.84First
      Quarter
                
                $
                8.36
                
                
                $
                6.00
                
                
                $
                6.97
                
                
                $
                4.60
                
                
                $
                1.85
                
                
                $
                1.00





1  These
securities no longer trade and historical pricing information is no longer
available for the period indicated.





Holders





As of May
13, 2010, there were 727 holders of record of our common
stock.   The warrants expired on October 23,
2009.  Accordingly, there are no holders of the warrants or units on
December 31, 2009.





Share
Repurchase Program





None.





Dividends





Platinum
has not paid any cash dividends on its common stock to date. It is the present
intention of the board of directors to retain all earnings, if any, for use in
the business operations, and accordingly, the board does not anticipate
declaring any dividends in the foreseeable future. The payment of any dividends
will be within the discretion of the board of directors and will be contingent
upon our financial condition, results of operations, capital requirements and
other factors our board deems relevant.





Item 7. Management’s Discussion and Analysis
of Financial Condition and Results of Operations





The
information and analyses should be read in conjunction with the financial
statements and the related notes.  These discussions and analyses may
contain forward-looking statements based upon current expectations that involve
risks and uncertainties. Our actual results may differ materially as a result of
various factors, including those set forth under “Risk Factors” or elsewhere in
this report.


23




Overview





On
October 26, 2007, we acquired substantially all of the assets and assumed
substantially all of the liabilities of TEC. Prior to that time; we were a
blank check company with no operations and no net revenues. Subsequent to the
acquisition of TEC, the Company made a series of oil and gas property
acquisitions and acquired a well servicing company to expand its exploration and
production activities.





On April
29, 2008 we acquired 100% of the stock of Maverick, a full-service engineering
services company.





With the
consummation of the Maverick acquisition, we consider ourselves to be in two
lines of business - (i) an independent oil and gas exploration and production
company and (ii) an engineering services company.




i)
              In
      our oil and gas operations, we conduct oil and natural gas exploration,
      development, acquisition, and production. Our basic business model is to
      find and develop oil and gas reserves through development activities, and
      sell the production from those reserves at a profit. We sell substantially
      all of our crude oil production under short-term contracts based on prices
      quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas
      Intermediate contracts, less agreed-upon deductions which vary by grade of
      crude oil. The majority of our natural gas production is sold under
      short-term contracts based on pricing formulas which are generally market
      responsive. From time to time, we may also sell a portion of the gas
      production under short-term contracts at fixed
  prices.
  (ii)
              Through
      our wholly-owned Maverick operation, we provide engineering and
      construction services primarily for three types of clients: (1) upstream
      oil and gas, domestic oil and gas producers and pipeline companies; (2)
      industrial, petrochemical and refining plants; and (3) infrastructure,
      private and public sectors, including state municipalities, cities, and
      port authorities. The types of services provided include project
      management, engineering, procurement, and construction management services
      to both the public and private sectors, including the oil and gas business
      in which we are engaged as described above. Maverick is based in south
      Texas with offices in Corpus Christi, Victoria, and
    Houston.




For the
first half of 2009, commodity prices continued to be weak and not conducive to
investment in our oil and gas properties. During the second half of 2009, oil
prices began to rebound, yet gas prices continued to be weak due to market
driven supply and demand issues.  Our most strategic and high profile
investment opportunities are targeting gas reserves in our Tomball area of
operations.  At the same time, the operational and financial
management of our properties was transitioned from Midland, Texas to Houston,
Texas.  Gas prices, the transition of our offices, and the lack of
available capital has hindered our ability to explore our available oil and gas
assets.





Furthermore,
like all businesses engaged in the exploration and production of oil and natural
gas, we face the challenge of natural production declines. As initial reservoir
pressures are depleted, oil and natural gas production from a given well
decreases. Thus, an oil and natural gas exploration and production company
depletes part of its asset base with each unit of oil or natural gas it
produces. Consequently, key to our success is not only finding reserves through
developmental drilling and strategic acquisitions, but also by exploiting
opportunities related to our existing production.





From time
to time, we may make strategic acquisitions in our oil and natural gas business
if we believe the acquired assets offer us the potential for reserve growth
through additional developmental drilling activities. However, the successful
acquisition of oil and natural gas properties requires assessment of many
factors, which are inherently inexact and may be inaccurate, including future
oil and natural gas prices, the amount of recoverable reserves, future operating
costs, future development costs, failure of titles to properties, costs and
timing of plugging and abandoning wells and potential environmental and other
liabilities.





Results
of Operations





Set forth
below are:





(A)
  A discussion of the results of operations for Platinum for the year ended
December 31, 2009 as compared to the year ended December 31, 2008;





(B) A
discussion of the results of operations for our oil and gas subsidiaries for the
year ended December 31, 2009 compared to the year ended December 31,
2008;





(C) A
comparison of certain summarized historical information of our engineering
services company (Maverick) for the year ended December 31, 2009 compared to the
period from the date of acquisition (April 29, 2008) through December 31,
2008.


24




The
following discussion should be read in conjunction with our Consolidated
Financial Statements and related Notes thereto included elsewhere in this
report.





(A)
- Results of Operations - Platinum





For
the year ended December 31, 2009 and the year ended December 31,
2008





We were a
blank check company from inception through October 26, 2007. For the year ended
December 31, 2007 our results of operations included those of the oil and gas
entities acquired on and subsequent to October 26, 2007.  For the year
ended December 31, 2008 our results of operations include those of our
engineering services business, Maverick, from its date of acquisition on April
29, 2008 through December 31, 2008.





For the
year ended December 31, 2009, our revenues were $35.7 million, resulting in
a net loss of $32 million or $1.45 loss per share. The results included non-cash
asset impairment charges of $16.6 million related to oil and gas properties and
equipment and a non-cash impairment of intangible assets of $4.4
million.  The Company also recognized a non-cash unrealized loss on
its commodity derivatives of $12.5 million.  Excluding the non-cash
impairment charges and unrealized loss on commodity derivatives, the Company
incurred a $1.5 million pretax loss for the year ended December 31,
2009.   For the year ended December 31, 2008, revenues were
$53.2 million, and the net loss was $80.8 million or $3.66 loss per
share. The significant decrease in revenues during 2009 was due primarily to a
precipitous drop in both oil and gas prices between 2008 and 2009.





On April
29, 2008, the Company completed the acquisition of Maverick Engineering, Inc.
Maverick is a provider of project management, engineering, procurement, and
construction management services to both the public and private sectors,
including the oil and gas business in which the Company is engaged. The
aggregate consideration paid in the merger was $6 million in cash and $5 million
to be paid over the next 5 years pursuant to non-interest bearing cash flow
notes, subject to certain escrows, holdbacks and post-closing
adjustments.   The Company’s 2008 results of operations include
Maverick from April 29, 2008 through December 31, 2008.




Our
general and administrative expenses, other than those attributable to our oil
and natural gas assets and our engineering services business for the year ended
December 31, 2009 were $2.6 million as compared to $4.2 million in
2008.  The $1.6 million decrease in corporate general and
administrative expenses for the year ended December 31, 2009 as compared to the
year ended December 31, 2008 is primarily attributable to a reduction in
salaries and wages that occurred as a reaction to lower oil and gas prices in
late 2008 and early 2009.   We also experienced a significant
decrease in legal and accounting fees during 2009, after completion of the S-1
registration for the TEC acquisition during 2008.





We also
recorded a net loss of $12.5 million for the year ended December 31,
2009 as compared to a net gain of $17.3 million in 2008, due to a
decrease in the fair value of commodity derivatives. We have experienced great
volatility in the value of these derivative instruments as a result of the great
fluctuation in the price of crude oil.  As market prices of oil and
gas increase, the value of our derivative positions will decrease.





(B)
- Results of Operations - Oil and Gas





For
the year ended December 31, 2009 and the year ended December 31,
2008





On a Boe
per day basis, average daily production remained relatively flat at 1,035 Boe
per day for the year ended December 31, 2009 compared to 1,141 Boe per day
during the same 2008 period.  Average oil and gas prices decreased
from $97.14 and $8.40, respectively during the 2008 period, to $56.49 and $3.54,
respectively during 2009.  Oil and gas revenues decreased 50% during
2009 due primarily to the dramatic decrease in commodity prices during 2009
compared to 2008.





Production
costs, consisting of lease operating expenses, production taxes and other
miscellaneous marketing costs decreased 40% in 2009 as compared to the 2008
period on a Boe basis due primarily to the substantial decrease in
commodity prices.  The decrease in commodity prices had a substantial
impact on oilfield activity, thereby, allowing us to contract vendor services at
more competitive prices.  Lower commodity prices also created lower
production taxes.  The decrease in production costs was coupled with
management’s intentional efforts to streamline field operations and cut
non-essential services.  As a result, our production costs decreased
from $33.54 per Boe in 2008, to $25.56 per Boe in 2009.





Oil and
gas depletion expense on a Boe basis decreased 41% from $26.87 in the 2008
period to $15.80 in 2009.  The decrease was due primarily to a
lower depletable cost basis in 2009 compared to the 2008
period.  Depletion expense per Boe is an operating metric that is
indicative of our weighted average cost to find or acquire a unit of equivalent
production.


25


The
Company recorded a non-cash ceiling test impairment of oil and natural gas
properties of $16.6 million during the fourth quarter of 2009, as a
result of the substantial decline in gas prices and negative revisions in the
Company's proved undeveloped reserve quantities.  The negative
revisions were principally related to the decline in value of our proved
undeveloped gas locations in Tomball as a result of declining gas
prices.  Furthermore, a number of proved undeveloped locations were
excluded from the reserve report until a more extensive study can be performed
to evaluate their potential.





General
and administrative costs related to the oil and gas entities on a Boe basis were
relatively flat from $9.31 in 2009 compared to $9.23 for the 2008
Period.





The
following information is intended to supplement the consolidated financial
statements included in this report with data that is not readily available from
those statements:





Year Ended
      December 31,2009
                                
                                
                                2008
                                
                                
                                October
      26,
                                  2007
                                  through
                                  December
                                  31,
      2007ProductionOil
      (Bls)
                                
                                
                                259,591
                                
                                
                                
                                281,441
                                
                                
                                
                                38,684Gas
      (Mcf)
                                
                                
                                709,557
                                
                                
                                
                                811,086
                                
                                
                                
                                125,849Boe
      (Bls)
                                
                                
                                377,850
                                
                                
                                
                                416,622
                                
                                
                                
                                59,659Average
      PricesOil
      ($/Bbl)
                                
                                $
                                56.49
                                
                                
                                $
                                97.14
                                
                                
                                $
                                85.24Gas
      ($/Mcf)
                                
                                $
                                3.54
                                
                                
                                $
                                8.40
                                
                                
                                $
                                8.03Average
      Lifting Cost per Boe (1)
                                
                                $
                                25.56
                                
                                
                                $
                                33.54
                                
                                
                                $
                                29.77





(1)
Includes severance and ad valorem taxes.





(C) – Results of
Operations – Engineering Services (Maverick)





For
the year ended December 31, 2009 compared to the period from the date of the
Maverick Acquisition (April 29, 2008) to December 31, 2008





Revenues
for the year ended December 31, 2009 were $18.5 million, compared to $18.3
million for the period since the acquisition (April 29, 2008 – December 31,
2008), generating gross margins of 3% and 12% for the year ended December 31,
2009 and for the period since the acquisition (April 29, 2008 – December
31, 2008), respectively.  The decrease in revenues was due to lower demand
for our services due to the weakened economy and the decrease in our gross
profit margin was due to pricing pressure on our contracts.  We have
seen a slowdown in work from some of our traditional clients due to the economic
climate in the United States.  We believe that relatively low
commodity prices will continue to impact the level of activity in this
division.





The
Company performed an analysis to determine if the fair value of the Engineering
Services reporting unit exceeded its carrying amount.  Based on a
combination of factors, including the current economic environment and the
historical performance of the segment, the Company recorded a non-cash goodwill
impairment charge of $7.8 million in 2008 and a non-cash intangible assets
acquired impairment of $5.1 million and $.2 million, during the fourth quarters
ended December 31, 2009 and 2008, respectively.   As a
result of lower than anticipated operating profit margins and the impairment of
goodwill and intangible assets, the Engineering Services division incurred a net
losses of $2.4 million and $8.9 million 2009 and 2008,
respectively.  Management has implemented significant cost reduction
initiatives and will focus on expanding its customer base internationally to
improve profitability within this segment.




26




For
the period from the date of the Maverick Acquisition (April 29, 2008) to
December 31, 2008


Revenues
for the period since the acquisition (April 29, 2008 – December 31, 2008)
were $18.3 million, generating gross margins of 12%.  Our industrial
division contributed approximately half, our oil and gas division contributed
approximately one-third and our infrastructure division contributed the
remainder of the total revenues for this segment.   Our
industrial division focused on maintenance capital projects for our traditional
refinery clients in South Texas.  In the fourth quarter, the
industrial division won a significant contract to assist a major oil company
client in repairing and restarting a Gulf Coast refinery that had been damaged
by Hurricane Ike.    This division was adversely impacted by
capital budget cuts in the refining market plus the decision by a key
customer to seek strategic alternatives for its Aruba refinery, with a
resulting deferral of some project work there. The oil and gas business focused
on gas processing, gas compression and gas storage projects in 2008 for key
customers including BP, DCP, and Shell.  Additionally, in the fourth
quarter, the oil & gas division kicked off a $4 million project involving a
new gas compression facility to be installed in Venezuela.  We have
seen a slowdown in work from some of our traditional clients in this segment and
anticipate low commodity prices will continue to impact the level of activity in
this division.  All three of our divisions were negatively affected by
Hurricane Ike as a result of lost or deferred business and the continuation of
compensation to our employees during this period.





In
accordance with Statement of Financial Accounting Standards (SFAS) No. 142,
Goodwill and Other Intangible Assets the Company performed an analysis to
determine if the fair value of the Engineering Services reporting unit exceeded
its carrying amount.  Based on a combination of factors, including the
current economic environment and the historical performance of the segment, the
Company recorded a non-cash goodwill impairment charge of $7.8 million and
a $0.2 million impairment to intangible assets acquired, during the fourth
quarter ended December 31, 2008.   As a result of lower than
anticipated operating profit margins and the impairment of goodwill and
intangible assets, the Engineering Services division incurred a $8.9 million net
loss in 2008.





Management
has implemented significant cost reduction initiatives and will focus on
expanding its customer base internationally to improve profitability within this
segment.





Liquidity
and Capital Resources





On
October 28, 2005, we consummated our initial public offering of
14,400,000 units with each unit consisting of one share of our common stock, par
value of $0.0001 per share, and one warrant to purchase one share of common
stock at an exercise price of $6.00 per share. The units were sold at an
offering price of $8.00 per unit, generating gross proceeds of $115
million.   Upon the October 26, 2007 consummation of the TEC
acquisition, the cash held in, or attributable to, the trust of approximately
$112 million became available to us and was applied as follows (i) payment
to our stockholders exercising their conversion rights; (ii) payment of TEC
debt assumed pursuant to the acquisition agreement; (iii) payment of certain
fees and expenses relating to the acquisition; and (iv) the remaining net
proceeds became available for operations and conduct of the business. This
resulted in net proceeds to us approximating $50,650,000, as
follows:




Distribution
      of cash to shareholders exercising their conversion rights
                
                $
                14,057,199Payment
      of TEC indebtedness, including interest
                
                
                41,704,635Other
      payments
                
                
                5,887,91161,649,745Available
      cash to Platinum upon consummation of the TEC acquisition
                
                
                50,650,255Total
                
                $
                112,300,000





On April
29, 2008, the Company completed the acquisition of Maverick, a provider of
project management, engineering, procurement, and construction management
services to both the public and private sectors, including the oil and gas
business in which the Company is engaged.  The aggregate consideration
paid in the merger was $6 million in cash and $5 million to be paid over the
next 5 years pursuant to non-interest bearing cash flow notes, subject to
certain escrows, holdbacks and post-closing adjustments. The cash flow notes
were reduced for a working capital post closing adjustment which was determined
by the Company to be $645,596. This amount may be subject to modification as may
be agreed between the parties. At the time the acquisition was completed, a
discount to present value in the amount of $1,320,404 was recorded and deducted
from the cash flow notes as these notes are non-interest bearing for the initial
5 years of their term. In addition, the sellers agreed to satisfy and assume
Maverick's bank indebtedness in the aggregate amount of $4,889,538 consisting of
a $2,960,155 revolving line of credit maturing April 2008, a $1,584,375 term
note due April 2011, and $345,008 oil and gas note due May 2009 (collectively
referred to as the “Notes”), using a portion of the cash received by them at
closing. Following the closing, the Company was indebted to the sellers for
these amounts under the identical terms of the bank loan agreements. On April
30, 2008, Maverick entered into extension and modification agreements with the
sellers pursuant to which sellers agreed to defer principal payments of the $1.6
million term loan for six months and extend the maturity date to April 2013. The
sellers also agreed to extend the maturity date of the revolving line of credit
to 2010. In addition, as of December 31, 2008, Maverick was not in compliance
with the debt service coverage ratio contained in the loan agreements. On August
14, 2008, the sellers waived the Company's obligation to maintain this ratio
through September 30, 2009.


27


On April
16, 2009, the Company received a written notice of acceleration from Robert L.
Kovar Services, LLC, as the stockholder representative, claiming that the
Company failed to make timely mandatory prepayments in the amount of $110,381
due under the terms of the cash flow notes.  The cash flow notes are
payable quarterly at the rate of 50% of pre-tax net income, as defined in the
merger agreement, generated by the Maverick business on a stand-alone basis in
the preceding quarter.  It is the Company’s position that Maverick
generated a pretax loss during the period April 29, 2008 through December 31,
2008 and the fourth quarter of 2008, and as such the Company was not obligated
to make a mandatory payment to the note holders.   Generally
Accepted Accounting Principles in the United States of America (“GAAP”) require
intangible assets to be amortized over their useful lives.  In
addition, goodwill and intangible assets are evaluated annually for potential
impairment.  The pretax income as calculated by Robert L. Kovar
Services, LLC, as the stockholder representative, did not include amortization
expense or impairment charges related to intangible assets and goodwill in
accordance with GAAP.





On April
29, 2009, Maverick received a notice of acceleration (the “Acceleration Letter”)
with respect to the Notes. The Acceleration Letter alleges that Maverick
failed to comply with certain covenants under the terms of the Loan Agreement
and that Maverick failed to make payments due under the Notes.  The
outstanding principal, accrued interest and late charges alleged to be owed by
Maverick in the Acceleration Letter total $4,659,227.  The
Acceleration Letter also contends that interest continues to accrue at the
default rate of 18% per annum.  In a separate letter, dated May 1,
2009, Robert L. Kovar Services, LLC, as the stockholder representative for the
sellers, purported to terminate the revolving credit facility under the Loan
Agreement and demanded turnover of all collateral securing indebtedness under
the Loan Agreement.





The
Company and Maverick have asserted claims in litigation against the holders of
the Notes, Robert L. Kovar Services, LLC, Robert L. Kovar, individually, and
others.  The litigation is in its early stages and, accordingly, the
Company cannot predict the outcome of these matters.





On March
14, 2008, TEC and PER Gulf Coast, Inc. (“Borrower”) which are wholly owned
subsidiaries of the Company, entered into a Senior Secured Revolving Credit
Facility (“Senior Credit Facility”) with Bank of Texas. The Senior Credit
Facility provided for a revolving credit facility up to the lesser of the
borrowing base and $100 million. The initial borrowing base was set at $35
million.  On January 9, 2009, the Borrower reaffirmed the
borrowing base at $35 million and amended the Senior Credit Facility to change
the interest rate provisions. Under the amended loan agreement the outstanding
debt bears interest at LIBOR, plus a margin which varies with the ratio of the
Borrower’s outstanding borrowings against the defined borrowing base, ranging
from 2.0% to 2.75 % provided the interest rate does not fall below a floor rate
of 4.5% per annum.  In addition, the Borrower is obligated to the bank
for a monthly fee of any unused portion of the line of credit at the rate of
0.50% per annum. The facility is collateralized by substantially all of the
Company’s proved oil & gas assets.





Under the
terms of the revolving line of credit agreement, the Borrower must maintain
certain financial ratios, must repay any amounts due in excess of the borrowing
base, and may not declare any dividends or enter into any transactions resulting
in a change in control, without the bank’s consent. The outstanding obligation
under the credit facility, approximately $13 million as of December 31, 2009,
matured on June 1, 2010.  Additionally, the Company has asked for
waivers of two other covenants associated with the facility.  First, a
significant stockholder has acquired legal control of the Company in that it now
owns over 50% of the Company’s outstanding common stock.  This event
results in a change of control as defined in the Senior Credit Facility
which requires the Company to obtain a waiver from the bank.  Second,
the Company did not furnish audited financial statements to the bank by March
31, 2010 as also required by the Senior Credit Facility.  The Company,
as the parent company, is not a co-borrower or guarantor of the line, and
transfers from the Borrower to the parent company are limited to (i) $1 million
per fiscal year to the parent for management fees, and (ii) the repayment of up
to $2 million per fiscal year in subordinate indebtedness owed to the parent.
Amounts drawn on the revolving line of credit in 2009 were used to fund our
capital expenditure program.





On June
12, 2009, the Borrowers received a“Notice of Borrowing Base
Redetermination and Notice of Event of Default” from the
bank.  The bank set the new borrowing base at $15 million, shortened
the maturity date of the loan from March 14, 2012 to June 1, 2010, raised the
floor interest rate from 4% to 4.5%, redefined certain covenant ratios, and
required certain fees paid to grant the waivers necessary to cure the
aforementioned covenant defects.  The Company executed the Second
Amendment to the Senior Credit Facility on June 25, 2009.  The
Company, as the parent company, is not a co-borrower or guarantor of the line,
and transfers from the Borrower to the parent company are limited to (i) $1
million per fiscal year to the parent for management fees, and (ii) the
repayment of up to $2 million per fiscal year in subordinate indebtedness owed
to the parent. As of December 31, 2009 the $13.0 million outstanding under the
revolving line of credit was bearing interest at the bank’s base rate,
which, at the time, was 4.5%.  As amended, the Senior Credit Facility
expires on June 1, 2010.  Accordingly, the Company has classified the
full $13 million as a current liability.  The borrowers are in
discussion with the Bank of Texas to renew the Senior Credit
Facility.  In addition, we are in discussion with other sources of
capital to utilize in refinancing the Senior Credit
Facility.  Currently, we have cash on hand of approximately $1.9
million and hedges and options with a fair market value of $5.9 million for a
total of $7.8 million of liquid assets.  With Bank of Texas, we are
discussing an extension of the loan.  In May, 2010 the Company paid
$3.5 million of its available cash toward the bank debt to bring the outstanding
balance to approximately $9.5 million.





The
Company had approximately $3,000,000 in cash on hand at December 31, 2009, which
is sufficient to fund our near term drilling program and fund
operations.


28




The
accompanying consolidated financial statements have been prepared assuming the
Company will continue as a going concern.  The Company has incurred
significant losses, resulting in cumulative losses of $111,276,255 through
December 31, 2009. Additionally, the Company’s outstanding loan with the Bank of
Texas matured on June 1, 2010 and remains unpaid as of June 24, 2010; however,
as of June 24, 2010, the Company has not received a notice of foreclosure from
the Bank of Texas.  The Company’s current cash on hand is not adequate
to satisfy the Bank of Texas debt. These conditions raise substantial doubt
about the Company’s ability to continue as a going concern.





Management’s
plan to resolve the uncertainty about our ability to continue as a going concern
includes cost reductions and seeking additional debt financing or the
refinancing of our existing Bank of Texas loan.  There is no assurance that
we will be able to obtain such additional funds through equity or debt
financing, or any combination thereof, or on satisfactory terms or at all.
Additionally, no assurance can be given that any such financing or refinancing,
if achievable, will be adequate to meet our ultimate capital needs and to
support our growth. If the Company is not able to obtain additional financing on
a timely basis and on satisfactory terms, our operations would be materially
negatively impacted.





As a
result of the above discussed conditions, there exists substantial doubt about
our ability to continue as a going concern. Our consolidated financial
statements are presented on a going concern basis, which contemplates the
realization of assets and satisfaction of liabilities in the normal course of
business. The consolidated financial statements do not include any adjustments
relating to the recoverability of the recorded assets or the classification of
liabilities that may be necessary should it be determined that we are unable to
continue as a going concern.





Capital
Expenditures





The
timing of most of our capital expenditures is discretionary because we operate
the majority of our wells and we have no material long-term capital expenditure
commitments. Consequently, we have a significant degree of flexibility to adjust
the level of our capital expenditures as circumstances warrant. Our capital
expenditure program includes the following:




•
              cost
      of acquiring and maintaining our lease acreage position and our seismic
      resources;
 
 •
              cost
      of drilling and completing new oil and natural gas
  wells;
 
 •
              cost
      of installing new production
infrastructure;
 
 •
              cost
      of maintaining, repairing and enhancing existing oil and natural gas
      wells; and
 
 •
              cost
      of recompleting previously abandoned well
bores.





During
2009 we made approximately $916,000 in capital expenditures related to our oil
and gas properties.  We drilled one well in our Ball lease in July
2009, costing approximately $215,000.  The well was successful and is
currently producing 250 Mcf of gas per day.   We upgraded
production equipment throughout our fields for approximately
$701,000.





The
industry saw unprecedented increases in commodity prices during 2008 when we
began an aggressive drilling program.  The focus was to drill low
cost, long lived proved undeveloped locations within our existing
fields.  Unfortunately, as commodity prices escalated, the cost to
drill followed closely behind. Although we were able to utilize our own drilling
rigs in most cases, the rig itself comprises only a portion of the cost to drill
and complete a well.  Labor costs increased, the availability of
casing and tubing became scarce and expensive, and the availability of other
services in a demand driven environment became cost prohibitive. By the end of
the second quarter, 2008, the cost to drill had affected the economic parameters
so much, that we began to curtail drilling operations during the third
quarter.





During
2009, oil prices have strengthened while gas prices have continued to remain
soft.  Management is currently evaluating potential development
opportunities related to oil projects.  Further capital expenditures
in 2010 will be dependent on product prices and subject to the availability of
capital.





Off-Balance
Sheet Arrangements





We do not
have any off-balance sheet arrangements as defined in Item 303(a)(4)(ii) of
Regulation S-K promulgated under the Securities Exchange Act of
1934.


29




Critical
Accounting Policies and Estimates





Use of Estimates. The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates.





The
selection and application of accounting policies is an important process that
has developed as our business activities have evolved and as the accounting
rules have developed.  Accounting rules generally do not involve a
selection among alternatives, but involve an implementation and interpretation
of existing rules, and the use of judgment applied to the specific set of
circumstances existing in our business.  We make every effort to
properly comply with all applicable rules on or before their adoption, and we
believe the proper implementation and consistent application of the accounting
rules are critical.  For further details on our accounting policies,
please read Note 2 to our consolidated financial statement included in Item 8 in
this report.


30




Revenue Recognition:With
respect to oil and gas operations, sales of natural gas, natural gas liquids and
oil are recognized when natural gas, natural gas liquids and oil have been
delivered to a custody transfer point, persuasive evidence of a sales
arrangement exists, the rights and responsibility of ownership pass to the
purchaser upon delivery, collection of revenue from the sale is reasonably
assured, and the sales price is fixed or determinable. We sell natural gas,
natural gas liquids and oil on a monthly basis. Virtually all of our contracts’
pricing provisions are tied to a market index, with certain adjustments based
on, among other factors, whether a well delivers to a gathering or transmission
line, quality of the natural gas, natural gas liquid or oil, and prevailing
supply and demand conditions, so that the price of the natural gas, natural gas
liquid and oil fluctuates to remain competitive with other available natural
gas, natural gas liquid and oil supplies.





The
Company has elected the entitlements method to account for gas production
imbalances. Gas imbalances occur when we sell more or less than our entitled
ownership percentage of total gas production. Any amount received in excess of
our share is treated as a liability. If we receive less than our entitled share
the underproduction is recorded as a receivable. The amounts of imbalances
were not material at December 31, 2009 and 2008.





With
respect to engineering services, revenues and profits on long-term contracts are
recorded under the percentage-of-completion method.  Progress towards
completion on fixed price contracts is measured based on physical completion of
individual tasks for all contracts with a value of $5,000 or greater. For
contracts with a value less than $5,000, progress toward completion is measured
based on the ratio of costs incurred to total estimated contract costs (the
cost-to-cost method).





Progress
towards completion on cost-reimbursable contracts is measured based on the ratio
of quantities expended to total forecasted quantities, typically man-hours.
Incentives are also recognized on a percentage-of-completion basis when the
realization of an incentive is assessed as probable. We include flow-through
costs consisting of materials, equipment or subcontractor services as both
operating revenues and cost of operating revenues on cost-reimbursable contracts
when we have overall responsibility as the contractor for the engineering
specifications and procurement or procurement services for such costs. There is
no contract profit impact of flow-through costs as they are included in both
operating revenues and cost of operating revenues.





Contracts
in process are stated at cost, increased for profits recorded on the completed
effort or decreased for estimated losses, less billings to the customer and
progress payments on uncompleted contracts.  At any point, we have numerous
contracts in progress, all of which are at various stages of completion.
Accounting for revenues and profits on long-term contracts requires estimates of
total estimated contract costs and estimates of progress toward completion to
determine the extent of revenue and profit recognition. We rely extensively on
estimates to forecast quantities of labor (man-hours), materials and equipment,
the costs for those quantities (including exchange rates), and the schedule to
execute the scope of work including allowances for weather, labor and civil
unrest. In determining the revenues, we must estimate the
percentage-of-completion, the likelihood that the client will pay for the work
performed, and the cash to be received net of any taxes ultimately due or
withheld where the work is performed. Projects are reviewed on an individual
basis and the estimates used are tailored to the specific circumstances. In
establishing these estimates, we exercise significant judgment, and all possible
risks cannot be specifically quantified





The
percentage-of-completion method requires that adjustments or re-evaluations to
estimated project revenues and costs, including estimated claim recoveries, be
recognized on a project-to-date cumulative basis, as changes to the estimates
are identified. Revisions to project estimates are made as additional
information becomes known, including information that becomes available
subsequent to the date of the consolidated financial statements up through the
date such consolidated financial statements are filed with the SEC. If the final
estimated profit to complete a long-term contract indicates a loss, provision is
made immediately for the total loss anticipated. Profits are accrued throughout
the life of the project based on the percentage-of-completion. The project life
cycle, including project-specific warranty commitments, can be up to
approximately six years in duration.


The
actual project results can be significantly different from the estimated
results. When adjustments are identified near or at the end of a project, the
full impact of the change in estimate is recognized as a change in the profit on
the contract in that period. This can result in a material impact on our results
for a single reporting period. We review all of our material contracts on a
monthly basis and revise our estimates as appropriate for developments such as
earning project incentive bonuses, incurring or expecting to incur contractual
liquidated damages for performance or schedule issues, providing services and
purchasing third-party materials and equipment at costs differing from those
previously estimated and testing completed facilities, which, in turn,
eliminates or confirms completion and warranty-related costs. Project incentives
are recognized when it is probable they will be earned. Project incentives are
frequently tied to cost, schedule and/or safety targets and, therefore, tend to
be earned late in a project’s life cycle.


31




Full
Cost and Impairment of Assets





We
account for our oil and natural gas exploration and development activities using
the full cost method of accounting. Under this method, all costs incurred in the
acquisition, exploration and development of oil and natural gas properties are
capitalized. Costs of non-producing properties, wells in the process of being
drilled and significant development projects are excluded from depletion until
such time as the related project is developed and proved reserves are
established or impairment is determined. At the end of each quarter, the net
capitalized costs of our oil and natural gas properties, as adjusted for asset
retirement obligations, is limited to the lower of unamortized cost or a
ceiling, based on the present value of estimated future net revenues, net of
income tax effects, discounted at 10%, plus the lower of cost or fair market
value of our unproved properties. Revenues are measured at prices beginning of
each month for the preceding 12 months with effect given to cash flow hedge
positions, if any. If the net capitalized costs of oil and natural gas
properties exceed the ceiling, we are subject to a ceiling test write-down to
the extent of the excess. A ceiling test write-down is a non-cash charge to
earnings. It reduces earnings and impacts stockholders’ equity in the period of
occurrence and results in lower DD&A expense in future
periods.  There is a risk that we will be required to write down the
carrying value of our oil and natural gas properties if oil and natural gas
prices decline further.





Depletion





Provision
for depletion of oil and natural gas properties under the full cost method is
calculated using the unit of production method based upon estimates of proved
oil and natural gas reserves with oil and natural gas production being converted
to a common unit of measure based upon their relative energy content. Costs to
be amortized include the net carrying value of our oil and gas properties, the
associated asset retirement costs, less estimated salvage value, plus the
estimated future development costs associated with our proved undeveloped
reserves. Investments in unproved properties and major development projects are
not amortized until proved reserves associated with the projects can be
determined or until impairment occurs. The cost of any impaired property is
transferred to the balance of oil and natural gas properties being
depleted.





Significant
Estimates and Assumptions





Oil
and Gas Reserves





(1)
Reserve engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact manner. The
accuracy of a reserve estimate depends on the quality of available geological
and engineering data, the precision of the interpretation of that data, and
judgment based on experience and training. We have historically engaged an
independent petroleum engineering firm to evaluate our oil and gas reserves. As
a part of this process, our internal reservoir engineer and the independent
engineers exchange information and attempt to reconcile any material differences
in estimates and assumptions.





(2)
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the proved
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.





(3)
Estimates of proved reserves do not include the following: (A) oil that may
become available from known reservoirs but is classified separately as indicated
additional reserves; (B) crude oil, natural gas, and natural gas liquids, the
recovery of which is subject to reasonable doubt because of uncertainty as to
geology, reservoir characteristics, or economic factors; (C) crude oil, natural
gas, and natural gas liquids, that may occur in undrilled prospects; and (D)
crude oil, natural gas, and natural gas liquids, that may be recovered from oil
shales, coal and other such sources.





Valuation
of proved undeveloped properties





Placing a
fair market value on proved undeveloped properties, commonly referred to as
“PUDs” is very subjective since there is no quoted market for them. The
negotiated price of any PUD between a willing seller and willing buyer depends
on the specific facts regarding the PUD, including:




·
              The
      location of the PUD in relation to known fields and reservoirs, available
      markets and transportation systems for oil and gas production in the
      vicinity, and other critical
services;
  32
  ·
              The
      nature and extent of geological and geophysical data on the
      PUD;
 
 ·
              The
      terms of the leases holding the acreage in the area, such as ownership
      interests, expiration terms, delay rental obligations, depth limitations,
      drilling and marketing restrictions, and similar
  terms;
 
 ·
              The
      PUDs risk-adjusted potential for return on investment, giving effect to
      such factors as potential reserves to be discovered, drilling and
      completion costs, prevailing commodity prices, and other economic factors;
      and
 
 ·
              The
      results of drilling activity in close proximity to the PUD that could
      either enhance or condemn the prospect’s chances of
    success.
 
 Provision
for Depreciation, Depletion and Amortization
 
 We have
computed our provision for Depreciation, Depletion and Amortization
(“DD&A”) on a unit-of-production method. Each quarter, we use the
following formulas to compute the provision for DD&A.
 
 ·
              DD&A
      Rate = Current period production, divided by beginning proved
      reserves.
 
 ·
              Provision
      for DD&A = DD&A Rate, times the un-depleted full cost pool of oil
      and gas properties plus the estimated future development costs associated
      with our PUDs.




Reserve
estimates have a significant impact on the DD&A rate. If reserve estimates
for our properties are revised downward in future periods, the DD&A rate
will increase as a result of the revision. Alternatively, if reserve estimates
are revised upward, the DD&A rate will decrease.





Hedging
Activities





From time
to time, we utilize derivative instruments, consisting of swaps, floors and
collars, to attempt to reduce our exposure to changes in commodity prices and
interest rates. We account for our derivatives in accordance with ASC 815 –
Derivatives and Hedging (ASC 815). ASC 815 requires that all derivative
instruments be recognized as assets or liabilities in the balance sheet,
measured at fair value. The accounting for changes in the fair value of a
derivative depends on both the intended purpose and the formal designation of
the derivative. Designation is established at the inception of a derivative, but
subsequent changes to the designation are permitted. We have elected not to
designate any of our derivative financial contracts as accounting hedges and,
accordingly, account for these derivative financial contracts using
mark-to-market accounting. Changes in fair value of derivative instruments which
are not designated as cash flow hedges are recorded in other income (expense) as
changes in fair value of derivatives. Hedging is a strategy that can help a
company to mitigate the volatility of oil and gas prices by limiting its losses
if oil and gas prices decline; however, this strategy may also limit the
potential gains that a company could realize if oil and gas prices
increase.





Asset
Retirement Obligation





We
account for asset retirement obligations by recognizing a liability for the
present value of all legal obligations associated with the retirement of
tangible, long-lived assets and capitalizing an equal amount as a cost of the
asset. The cost of the abandonment obligations, less estimated salvage values,
is included in the computation of depreciation, depletion and
amortization.





Intangibles





We follow
the provisions of ASC 350-35 (ASC 350-35) on intangibles (formerly FASB Staff
Position (FSP) No. FAS 142-3, “Determination of the Useful Life of
Intangible Assets”).  ASC 350-35 requires us to identify the
factors that should be considered in developing renewal or extension assumptions
used to determine the useful life of a recognized intangible asset on goodwill
and other intangibles in order to improve the consistency between the useful
life of a recognized intangible asset and the period of expected cash flows used
to measure the fair value of the asset.  This change is intended to
improve consistency between the useful life of a recognized intangible asset of
ASC 350 and the period of expected cash flows used to measure the fair value of
such asset of ASC 350 and other accounting guidance.  The requirement
for determining useful lives must be applied prospectively to all intangible
asset recognized as of, and subsequent to, January 1, 2009.





Inventory




Materials,
supplies and commodity inventories are valued at the lower of cost or market.
The cost is determined using the first-in, first-out method.


33




Recent
Accounting Pronouncements





In July
2009, the FASB issued new accounting guidance under the Accounting Standards
Codification (ASC) Topic 105 (ASC 105), (formerly, Statement of Financial
Accounting Standards (SFAS) No. 168, “The FASB Accounting Codification and
the Hierarchy of Generally Accepted Accounting Principles”). Under this
guidance, the ASC became the single source of authoritative U.S. generally
accepted accounting principles (GAAP) recognized by the FASB to be applied by
nongovernmental entities. Rules and interpretive releases of the Securities and
Exchange Commission (SEC) under authority of federal securities laws are also
sources of authoritative GAAP for SEC registrants. On the effective date of this
Statement, the ASC superseded all then-existing non-SEC accounting and reporting
standards. All other non-grandfathered non-SEC accounting literature not
included in the ASC will become non-authoritative.   This Statement is
effective for interim and annual periods ending after September 15, 2009. Other
than the manner in which new accounting guidance is referenced, the adoption of
this guidance did not materially impact the Company’s consolidated financial
statements.





On
January 1, 2009, the Company adopted new accounting guidance under ASC
Topic 805 (ASC 805) on business combinations, (formerly SFAS No. 141 (R),
“Business Combinations”
which replaced SFAS No. 141“Business
Combinations”).  ASC 805 retains the fundamental requirements
in SFAS 141, including that the purchase method be used for all business
combinations and for an acquirer to be identified for each business combination.
This standard defines the acquirer as the entity that obtains control of one or
more businesses in the business combination and establishes the acquisition date
as the date that the acquirer achieves control instead of the date that the
consideration is transferred. ASC 805 requires an acquirer in a business
combination, including business combinations achieved in stages (step
acquisition), to recognize the assets acquired, liabilities assumed, and any
non-controlling interest in the acquiree at the acquisition date, measured at
their fair values as of that date, with limited exceptions. It also requires the
recognition of assets acquired and liabilities assumed arising from certain
contractual contingencies as of the acquisition date, measured at their
acquisition-date fair values. Additionally, ASC 805 requires acquisition-related
costs to be expensed in the period in which the costs are incurred and the
services are received instead of including such costs as part of the acquisition
price. The adoption of ASC 805 did not have a material impact on the Company’s
condensed consolidated financial statements. The provisions of ASC 805 will be
applied at such time when measurement of a business acquisition is
required.





On
January 1, 2009, the Company adopted new accounting guidance under ASC
Topic 820 (ASC 820) on fair value measurements (formerly SFAS No. 157,
“Fair Value
Measurements ”),  as it relates to nonfinancial assets and
nonfinancial liabilities that are not recognized or disclosed at fair value in
the consolidated financial statements on at least an annual basis. ASC 820
defines fair value, establishes a framework for measuring fair value in
accounting principles generally accepted in the United States of America (GAAP),
and expands disclosures about fair value measurements. The provisions of ASC 820
apply to other topics that require or permit fair value measurements and are to
be applied prospectively with limited exceptions. The adoption of ASC 820, as it
relates to nonfinancial assets and nonfinancial liabilities had no impact on the
Company’s consolidated financial statements.





On
January 1, 2009, the Company adopted new accounting guidance under ASC
Topic 810 (ASC 810) on consolidation (formerly SFAS No. 160, “Noncontrolling Interests in
Consolidated Financial Statements—an amendment of ARB
No. 51”).   ASC 810 establishes accounting and
reporting standards for the noncontrolling interest in a subsidiary and for the
deconsolidation of a subsidiary. This topic defines a noncontrolling interest,
previously called a minority interest, as the portion of equity in a subsidiary
not attributable, directly or indirectly, to a parent. ASC 810 requires, among
other items, that a noncontrolling interest be included in the consolidated
statement of financial position within equity separate from the parent’s equity;
consolidated net income to be reported at amounts inclusive of both the parent’s
and noncontrolling interest’s shares and, separately, the amounts of
consolidated net income attributable to the parent and noncontrolling interest
all on the consolidated statement of operations; and if a subsidiary is
deconsolidated, any retained noncontrolling equity investment in the former
subsidiary be measured at fair value and a gain or loss be recognized in net
income based on such fair value. The presentation and disclosure requirements of
ASC 810 were applied retrospectively. The adoption of ASC 810 had no impact on
the Company’s consolidated financial statements.





On
January 1, 2009, the Company adopted new accounting guidance under ASC
Topic 815 (ASC 815) on derivatives and hedging (formerly SFAS No. 161,
“Disclosures about Derivative
Instruments and Hedging Activities—an amendment of FASB Statement
No. 133 ”). ASC 815 requires enhanced disclosures about an entity’s
derivative and hedging activities, including (i) how and why an entity uses
derivative instruments, (ii) how derivative instruments and related hedged
items are accounted for under ASC 815, and (iii) how derivative instruments
and related hedged items affect an entity’s financial position, financial
performance, and cash flows. The adoption of ASC 815 had no impact on the
Company’s consolidated financial statements.





On
January 1, 2009, the Company adopted new accounting guidance under ASC
Topic 350-35 (ASC 350-35) on intangibles (formerly FASB Staff Position (FSP) No.
FAS 142-3, “Determination of
the Useful Life of Intangible Assets ”).  ASC
350-35  identifies the factors that should be considered in developing
renewal or extension assumptions used to determine the useful life of a
recognized intangible asset on goodwill and other intangibles in order to
improve the consistency between the useful life of a recognized intangible asset
and the period of expected cash flows used to measure the fair value of the
asset. The adoption of ASC 350-35 had no impact on the Company’s consolidated
financial statements.


34




On
January 1, 2009, the Company adopted new accounting guidance under ASC
Topic 260 (ASC 260) on earnings per share which established that unvested
share-based payment awards that contain nonforfeitable rights to dividends or
dividend equivalents (whether paid or unpaid) are participating securities and
shall be included in the computation of earnings per share pursuant to the
two-class method. The adoption of this guidance did not have a material impact
on the Company’s condensed consolidated financial statements.





On
January 1, 2009 the Company adopted new accounting guidance under ASC Topic
815 (ASC 815) on derivatives and hedging which provides that an entity should
use a two steps approach to evaluate whether an equity-linked financial
instrument, or embedded feature, is indexed to its own stock, including
evaluating the instrument’s contingent exercise and settlement provisions. It
also clarifies on the impact of foreign currency denominated strike prices and
market-based employee stock option valuations. The adoption of this guidance did
not have a material impact on the Company’s condensed consolidated financial
statements.





In May,
2009 the Company adopted new accounting guidance under ASC Topic 855 (ASC 855)
on subsequent events, (formerly, SFAS No. 165, “Subsequent Events”) . ASC
855 establishes general standards of accounting for and disclosure of events
that occur after the balance sheet date but before financial statements are
issued or are available to be issued. ASC 855 was effective for interim or
annual periods ending after June 15, 2009. Management has evaluated
subsequent events to determine if events or transactions occurring through
November 11, 2009 (the date at which the financial statements were available to
be issued), and has determined that no such events have occurred that would
require adjustment to or disclosure in the financial statements.





In
June 2009 the FASB issued SFAS No. 167, “Amendments to FASB Interpretation
No. 46(R)” (“SFAS 167 ”). SFAS 167 eliminates Interpretation 46(R)’s
exceptions to consolidating qualifying special-purpose entities, contains new
criteria for determining the primary beneficiary, and increases the frequency of
required reassessments to determine whether a company is the primary beneficiary
of a variable interest entity. SFAS 167 also contains a new requirement that any
term, transaction, or arrangement that does not have a substantive effect on an
entity’s status as a variable interest entity, a company’s power over a variable
interest entity, or a company’s obligation to absorb losses or its right to
receive benefits of an entity must be disregarded in applying Interpretation
46(R)’s provisions. The elimination of the qualifying special-purpose entity
concept and its consolidation exceptions means more entities will be subject to
consolidation assessments and reassessments. SFAS 167 will be effective January
1, 2010. The adoption of this pronouncement is not expected to have a
material impact on the Company’s consolidated financial position and results of
operations.





In August
2009, FASB issued Accounting Standards Update 2009-05 which includes amendments
to Subtopic 820-10, Fair Value Measurements and Disclosures—Overall. The update
provides clarification that in circumstances in which a quoted price in an
active market for the identical liability is not available, a reporting entity
is required to measure fair value using one or more of the techniques provided
for in this update. The amendments in this Update clarify that a reporting
entity is not required to include a separate input or adjustment to other inputs
relating to the existence of a restriction that prevents the transfer of the
liability and  also clarifies  that both a quoted price in
an active market for the identical liability at the measurement date and the
quoted price for the identical liability when traded as an asset in an active
market when no adjustments to the quoted price of the asset are required are
Level 1 fair value measurements. The adoption of this standard is not
expected to have a material impact on the Company’s consolidated financial
position and results of operations.





Other
accounting standards that have been issued or proposed by the FASB or other
standards-setting bodies that do not require adoption until a future date are
not expected to have a material impact on our consolidated financial statements
upon adoption.





SEC
Rulemaking





On
December 31, 2008, the SEC published the final rules and interpretations
updating its oil and gas reporting requirements. Many of the revisions are
updates to definitions in the existing oil and gas rules to make them consistent
with the petroleum resource management system, which is a widely accepted
standard for the management of petroleum resources that was developed by several
industry organizations. Key revisions include the ability to include
nontraditional resources in reserves, the use of new technology for determining
reserves, permitting disclosure of probable and possible reserves, and changes
to the pricing used to determine reserves in that companies must use a 12-month
average price. The average is calculated using the first-day-of-the-month price
for each of the 12 months that make up the reporting period. The SEC has
required companies to comply with the amended disclosure requirements for
registration statements filed after January 1, 2010, and for annual reports
for fiscal years ending on or after December 15, 2009. Early adoption is
not permitted. These rules and disclosures are incorporated in our results of
operation, financial statements and disclosures for the year ended December 31,
2009.


35




Item 8.   Financial Statements and
Supplementary Data.




Our
Consolidated Financial Statements and supplementary financial data are included
in this annual report on Form 10-K beginning on page F-1 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.





Disclosure
Controls and Procedures





The
Company’s management has evaluated, with the participation of the Company’s
Chief Executive Officer, the effectiveness of the Company’s disclosure controls
and procedures, as of the end of the period covered by this report, pursuant to
Exchange Act Rule 13a-15. Based upon that evaluation, the Company’s Chief
Executive Officer concluded that the Company’s disclosure controls and
procedures were not effective as a result of material weaknesses in internal
controls as of December 31, 2009.





(a)Management’s Annual Report on
Internal Control Over Financial Reporting





Our
management is responsible for establishing and maintaining internal control over
financial reporting (ICFR). Our internal control system was designed to provide
reasonable assurance to the Company’s management and Board of Directors
regarding the preparation and fair presentation of published financial
statements. All internal control systems, no matter how well designed, have
inherent limitations, and therefore can only provide reasonable assurance with
respect to financial statement preparation and presentation.





An
internal control material weakness is a significant deficiency, or combination
of significant deficiencies, that results in more than a remote likelihood that
a material misstatement of the financial statements would not be prevented or
detected on a timely basis by employees in the normal course of their work. Our
management’s assessment is that the Company did not maintain effective ICFR as
of December 31, 2009 within the context of the framework established by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based
on our ICFR as designed, documented and tested, we identified multiple material
weaknesses primarily related to maintaining an adequate control environment. The
material weaknesses in our internal controls related to inadequate staffing
within our accounting department and upper management,  lack of
consistent policies and procedures, inadequate monitoring of controls,
inadequate disclosure controls and significant turnover among the staff and
officers of the Company.





It is
Management’s plan to remediate the internal control material weakness by
implementing new controls and procedures that combined will improve the quality
of the financial reporting process.





This
annual report does not include an attestation report of the company's registered
public accounting firm regarding internal control over financial reporting.
Management's report was not subject to attestation by the company's registered
public accounting firm pursuant to temporary rules of the Securities and
Exchange Commission that permit the company to provide only management's report
in this annual report.





(b)Changes in Internal Control Over
Financial Reporting





We have
evaluated our internal control over financial reporting as of the end of our
fourth fiscal quarter. There were no changes in our internal control over
financial reporting, identified in connection with the evaluation of such
internal control, that occurred during the fourth quarter of our last fiscal
year that have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.





This
management report on internal control over financial reporting shall not be
deemed to be filed for purposes of Section 18 of the Securities Exchange Act of
1934, as amended or otherwise subject to the liabilities of that
Section.


36




PART
III





Item
10.  Directors, Executive Officers and Corporate Governance.





The
current Board of Directors and Executive Officers of Platinum are as
follows:




Name
              
              Age (1)
              
              Position
              
              Director
                Since
              
              Director
                ClassTim
      G. Culp
              
              51
              
              Chairman
      of the Board
              
              2007
              
              Class
      CAl
      Rahmani
              
              63
              
              Interim
      Chief Executive Officer and Director
              
              2009
              
              Class
      AWilliam
      C. Glass
              
              39
              
              President
      and Director
              
              2005
              
              Class
      BBernard
      Albert Lang
              
              73
              
              Director
              
              2008
              
              Class
      AMarc
      Berzins
              
              70
              
              Director
              
              2009
              
              Class
      A










Tim G.
Culp has been our Chairman of the Board and President and Chief Executive
Officer of New TEC since the TEC acquisition in October 2007.  From
June 2005 through October 2007, Mr. Culp was President and Chief Executive
Officer of Tandem, Old TEC’s parent entity.  Prior to this, Mr. Culp
was a co-founder, senior officer and principal stockholder of Old TEC's and
Shamrock Energy Corporation and its operating affiliate, Arrowhead Operating,
Inc. Prior to forming TEC, Mr. Culp was a Vice President with Adobe Resources
Corporation. During Mr. Culp’s tenure, Adobe, TEC and Shamrock acquired over
$140 million in oil and gas properties. Mr. Culp has over twenty-five years of
oil and gas industry experience with over twenty years of experience in property
acquisitions and development. Prior to joining Adobe, Mr. Culp was a manager for
the public accounting firm of KPMG Peat Marwick. Mr. Culp received his Bachelor
of Business Administration degree in Accounting from Texas Tech University in
1981.





Al Rahmani
has been a member of our board of directors since his appointment on February
18, 2009 and has been the Chief Executive Officer of Platinum Energy Resources,
Inc. since March 2, 2009. Prior to joining the company, Mr. Rahmani held the
position of Senior Vice President of Engineering and Development for Triple Five
Worldwide Organization, LLC since 2006.  In that capacity, Mr. Rahmani
was in charge of all Triple Five domestic and international mix-use,
multi-discipline projects throughout the world.  From 1995 to December
2008, Mr. Rahmani served as Managing Director of A.R. Development, Inc., a
technical engineering and financial services firm. In this capacity Mr. Rahmani
was responsible for a variety of development projects.  From 1981 to
1995 Mr. Rahmani was one of the Principals of G.C.G. Consulting, a
multi-disciplinary engineering firm.  In this capacity he was the head
of the Infrastructure Engineering department as well as being responsible for
international projects providing engineering services to a variety of clients
both in the public and private sector.  During this period Mr. Rahmani
successfully completed engineering projects in Ecuador, Peru and
Bolivia.  From 1976 to 1981 Mr. Rahmani was managing director of Iran
M.C.A., a consulting engineering firm, which was a division of WALTERKIDDE
conglomerate, a publically traded company.  In this capacity Mr.
Rahmani was responsible for numerous projects in Iran and throughout the Middle
East.  The firm was engaged in a series of Fire Protection projects
for the airline industry, hotels, and resort developments, highways, bridges,
port design and infrastructure engineering.  Mr. Rahmani received a
B.S. in civil engineering and a M.S. in civil/environmental engineering from the
University of Massachusetts.





William C.
Glass has been President of the Company and a member of our board of
directors since inception. Mr. Glass has worked in the energy industry and
energy financial derivatives markets since 1996. Mr. Glass has been an
independent energy trader and consultant since December 2003. From July 2000 to
December 2003, Mr. Glass was Vice president of Marubeni Energy Incorporated’s
North American Natural gas division. He was responsible for all natural gas
transactions, transportation, marketing, trading, and operations. From February
1997 to July 2000, Mr. Glass was a senior trader at Southern Company Energy
marketing. His responsibilities included managing the financial gas daily desk
as well as trading gulf coast, northeast, and mid west financial products. From
October 1995 to February 1997, Mr. Glass worked at Enron as part of the risk
management team. Mr. Glass holds a bachelor’s in Finance and Accounting from
Texas A&M University.





Bernard Albert
Lang has been a member of our board of directors since his appointment on
July 15, 2008. Mr. Lang is currently President of Bert Lang and Associates, a
megaproject and energy consulting firm. Mr. Lang was Executive Vice
President, Project Execution for Synenco Energy Inc., until it was acquired
by Total in August 2008. Mr. Lang is also currently a director for Exall
Energy Corporation, a Canadian based oil and gas E&P company. Prior to
joining Synenco, Mr. Lang was a Partner of Techna West Engineering, an Edmonton,
Alberta-based firm that specializes in petroleum-based engineering services,
where he acted as the Vice President, Client Relations from November 2002 to
January 2006. From July 2001 to November 2002, Mr. Lang was President &
Chief Operating Officer (Contract) and the Vice Chairman of the Board of
Directors for Exall Resources Ltd. Slovakia. There, Mr. Lang was responsible for
the restructuring and reorganization of Novácke Chemické Závody a.s., a
subsidiary of Exall Resources that produces organic and inorganic chemicals,
technical gases, polymers, PVC emulsions and suspensions along with other
products.  Prior to that, Mr. Lang held various executive management
positions with Suncor Energy Inc. from June 1982 to July 2001. During this time
Mr. Lang directed an award winning changeover project of an upgrader control
room from manual to computer control and a $210 million flue gas
desulphurization plant. From 1997 to 2001, Mr. Lang served as Vice-President,
Millennium Project where he was accountable for a $3.4 billion oil sands
expansion. Suncor is one of Canada’s largest petroleum recovery and refining
operations, mining vast heavy oil and natural gas reserves in northern Alberta
and throughout western Canada.


37




Marc Berzinshas been a member of our board of directors since his appointment on June
3, 2009.  Mr. Berzins has been a lawyer in private practice in
Edmonton, Alberta, Canada since 1969.




Board
Composition





Our board
of directors is divided into three classes with only one class of directors
being elected in each year and each class serving a three-year term. The term of
office of the first class of directors (Class A), currently consisting of
Bernard Lang, Al Rahmani and  Marc Berzins will expire at our first
annual meeting of stockholders. The term of office of the second class of
directors (Class B), consisting of William C. Glass, will expire at the second
annual meeting. The term of office of the third class of directors (Class C),
currently consisting of Tim G. Culp, will expire at the third annual meeting.
Pursuant to the TEC acquisition agreement, Platinum has agreed that, for so long
as Mr. Culp owns at least one percent (1%) of the outstanding shares of
Platinum, to the extent permitted by applicable law and corporate governance
rules, it shall: (i) cause Mr. Culp to be nominated to the board as a Class C
director and submitted for election by the stockholders of Platinum; and (ii)
cause an individual recommended by Mr. Culp to be nominated to the board as a
Class A director (which individual shall be “independent” within the meaning of
the NASDAQ corporate governance rules) and submitted for election by the
shareholders of Platinum.  Mr. Culp has not yet recommended any
individual to be nominated to the board.





Board
Committees





Audit
Committee





We do not
have an audit committee of our board of directors, nor do we have an audit
committee financial expert. Our entire Board performs the functions of an audit
committee and because our equity securities are not listed on an exchange or
automated quotation system, we are not required to appoint an audit
committee.  We believe that the members of our board of directors are
collectively capable of analyzing and evaluating our financial statements and
understanding internal controls and procedures for financial
reporting.  Accordingly, we do not have an audit committee financial
expert.





We
currently have two board members that are considered “independent” under the
Nasdaq listing standards.





Compensation
Committee





The
compensation committee consists of the following members: Bernard Lang (chair),
and Marc Berzins.





Nominating
Committee





We do not
have a nominating committee. As such, the entire board of directors performs the
function of a nominating committee. The board will consider director candidates
who have relevant business experience, are accomplished in their respective
fields and who possess the skills and expertise to make a significant
contribution to the board of directors, the Company and its
shareholders.  If a shareholder wishes to suggest a proposed name for
board consideration, the name of that nominee and related personal information
should be forwarded to the Chairman of the Board.





Code
of Ethics





We have
adopted a Code of Business Conduct and Ethics that applies to our principal
executive officer, principal financial officer, or persons performing similar
functions, as well as to all our directors, officers and employees. Our Code of
Conduct and Ethics is posted on our Internet website. Our Internet website is
www.platenergy.com. We intend to satisfy the disclosure requirements under Item
5.05 on Form 8-K regarding an amendment to, or waiver from, a provision of our
Code of Business Conduct and Ethics by posting such information on our
website.





Section
16(a) Beneficial Ownership Reporting Compliance





Section
16(a) of the Securities and Exchange Act of 1934, as amended, requires Platinum
directors, officers and persons owning more than 10% of Platinum’s common stock
to file reports of ownership and changes of ownership with the Securities and
Exchange Commission. Based on its review of the copies of such reports furnished
to Platinum, or representations from certain reporting persons that no other
reports were required, Platinum believes that all applicable filing requirements
were complied with during the fiscal year ended December 31,
2009.


38


Item
11.  Executive Compensation.
 
 Summary
Compensation Table
 
 The
following table sets forth the aggregate compensation awarded to, earned by or
paid to our named executive officers in 2009 and 2008.
  Name and Principal Position
                                                    
                                                    Year
                                                    
                                                    Salary
                                                      ($)
                                                    
                                                    Bonus
                                                      ($)
                                                    
                                                    Stock
                                                      Awards
                                                      ($)
                                                    
                                                    Option
                                                      Awards
                                                      (1) ($)
                                                    
                                                    Non-Equity
                                                      Incentive Plan
                                                      Compensation
                                                      ($)
                                                    
                                                    Nonqualified
                                                      Deferred
                                                      Compensation
                                                      Earnings
                                                    
                                                    All Other
                                                      Compensation
                                                      (2) ($)
                                                    
                                                    
                                                    Total ($)Tim
      Culp
                                                    
                                                    2009
                                                    
                                                    134,978
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    7,500
                                                    
                                                    
                                                    
                                                    142,478Chairman
      of the Board(3)
                                                    
                                                    2008
                                                    
                                                    188,760
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    12,000
                                                    
                                                    
                                                    
                                                    200,760Al
      Rahmani
                                                    
                                                    2009
                                                    
                                                    182,533
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    16,309
                                                    
                                                    
                                                    
                                                    198,842Chief
      Executive OfficerBarry
      Kostiner
                                                    
                                                    2009
                                                    
                                                    81,400
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    81,400Former Chief
                                                      Executive
      Officer(4)
                                                    
                                                    2008
                                                    
                                                    188,760
                                                    
                                                    2,750
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    191,510Stephen
      Chalupka
                                                    
                                                    2009
                                                    
                                                    8,215
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    8,215Former
      Chief Financial Officer(8)Mickey
      Cunningham
                                                    
                                                    2009
                                                    
                                                    201,940
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    10,500
                                                    
                                                    
                                                    
                                                    212,440Former
      Chief Financial Officer(7)Lisa
      Meier
                                                    
                                                    2009
                                                    
                                                    81,400
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    81,400Former
      Chief Financial Officer and Treasurer(5)
                                                    
                                                    2008
                                                    
                                                    93,750
                                                    
                                                    2,750
                                                    
                                                    
                                                    
                                                    12,104
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    5,000
                                                    
                                                    
                                                    
                                                    113,604Robert
      L. Kovar
                                                    
                                                    2008
                                                    
                                                    125,510
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    19,494
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    
                                                    145,004Former
      Chief Operating Officer(6)
  (1)
              Represents
      the dollar amount recognized for financial statement reporting purposes
      for the year ended December 31, 2009 in accordance with Financial
      Accounting Standards Board Statement of Financial Accounting Standards No.
      123 (revised 2004), “Share-Based Payment” as modified or supplemented
      (“SFAS 123R”).  See Note 9 – Equity and Stock Plans, for a
      description of the assumptions used in the calculation of stock option
      expense. Ms. Meier and Mr. Kovar each received an option to purchase
      50,000 shares of common stock in 2008 and no awards in
      2009.  Ms. Meier’s stock options had an exercise price of $3.90
      per share, the closing price of the common stock on August 11, 2008, the
      date of grant, and are subject to a four year vesting schedule, with
      one-quarter of such options vesting on each anniversary of the date of
      grant, beginning August 11, 2009.  Mr. Kovar’s options had an
      exercise price of $5.15 per share, the closing price on the date of grant,
      and were subject to a five year vesting schedule, with one-fifth of such
      options to vest on each anniversary of the date of grant, beginning April
      29, 2009.
  (2)
              Represents
      vehicle allowances paid to Tim Culp Mickey Cunningham and Lisa Meier.
      Other compensation paid to Mr. Rahmani represents the amount paid by the
      Company for an apartment for Mr. Rahmani’s
  use.
  (3)
              From
      January 1, 2007 until the completion of the TEC acquisition on
      October 26, 2007, Mr. Culp received compensation from TEC as an
      officer of TEC.  As of March 2, 2009, the position of Chairman
      of the Board is no longer an executive position with the
      Company.
  (4)
              Mr.
      Kostiner did not receive any compensation from Platinum until the
      completion of the TEC acquisition on October 26, 2007.  Mr.
      Kostiner was removed from the position of Chief Executive Officer on March
      2, 2009.
  (5)
              Mrs.
      Meier was hired August 11, 2008.  Mrs. Meier resigned from her
      position on June 10, 2009.
  39
 
 (6)
              Mr.
      Kovar was hired April 29, 2008 upon completion of the acquisition of
      Maverick Engineering, Inc. See “Employment Agreements-Robert L. Kovar”
      below.  On December 3, 2008, Mr. Kovar resigned from his
      position of Chief Operating
Officer.
  (7)
              On
      June 30, 2009, Mickey Cunningham, the Chief Financial Officer of our
      subsidiary, Tandem Energy Corporation, was appointed to the additional
      role as Interim Chief Financial Officer of Platinum.  On
      September 15, 2009, Mr. Cunningham relinquished his role as the Chief
      Financial Officer of Platinum.
 
 (8)
              On
      September 15, 2009, Mr. Stephen Chalupka was appointed Chief Financial
      Officer of Platinum.  Mr.  Chalupka resigned from his
      position as Chief Financial Officer on October 9,
  2009.
 
 Equity Awards
 
 During
2009 equity awards were made under the 2006 Long Term Incentive Plan to certain
of our directors as part of their compensation for serving on the board of
directors.  Our 2006 Long Term Incentive Plan provides for different
types of equity awards, including non-qualified and incentive stock options,
shares of common stock, restricted stock and stock appreciation rights. Since
equity awards may vest and grow in value over time, this component of our
compensation plan is designed to reward performance over a sustained
period.  Stock options represent rights to purchase shares of our
stock at a set price at some date in the future, not to exceed ten years from
the date of grant. Stock options are granted with an exercise price equal to the
closing stock price on the business day immediately preceding the date of
grant.  A total of 172,000 options have been made by the Company as of
May 14, 2010. See “Director Compensation” for information on option grants made
to certain directors.
 
 Employment
Agreements
 
 None.
 
 Long-Term Incentive Compensation
Plan
 
 Platinum’s
2006 Long-Term Incentive Plan (the “2006 Plan”) has been approved by our board
of directors and our stockholders at the special meeting of stockholders held on
October 26, 2007, in connection with the consummation of the TEC
acquisition.  The purposes of the 2006 Plan are to create incentives
designed to motivate our employees to significantly contribute toward our growth
and profitability, to provide our executives, directors and other employees, and
persons who, by their position, ability and diligence, are able to make
important contributions to our growth and profitability, with an incentive to
assist us in achieving our long-term corporate objectives, to attract and retain
executives and other employees of outstanding competence, and to provide such
persons with an opportunity to acquire an equity interest in us.
  We may
grant incentive and non-qualified stock options, stock appreciation rights,
performance units, restricted stock awards and performance bonuses, or
collectively, awards, to our officers and key employees, and those of our
subsidiaries. In addition, the Plan authorizes the grant of non-qualified stock
options and restricted stock awards to our directors and to any independent
contractors and consultants who by their position, ability and diligence are
able to make important contributions to our future growth and profitability.
Generally, all classes of our employees are eligible to participate in our
Plan.  As of May 14, 2010, options to purchase 172,000 shares of our
common stock have been granted under the 2006 Plan.
  We have
reserved a maximum of 4 million shares of our authorized common stock, subject
to adjustment, for issuance upon the exercise of awards to be granted pursuant
to the 2006 Plan.
  The 2006
Plan permits the board to grant the following types of awards:
  Stock Options.  The
2006 Plan provides that the stock options may either be Incentive Stock Options
within the meaning of Section 422 of the Internal Revenue Code of 1986, as
amended, or Non-Qualified Options, which are stock options other than Incentive
Stock Options within the meaning of Sections 422 of the
Code.  Incentive Stock Options may be granted only to our employees or
employees of our subsidiaries, and must be granted at a per share option price
not less than the fair market value of our common stock on the date the
Incentive Stock Option is granted.  The maximum number of shares
subject to stock options that may be awarded in any fiscal year to any employee
may not exceed 100,000 and the number of shares subject to stock options that
may be awarded in any fiscal year to any director may not exceed
10,000.
 
 40
  The
exercise price for each stock option granted under the 2006 Plan will be
determined by our board of directors or a committee of the board at the time of
the grant, but will not be less than fair market value on the date of the grant
(not less than 110% of the fair market value of one share of our common stock on
the date the Incentive Stock Option is granted if the grantee is a 10% or
greater stockholder of the total combined voting power of all of our outstanding
stock of all classes entitled to vote in the election of directors). Our board
of directors or a committee of the board will also determine the duration of
each option; however, no option may be exercisable more than ten years after the
date the option is granted (no more than five years if the grantee is a 10% or
greater stockholder of the total combined voting power of all of our outstanding
stock of all classes entitled to vote in the election of
directors).  Options granted under our Plan will vest at rates
specified in the option agreement at the time of grant; however, all options
granted under our Plan will vest upon the occurrence of a change of control, as
defined in the Plan. The 2006 Plan also contains provisions for our board of
directors or a committee of the board to provide in the participants’ option
award agreements for accelerating the right of an individual employee to
exercise his or her stock option or restricted stock award in the event of
retirement or other termination of employment.  The exercise price of
stock options may be paid in cash, in whole shares of our common stock, in a
combination of cash and our common stock, or in such other form of consideration
as our board of directors or the committee of the board may determine, equal in
value to the exercise price. However, only shares of our common stock which the
option holder has held for at least six months on the date of the exercise may
be surrendered in payment of the exercise price for the options.
  Stock Appreciation Rights.
Stock appreciation rights may or may not be granted in connection with the grant
of an option. The exercise price of stock appreciation rights granted under the
2006 Plan will be determined by the board of directors or a committee of the
board; provided, however, that such exercise price cannot be less than the fair
market value of a share of common stock on a date the stock appreciation right
is granted (subject to adjustments). A stock appreciation right may be exercised
in whole or in such installments and at such times as determined by the board of
directors or a committee of the board.
  Restricted Stock. Restricted
shares of our common stock may be granted under our Plan subject to such terms
and conditions, including forfeiture and vesting provisions, and restrictions
against sale, transfer or other disposition as the board of directors or a
committee of the board may determine to be appropriate at the time of making the
award.  The board of directors or a committee of the board, in its
discretion, may provide in the award agreement for a modification or
acceleration of shares of restricted stock in the event of permanent disability,
retirement or other termination of employment or business relationship with the
grantee. The maximum number of restricted shares that may be awarded under the
Plan to any employee may not exceed 100,000 shares and the number of restricted
shares that may be awarded in any fiscal year to any director may not exceed
10,000 shares.
  Performance Units. The 2006
Plan permits grants of performance units, which are rights to receive cash
payments equal to the difference (if any) between the fair market value of our
common stock on the date of grant and its fair market value on the date of
exercise of the award, except to the extent otherwise provided by the board of
directors or a committee of the board or required by law. Such awards are
subject to the fulfillment of conditions that may be established by the board of
directors or a committee of the board including, without limitation, the
achievement of performance targets based upon the factors described above
relating to restricted stock awards.
  Performance Bonus. The 2006
Plan permits grants of performance bonuses, which may be paid in cash, common
stock or combination thereof as determined by the board of directors or a
committee of the board.  The performance targets will be determined by
the board of directors or a committee of the board based upon the factors
described above relating to restricted stock awards.  Following the
end of the performance period, the board of directors or a committee of the
board will determine the achievement of the performance targets for such
performance period.  An employee’s receipt of cash, common stock or
combination thereof will be contingent upon achievement of performance targets
during the performance period.  Any payment made in shares of common
stock will be based upon the fair market value of the common stock on the
payment date. The maximum amount of any performance bonus payable to a
participant in any calendar year is $500,000.
  The 2006
Plan provides for the acceleration of any unvested portion of any outstanding
awards under the 2006 Plan upon a change of control event.
  Awards
granted under the 2006 Plan that have not vested will generally terminate
immediately upon the grantee’s termination of employment or business
relationship with us or any of our subsidiaries for any reason other than
retirement with our consent, disability or death.
  41
  Outstanding
Equity Awards at Fiscal Year-End 2009
  The
following table sets forth information concerning unexercised options
outstanding as of December 31, 2009 for each named executive
officer.
  Option AwardsName
                  
                  Number of
                    Securities
                    Underlying
                    Unexercised
                    Options #
                    Exercisable
                  
                  
                  Number of
                    Securities
                    Underlying
                    Unexercised
                    Options #
                    Unexercisable
                  
                  
                  Option
                    Exercise
                    Price ($)
                  
                  Option
                    Expiration
                    DateLisa Meier (1)
                  
                  
                  -
                  
                  
                  
                  50,000
                  
                  
                  
                  3.90
                  
                  August 11, 2018Robert L. Kovar
      (2)
                  
                  
                  -
                  
                  
                  
                  50,000
                  
                  
                  
                  5.15
                  
                  April 29, 2018
 
 (1) The
stock options are subject to a four year vesting schedule, with one-quarter of
such options vesting on each anniversary of the date of grant, beginning August
11, 2009.
 (2) The
options were subject to a five year vesting schedule, with one-fifth of
such options vesting on each anniversary of the date of grant, beginning April
29, 2009.
 
 Both Ms.
Meier and Mr. Kovar resigned from the Company in 2009.  Their
separation from the Company is subject to litigation.
  Director
Compensation
  The
following table sets forth information concerning the compensation earned by
non-employee directors during the fiscal year ended December 31,
2009.  Other than Mr. Glass, none of our employee directors received
compensation for their services as a director on our Board.
  Name
                  
                  Option Awards ($)(1)
                  
                  
                  Total ($)Bernard
      Albert Lang(2)
                  
                  
                  1,146
                  
                  
                  
                  21,250William
      Glass
                  
                  
                  -
                  
                  
                  
                  42,750Marc
      Berzins
                  
                  
                  -
                  
                  
                  
                  6,250
 
 (1)  Represents
      the dollar amount recognized for financial statement reporting purposes
      for the fiscal year ended December 31, 2009 in accordance with SFAS 123R
      disregarding the estimate of forfeitures.  See Part II, Item 8 –
      Notes to the Consolidated Financial Statements for the years ended
      December 31, 2009 and 2008, Note 9 – Equity and Stock Plans, for a
      description of the assumptions used in the calculation of stock option
      expense.
  (2)  As
      of December 31, 2009, Mr. Lang held options to purchase 21,000 shares of
      common stock, 17,250 of which were exercisable. Mr. Lang received an
      option to purchase 5,000 shares of common stock on July 16, 2008 with an
      exercise price of $3.90 per share, the closing price on the date of
      grant.  The option is subject to a five year vesting schedule,
      with one-fifth of such options vesting on each anniversary of the date of
      grant, beginning July 16, 2009.  In addition, Mr. Lang received
      an option to purchase 16,000 shares of common stock on January 1, 2009
      with an exercise price of $0.61 per share, the closing price on the date
      of grant.  The option vests on the first anniversary of the date
      of grant, January 1,
2010.
  Compensation
Committee Interlocks and Insider Participation
 
 Our
compensation committee is composed of Bernard Lang and Marc
Berzins.  Mr. Lang serves as chair of the
committee.   For the year ended December 31, 2009, our board of
directors consisted of Messrs. Culp, Glass, Berzins, Lang, Rahmani,
Kostiner and McLennan.  Mr. Kostiner resigned from the board in March
2010 and Mr. McLennan resigned from the board in May 2010. No person who served
as a member of the board of directors during the fiscal year ended December 31,
2009 was a current or former officer or employee or engaged in certain
transactions with us, required to be disclosed by regulations of the
SEC.  There were no compensation committee “interlocks” during the
fiscal year ended December 31, 2009, which generally means that none of our
executive officers served as a director or member of the compensation committee
of another entity, one of whose executive officers served as one of our
directors.
  42
  Item
12.  Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.
 
 The
following table sets forth information regarding the beneficial ownership of our
common stock as of April 12, 2010:
 
 ·
              each
      person known by us to be the beneficial owner of more than 5% of our
      outstanding shares of common stock;
  ·
              each
      named executive officer and director;
and
  ·
              all
      our officers and directors as a
group.
  Name and Address of Beneficial Owner(1)
                  
                  Amount and
                    Nature of
                    Beneficial
                    Ownership
                  
                  
                  Approximate
                    Percentage of
                    Outstanding
                    Common
                    Stock **D.B. Zwirn Special Opportunities
      Fund, L.P. (2)
                  
                  
                  1,625,000
                  
                  
                  
                  7.19
                  %D.B. Zwirn Special Opportunities
      Fund, Ltd. (2)HCM/Z Special Opportunities
      LLC(2)Syd
      Ghermezian(3)
                  
                  
                  12,715,263
                  
                  
                  
                  56.25
                  %Pacific International Holdings
      Group LLC(3)Tim
      G. Culp
                  
                  
                  2,115,976
                  
                  
                  
                  9.36
                  %William
      C. Glass
                  
                  
                  270,000
                  
                  
                  
                  1.19
                  %Bernard
      Albert Lang(4)
                  
                  
                  17,250
                  
                  
                  
                  *
                  %Marc
      Berzins
                  
                  
                  -
                  
                  
                  
                  -
                  %Roderick
      McLennan
                  
                  
                  -
                  
                  
                  
                  -
                  %Al
      Rahmani
                  
                  
                  -
                  
                  
                  
                  -
                  %All
      directors and executive officers as a group (8
individuals)
                  
                  
                  2,403,226
                  
                  
                  
                  10.63
                  %
  43
  *
              Denotes
      percentages of less than 1%.
  **
              Percentage
      of outstanding common stock based on 22,606,475 shares of our common stock
      outstanding as of  April 12,
2010.
  (1)
              Unless
      otherwise indicated, the business address of each of the individuals 11490
      Westheimer Rd., Suite 1000, Houston Texas,
77077
  (2)
              Based
      upon a Statement on Schedule 13G dated September 5, 2006 filed by D.B.
      Zwirn & Co., L.P., DBZ GP, LLC, Zwirn Holdings, LLC, Daniel B. Zwirn,
      D.B. Zwirn Special Opportunities Fund, L.P. (“Fund L.P.”), D.B. Zwirn
      Special Opportunities Fund, Ltd. (“Fund Ltd.”) and HCM/Z Special
      Opportunities LLC (“Opportunities LLC”), D.B. Zwirn & Co., L.P., DBZ
      GP, LLC, Zwirn Holdings, LLC, and Daniel B. Zwirn may each be deemed the
      beneficial owner of (i) 573,750 shares of common stock owned by Fund,
      L.P., (ii) 932,500 shares of common stock owned by Fund, Ltd. and (iii)
      118,750 shares of common stock owned by Opportunities LLC. D.B. Zwirn
      & Co., L.P. is the manager of each of Fund L.P., Fund Ltd. and
      Opportunities LLC, and, consequently, has voting control and investment
      discretion over the shares of common stock held by each of the Funds.
      Furthermore, Daniel B. Zwirn is the managing member of, and thereby
      controls, Zwirn Holdings, LLC, which in turn is the managing member of
      and, thereby, controls DBZ GP, LLC, which in turn is the general partner
      of and thereby controls D.B. Zwirn & Co., L.P. The address of each of
      the parties is 745 Fifth Avenue, 18th Floor, New York, NY 10151, except
      for Fund Ltd. which has an address at P.O. Box 896, George Town, Harbour
      Centre, 2nd Floor, Grand Cayman, Cayman Islands, British West Indies and
      Opportunities LLC which has an address at Seven Mile Beach, Grand Cayman,
      Cayman Islands, British West
Indies.
  (3)
                Based
      on a Statement on Schedule 13D (Amendment No. 12) filed with the SEC on
      March 5, 2010, by Syd Ghermezian and Pacific International Group Holdings
      LLC.  The 12,715,263 shares listed include 12,715,263
      shares of common stock held by Pacific International Group Holdings
      LLC.  Mr. Ghermezian is manager of Pacific International Group
      Holdings LLC. Syd Ghermezian’s address is 9440 West Sahara, Suite 240, Las
      Vegas, Nevada 89117.(4)
                Mr.
      Lang is the holder of options to purchase 21,000 shares of the Company’s
      common stock, 17,250 of which have
vested.
 
 Securities
Authorized for Issuance Under Our Long-Term Incentive Compensation
Plan
 
 The
following chart reflects the status of securities authorized under our Long-Term
Incentive Compensation Plan as of December 31, 2009:
  Equity
Compensation Plan Information
 
 Plan Category
                  
                  Number of securities
                    to be issued upon
                    exercise of outstanding
                    options
                  
                  
                  Weighted-average
                    exercise price of
                    outstanding
                    options
                  
                  
                  Number of securities
                    remaining available
                    for future issuance
                    under equity
                    compensation plansEquity
      compensation plans approved by security holders
                  
                  
                  151,000
                  
                  
                  $
                  4.00
                  
                  
                  
                  3,828,000Equity
      compensation plans not approved by security holders
                  
                  
                  N/A
                  
                  
                  
                  N/A
                  
                  
                  
                  0Total
                  
                  
                  151,000
                  
                  
                  $
                  4.00
                  
                  
                  
                  3,828,000
 
 Item
13.  Certain Relationships and Related Transactions, Director
Independence
 
 Director
Independence
 The Board
has adopted the Nasdaq listing standards’ definition of “independence” to assist
the Board in its determination of whether a director is deemed to be independent
of the Company. Accordingly, after review of any relevant transactions or
relationships involving any director, or any of his or her family members, our
senior management, independent registered public accounting firm, or any of our
significant customers, partners or vendors the Board affirmatively has
determined that, Messrs. Lang, McLennan and Blain are independent. In making
this determination, the Board found that none of these directors has a direct or
indirect material or other disqualifying relationship with us, which, in the
opinion of the Board, would interfere with the exercise of independent judgment
in carrying out the responsibilities of a director.
 
 There
were no transactions with related parties in 2009.
 
 Item
14.  Principal Accounting Fees and Services
 
 The firm
of GBH CPAs, P.C. acts as our independent registered accounting firm. GBH CPAs,
P.C. was appointed as our independent registered accounting firm on January 22,
1010.  We did not pay any fees to GBH CPAs, P.C. during the year ended
December 31, 2009.  Our prior independent registered accounting firm
was Marcum, LLP, formerly known as Marcum & Kleigman LLP.  The
following is a summary of fees paid to Marcum, LLP for services rendered in the
years ended December 31, 2009 and 2008.
  Type
      of Fees
                    
                    2009
                    
                    
                    2008Audit
      fees
                    
                    $
                    264,000
                    
                    
                    $
                    307,000Audit-related
      fees
                    
                    $
                    -
                    
                    
                    $
                    105,500Tax
      fees
                    
                    $
                    –
                    
                    
                    $
                    –All
      other fees
                    
                    $
                    –
                    
                    
                    $
                    –
  Audit
Fees
 During
the year ended December 31, 2009, the fees for our principal accountant were
$69,000 for the review of our Quarterly Reports on Form 10-Q for the quarters
ended March 31, 2009, June 30, 2009 and September 30, 2009, and
$195,000 for the audit of our Financial Statements included in our annual report
on Form 10-K for the year ended December 31, 2010.
 
 During
the year ended December 31, 2008, the fees for our principal accountant were
$307,000 for the review of our Quarterly Reports on Form 10-Q for the quarters
ended March 31, 2008, June 30, 2008 and September 30, 2008 and the audits of our
financial statements to be included in our Annual Reports on Form 10-K for
the years ended December 31, 2008.
  44
 
 Audit
Related Fees
  During
the fiscal year ended December 31, 2008, the audit related fees for our prior
principal accountant were $105,500 in connection with the Company’s Form S-1 and
S-1/A filings made with the SEC and Form 8-K filing made with the SEC on the
Maverick acquisition. We did not incur any audit related fees in the year ended
December 31, 2009.
 
 Tax
Fees
 
 Our
principal accountants rendered no services with respect to tax advice and tax
planning in 2009 or 2008.
 
 All
Other Fees
 
 In 2009
and 2008, there were no fees billed for services provided by the principal
accountant other than those set forth above.
 
 Audit
Committee Approval
 
 We
currently do not have an audit committee. Our board of directors approved the
engagement of GBH CPAs, P.C. as our independent registered public accounting
firm on January 22, 2010.
  45
  PART
IV
  Item 15.Exhibits, Financial Statement
Schedules
  a)
              Financial
      Statements.
  Our
financial statements as set forth in the Index to Financial Statements attached
hereto commencing on page F-1 are hereby incorporated by
reference.
  (b)
              Exhibits.
  The
following exhibits, which are numbered in accordance with Item 601of
Regulation S-K, are filed herewith or, as noted, incorporated by reference
herein:
  Exhibit
                Number
              
              Exhibit
      Description2.1
              
              Asset
      Acquisition Agreement and Plan of Reorganization dated October 4, 2006 by
      and among Platinum, Tandem Energy Corporation, a Colorado corporation, and
      PER Acquisition Corporation, a Delaware corporation and wholly owned
      subsidiary of the Corporation (included as Annex A of the Definitive Proxy
      Statement (File No. 000-51553), filed October 17, 2007 and incorporated by
      reference herein)2.2
              
              Amendment
      No. 1 to the Asset Acquisition Agreement and Plan of Reorganization dated
      December 6, 2006 by and among Platinum, Tandem Energy Corporation and PER
      Acquisition Corporation (included as Annex A of the Definitive Proxy
      Statement (File No. 000-51553), filed October 17, 2007 and incorporated by
      reference herein)2.3
              
              Amendment
      No. 2 to the Asset Acquisition Agreement and Plan of Reorganization dated
      February 9, 2007 by and among Platinum, Tandem Energy Corporation and PER
      Acquisition Corporation (included as Annex A of the Definitive Proxy
      Statement (File No. 000-51553), filed October 17, 2007 and incorporated by
      reference herein)2.4
              
              Amendment
      No. 3 to the Asset Acquisition Agreement and Plan of Reorganization dated
      March 29, 2007 by and among Platinum, Tandem Energy Corporation and PER
      Acquisition Corporation (included as Annex A of the Definitive Proxy
      Statement (File No. 000-51553), filed October 17, 2007 and incorporated by
      reference herein)2.5
              
              Amendment
      No. 4 to the Asset Acquisition Agreement and Plan of Reorganization dated
      June 1, 2007 by and among Platinum, Tandem Energy Corporation and PER
      Acquisition Corporation (included as Annex A of the Definitive Proxy
      Statement (File No. 000-51553), filed October 17, 2007 and incorporated by
      reference herein)2.6
              
              Amendment
      No. 5 to the Asset Acquisition Agreement and Plan of Reorganization dated
      July 18, 2007 by and among Platinum, Tandem Energy Corporation and PER
      Acquisition Corporation (included as Annex A of the Definitive Proxy
      Statement (File No. 000-51553), filed October 17, 2007 and incorporated by
      reference herein)2.7
              
              Amendment
      No. 6 to the Asset Acquisition Agreement and Plan of Reorganization dated
      September 4, 2007 by and among Platinum, Tandem Energy Corporation and PER
      Acquisition Corporation (included as Annex A of the Definitive Proxy
      Statement (File No. 000-51553), filed October 17, 2007 and incorporated by
      reference herein)
  46
  2.8
              
              Amendment
      No. 7 to the Asset Acquisition Agreement and Plan of Reorganization dated
      October 26, 2007 by and among Platinum, Tandem Energy Corporation and PER
      Acquisition Corporation (incorporated by reference from Exhibit 2.8 to
      Platinum’s Current Report on Form 8-K filed November 1,
    2007)2.9
              
              Agreement
      and Plan of Merger among Platinum Energy Resources, Inc., PERMSub, Inc.,
      Maverick Engineering, Inc. and Robert L. Kovar Services, LLC as
      Stockholder Representative entered into as of March 18, 2008 (incorporated
      by reference from Exhibit 2.1 to Platinum’s Current Report on Form 8-K
      filed March 20, 2008)3.1
              
              Amended
      and Restated Certificate of Incorporation of Platinum (incorporated by
      reference from Exhibit 3.1 to Platinum’s Current Report on Form 8-K filed
      November 1, 2007)3.2
              
              Amended
      and Restated Bylaws of Platinum (incorporated by reference from Exhibit
      3.2 to Platinum’s Current Report on Form 8-K filed November 1,
      2007)4.1
              
              Specimen
      Unit Certificate (incorporated by reference from Exhibit 4.1 to Platinum’s
      Registration Statement on Form S-1 (File No. 333-125687) on June 10,
      2005)4.2
              
              Specimen
      Common Stock Certificate (incorporated by reference from Exhibit 4.2 to
      Platinum’s Registration Statement on Form S-1 (File No. 333-125687) on
      June 10, 2005)4.3
              
              Specimen
      Warrant Certificate (incorporated by reference from Exhibit 4.3 to
      Platinum’s Registration Statement on Form S-1 (File No. 333-125687) on
      June 10, 2005)4.4
              
              Form
      of Warrant Agreement between American Stock Transfer & Trust Company
      and the Registrant (incorporated by reference from Exhibit 4.4 to
      Platinum’s Registration Statement on Form S-1 (File No. 333-125687) on
      June 10, 2005)4.5
              
              Form
      of Unit Purchase Option to be granted to Representative (incorporated by
      reference from Exhibit 4.5 to Platinum’s Registration Statement on Form
      S-1 (File No. 333-125687) on June 10, 2005)4.6
              
              Warrant
      Clarification and Confirmation Agreement, dated as of November 3, 2006,
      between Platinum Resources, Inc. and American Stock Transfer and Trust
      Company (incorporated by reference from Exhibit 4.1 to Platinum’s Current
      Report on Form 8-K filed November 9, 2006)4.7
              
              Amendment
      to Unit Purchase Options, dated as of November 3, 2006, among Platinum
      Energy Resources, Inc. and the holders of Unit Purchase Options
      (incorporated by reference from Exhibit 4.2 to Platinum’s Current Report
      on Form 8-K filed November 9, 2006)10.1
              
              Credit
      Agreement among Tandem Energy Corporation, PER Gulf Coast, Inc. and Bank
      of Texas, N.A. entered into as of March 14, 2008 (incorporated by
      reference from Exhibit 10.1 to Platinum’s Current Report on Form 8-K filed
      March 20, 2008)10.2
              
              Credit
      Agreement, effective as of June 8, 2005, between Tandem Energy
      Corporation and Guaranty Bank, FSB (incorporated by reference from
      Exhibit 10.1 to Platinum’s Current Report on Form 8-K filed November 1,
      2007)
  47
 
 10.3
              
              First
      Amendment to Credit Agreement, effective as of October 21, 2005, between
      TEC and Guaranty Bank, FSB (incorporated by reference from Exhibit 10.2 to
      Platinum’s Current Report on Form 8-K filed November 1,
    2007)10.4
              
              Waiver
      and Second Amendment to Credit Agreement, effective as of February 15,
      2006, between TEC and Guaranty Bank, FSB (incorporated by reference from
      Exhibit 10.3 to Platinum’s Current Report on Form 8-K filed November 1,
      2007)10.5
              
              Assignment,
      Waiver and Third Amendment to Credit Agreement, effective as of October
      26, 2007, among TEC, New TEC and Guaranty Bank, FSB (incorporated by
      reference from Exhibit 10.4 to Platinum’s Current Report on Form 8-K filed
      November 1, 2007)10.6
              
              Platinum’s
      2006 Long-Term Incentive Compensation Plan (incorporated by reference from
      Exhibit 10.5 to Platinum’s Current Report on Form 8-K filed November 1,
      2007)10.7
              
              Office
      Lease Agreement executed July 28, 2006 by and between Loraine at Texas
      Office Tower, Ltd. dba Centennial Tower, Ltd. and TEC (incorporated by
      reference from Exhibit 10.6 to Platinum’s Current Report on Form 8-K filed
      November 1, 2007)10.8
              
              Form
      of Stock Escrow Agreement between the Registrant, American Stock Transfer
      & Trust Company and the Initial Stockholders (incorporated by
      reference from Exhibit 10.10 to Platinum’s Registration Statement on Form
      S-1 (File No. 333-125687) on June 10, 2005)10.9
              
              Form
      of Registration Rights Agreement among the Registrant and the Initial
      Stockholders (incorporated by reference from Exhibit 10.13 to Platinum’s
      Registration Statement on Form S-1 (File No. 333-125687) on June 10,
      2005)10.10
              
              Purchase
      and Sale Agreement, dated December 18, 2007 entered into between Tandem
      Energy Corporation and Lothian Oil, Inc. (incorporated by reference from
      Exhibit 10.1 to Platinum’s Current Report on Form 8-K filed on January 3,
      2008)10.11
              
              Amendment,
      dated December 27, 2007 to Purchase and Sale Agreement, dated December 18,
      2007 entered into between Tandem Energy Corporation and Lothian Oil, Inc.
      (incorporated by reference from Exhibit 10.2 to Platinum’s Current Report
      on Form 8-K filed on January 3, 2008)14
              
              Code
      of Conduct and Ethics (incorporated by reference from Exhibit 14 to
      Platinum’s Annual Report on Form 10-K for the fiscal year ended December
      31, 2005 filed on March 24, 2006)21
              
              Subsidiaries
      of Platinum (incorporated by reference from Exhibit 21 to Platinum’s
      Annual Report on Form 10-K for the fiscal year ended December 31, 2007
      filed on April 1, 2008)23
              
              Consent
      of independent petroleum consultants.31.1
              
              Section
      302 Certification of Principal Executive
Officer
  48
 
 31.2
              
              Section
      302 Certification of Principal Financial Officer32.1
              
              Section
      906 Certification of Principal Executive Officer32.2
              
              Section
      906 Certification of Principal Financial Officer99.1
              
              Report
      of Williamson Petroleum Consultants, Inc., Petroleum
      Consultants
  49
 
 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, hereunder duly authorized, as of June 30, 2010.
  PLATINUM
      ENERGY RESOURCES, INC.By
                /s/
      AL RAHMANIAl
      RahmaniInterim
      Chief Executive Officer and
Director
  Pursuant
to the requirements of the Securities Exchange Act of 1934, the following
persons on behalf of the Registrant and in the capacity indicated have signed
this report below as of June 30, 2010.
  /s/
      AL RAHMANI
              
              Interim
      Chief Executive Officer, DirectorAl
      Rahmani
              
              (Principal
      Executive Officer)/s/
      AL RAHMANI
              
              Principal
      Accounting OfficerAl
      Rahmani
              
              (Principal
      Financial and Accounting Officer)/s/
      TIM G. CULP
              
              Chairman
      of the BoardTim
      G. Culp/s/
      WILLIAM C. GLASS
              
              President,
      DirectorWilliam
      C. Glass/s/
      BERTRAM A. LANG
              
              DirectorBertram
      A. Lang/s/
      Marc Berzins
              
              DirectorMarc
      Berzins
  50
  PLATINUM
ENERGY RESOURCES, INC.
  INDEX
TO CONSOLIDATED FINANCIAL STATEMENTS
  PageReports
      of Independent Registered Public Accounting Firms
                    
                    
                    F-2Consolidated
      Balance Sheets as of December 31, 2009 and 2008
                    
                    
                    F-4Consolidated
      Statements of Operations for the Years Ended December 31, 2009 and
      2008
                    
                    
                    F-5Consolidated
      Statements of Stockholders’ Equity for the Years Ended December 31,
      2009 and 2008
                    
                    
                    F-6Consolidated
      Statements of Cash Flows for the Years Ended December 31, 2009 and
      2008
                    
                    
                    F-7Notes
      to the Consolidated Financial Statements
                    
                    
                    F-8
  F-1
  REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
  To the
Board of Directors and Shareholders
 Platinum
Energy Resources, Inc. and Subsidiaries
 Houston,
Texas
 
 We have
audited the accompanying consolidated balance sheet of Platinum Energy
Resources, Inc. and Subsidiaries (the “Company”) as of December 31, 2009, and
the related consolidated statements of operations, stockholders’ equity and cash
flows for the year then ended.  These financial statements are the
responsibility of the Company’s management. Our responsibility is to express an
opinion on these financial statements based on our audit.
 
 We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States).  Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement.  The Company is not
required to have, nor were we engaged to perform, an audit of its internal
control over financial reporting. Our 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 also includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation.  We believe that our audit provides a
reasonable basis for our opinion.
 
 In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Platinum Energy
Resources, Inc. and Subsidiaries, as of December 31, 2009 and the consolidated
results of their operations and their cash flows for the year then ended in
conformity with accounting principles generally accepted in the United States of
America.
 
 The
accompanying consolidated financial statements have been prepared assuming that
the Company will continue as a going concern.  As discussed in Note 2
to the consolidated financial statements, the Company has experienced
significant losses since inception and is currently in default of its debt
agreements.  These conditions raise substantial doubt about the
Company’s ability to continue as a going concern.  Management’s plans
regarding these matters are also discussed in Note 2.  The
accompanying consolidated financial statements do not include any adjustments
that might result from the outcome of this uncertainty.
  /s/ GBH
CPAs, P.C.
 
 GBH CPAs,
PC
 Houston,
Texas
 June 30,
2010
  F-2
  REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
 
 
 To the
Board of Directors and Shareholders
 of
Platinum Energy Resources, Inc. and Subsidiaries
 
 We have
audited the accompanying consolidated balance sheet of Platinum Energy
Resources, Inc. and Subsidiaries (the “Company”) as of December 31, 2008, and
the related consolidated statements of operations, stockholders’ equity and cash
flows for the year then ended.  These financial statements are the
responsibility of the Company’s management. Our responsibility is to express an
opinion on these financial statements based on our audit.
 
 We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States).  Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement.  The Company is not
required to have, nor were we engaged to perform, an audit of its internal
control over financial reporting. Our 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 also includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation.  We believe that our audit provides a
reasonable basis for our opinion.
 
 In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Platinum Energy
Resources, Inc. and Subsidiaries, as of December 31, 2008, and the consolidated
results of their operations and their cash flows for the year then ended in
conformity with accounting principles generally accepted in the United States of
America.
 
 /s/
Marcum LLP
 (formerly
Marcum & Kliegman LLP)
 New York,
New York
 May 29,
2009
  F-3
 
 PLATINUM
ENERGY RESOURCES, INC. AND SUBSIDIARIES
 
 CONSOLIDATED
BALANCE SHEETS
 
 December
      31,2009
                      
                      
                      2008ASSETSCURRENT
      ASSETSCash
      and cash equivalents
                      
                      $
                      2,941,939
                      
                      
                      $
                      3,668,092Accounts
      receivable, net of $224,392 and $164,392 allowance for doubtful accounts
      as of December 31, 2009 and 2008, respectivelyOil
      and gas sales
                      
                      
                      2,079,201
                      
                      
                      
                      1,629,931Service
                      
                      
                      2,961,546
                      
                      
                      
                      5,255,041Inventory
                      
                      
                      410,791
                      
                      
                      
                      436,477Fair
      value of commodity derivatives - current
                      
                      
                      3,595,144
                      
                      
                      
                      1,968,186Prepaid
      expenses and other current assets
                      
                      
                      610,989
                      
                      
                      
                      747,225Total
      current assets
                      
                      
                      12,599,610
                      
                      
                      
                      13,704,952Property
      and equipment, at costOil
      and gas properties, full cost method
                      
                      
                      208,291,206
                      
                      
                      
                      204,372,437Other
      property and equipment
                      
                      
                      5,565,746
                      
                      
                      
                      5,492,072Less
      accumulated depreciation, depletion, amortization and
      impairment
                      
                      
                      (167,973,630
                      )
                      
                      
                      (145,016,531
                      )Property
      and equipment, net
                      
                      
                      45,883,322
                      
                      
                      
                      64,847,978Other
      assetsIntangible
      assets, net
                      
                      
                      -
                      
                      
                      
                      5,061,066Fair
      value of commodity derivatives
                      
                      
                      3,190,294
                      
                      
                      
                      18,562,702Real
      estate held for development
                      
                      
                      2,700,000
                      
                      
                      
                      2,700,000Total
      assets
                      
                      $
                      64,373,226
                      
                      
                      $
                      104,876,698LIABILITIES
      AND STOCKHOLDERS' EQUITYCURRENT
      LIABILITIESAccounts
      payableTrade
      service
                      
                      $
                      2,154,188
                      
                      
                      $
                      2,551,808Oil
      and gas
                      
                      
                      920,818
                      
                      
                      
                      1,115,114Accrued
      liabilities and other
                      
                      
                      4,033,935
                      
                      
                      
                      4,437,995Income
      taxes payable
                      
                      
                      328,324
                      
                      
                      
                      119,770Current
      Portion of Asset
      Retirement Obligation
                      
                      
                      812,670
                      
                      
                      
                      -Current
      maturities of long-term debt, capital lease obligations and notes
      payable
                      
                      
                      17,802,925
                      
                      
                      
                      13,403,731Total
      current liabilities
                      
                      
                      26,052,860
                      
                      
                      
                      21,628,418Long-term
      debt and capital lease obligations, net of current portion
                      
                      $
                      111,315
                      
                      
                      
                      4,687,423Notes
      payable - acquisitions
                      
                      
                      3,422,433
                      
                      
                      
                      3,231,959Other
      accrued liabilities
                      
                      
                      119,735
                      
                      
                      
                      148,458Asset
      retirement obligation
                      
                      $
                      6,426,424
                      
                      
                      
                      4,537,243Deferred
      income taxes
                      
                      
                      -
                      
                      
                      
                      10,459,000Total
      long-term liabilities
                      
                      $
                      10,079,907
                      
                      
                      
                      23,064,083COMMITMENTS
      AND CONTINGENCIESSTOCKHOLDERS'  EQUITYPreferred
      stock, $.0001 par value, 1,000,000 authorized, 0 shares
    issued
                      
                      
                      —
                      
                      
                      
                      —Common
      stock, $.0001 par value; 75,000,000 shares authorized; 24,068,675 shares
      issued and 22,070,762 shares outstanding in each period,
      respectively
                      
                      
                      2,407
                      
                      
                      
                      2,407Additional
      paid-in capital
                      
                      
                      155,175,771
                      
                      
                      
                      155,100,474Accumulated
      deficit
                      
                      
                      (111,276,255
                      )
                      
                      
                      (79,257,220
                      )Treasury
      stock - 1,997,913 shares, at cost
                      
                      
                      (15,661,464
                      )
                      
                      
                      (15,661,464
                      )Total
      stockholders' equity
                      
                      $
                      28,240,459
                      
                      
                      
                      60,184,197Total
      liabilities and stockholders' equity
                      
                      $
                      64,373,226
                      
                      
                      $
                      104,876,698
  The
accompanying notes are an integral part of these consolidated financial
statements.
  F-4
 
 PLATINUM
ENERGY RESOURCES, INC. AND SUBSIDIARIES
 
 CONSOLIDATED
STATEMENTS OF OPERATIONS
 
 Year
      ended December 31,2009
                    
                    
                    2008RevenuesOil
      and gas sales
                    
                    $
                    17,173,709
                    
                    
                    $
                    34,156,974Service
      revenues
                    
                    
                    18,520,324
                    
                    
                    
                    19,025,92135,694,033
                    
                    
                    
                    53,182,895Costs
      and expensesLease
      and other operating expense
                    
                    
                    9,656,006
                    
                    
                    
                    13,972,725Cost
      of service revenues
                    
                    
                    17,542,774
                    
                    
                    
                    16,698,860Marketing,
      general and administrative expense
                    
                    
                    8,632,621
                    
                    
                    
                    11,369,994Depreciation,
      depletion and amortization expense
                    
                    
                    7,101,352
                    
                    
                    
                    12,608,072Impairment
      of oil and gas properties and equipment
                    
                    
                    16,597,257
                    
                    
                    
                    131,795,087Impairment
      of goodwill and intangible assets
                    
                    
                    4,397,928
                    
                    
                    
                    8,040,179Accretion
      of abandonment obligations
                    
                    
                    322,969
                    
                    
                    
                    266,054Total
      costs and expenses
                    
                    
                    64,250,907
                    
                    
                    
                    194,750,971Operating
      loss
                    
                    
                    (28,556,874
                    )
                    
                    
                    (141,568,076
                    )OTHER
      INCOME (EXPENSE)Interest
      income
                    
                    
                    14,482
                    
                    
                    
                    199,162Interest
      expense
                    
                    
                    (1,283,525
                    )
                    
                    
                    (924,520
                    )Change
      in fair value of commodity derivatives
                    
                    
                    (12,525,540
                    )
                    
                    
                    17,309,196Other
                    
                    
                    7,678
                    
                    
                    
                    (6,117
                    )Total
      other income (expense)
                    
                    
                    (13,786,905
                    )
                    
                    
                    16,577,721Loss
      Before Income Taxes
                    
                    
                    (42,343,779
                    )
                    
                    
                    (124,990,355
                    )Provision
      (Benefit) For Income Taxes
                    
                    
                    (10,324,744
                    )
                    
                    
                    (44,170,760
                    )Net
      Loss
                    
                    $
                    (32,019,035
                    )
                    
                    $
                    (80,819,595
                    )WEIGHTED
      AVERAGE NUMBER OF COMMON SHARES:Basic
      and diluted
                    
                    
                    22,070,762
                    
                    
                    
                    22,070,762NET
      LOSS PER COMMON SHARE:Basic
      and diluted
                    
                    $
                    (1.45
                    )
                    
                    $
                    (3.66
                    )
  The
accompanying notes are an integral part of these consolidated financial
statements.
  F-5
 
 PLATINUM
ENERGY RESOURCES, INC. AND SUBSIDIARIES
 
 CONSOLIDATED
STATEMENT OF STOCKHOLDERS’ EQUITY
 
 Common
      stock
                                                            
                                                            
                                                            
                                                            
                                                            
                                                            Treasury
      stockAdditional
                                                              paid-
                                                            
                                                            Retained
                                                              earnings
                                                            
                                                            
                                                            
                                                            
                                                            
                                                            
                                                            Total
                                                              stockholders'Shares
                                                            
                                                            Amount
                                                            
                                                            in
      capital
                                                            
                                                            (deficit)
                                                            
                                                            Shares
                                                            
                                                            Amount
                                                            
                                                            
                                                            equityBalance
      -January
      1, 2008
                                                            
                                                            24,068,675
                                                            
                                                            $
                                                            2,407
                                                            
                                                            $
                                                            155,064,142
                                                            
                                                            $
                                                            1,562,375
                                                            
                                                            
                                                            (1,997,913
                                                            )
                                                            $
                                                            (15,661,464
                                                            )
                                                            
                                                            $
                                                            140,967,460Stock
      based compensation
                                                            
                                                            —
                                                            
                                                            
                                                            —
                                                            
                                                            
                                                            36,332
                                                            
                                                            
                                                            —
                                                            
                                                            
                                                            —
                                                            
                                                            
                                                            —
                                                            
                                                            
                                                            
                                                            36,332Net
      loss
                                                            
                                                            —
                                                            
                                                            
                                                            —
                                                            
                                                            
                                                            —
                                                            
                                                            
                                                            (80,819,595
                                                            )
                                                            
                                                            —
                                                            
                                                            
                                                            —
                                                            
                                                            
                                                            
                                                            (80,819,595
                                                            )Balance
      -December
      31, 2008
                                                            
                                                            24,068,675
                                                            
                                                            $
                                                            2,407
                                                            
                                                            $
                                                            155,100,474
                                                            
                                                            $
                                                            (79,257,220
                                                            )
                                                            
                                                            (1,997,913
                                                            )
                                                            $
                                                            (15,661,464
                                                            )
                                                            
                                                            $
                                                            60,184,197Stock
      based  compensation
                                                            
                                                            —
                                                            
                                                            
                                                            —
                                                            
                                                            
                                                            75,297
                                                            
                                                            
                                                            —
                                                            
                                                            
                                                            —
                                                            
                                                            
                                                            —
                                                            
                                                            
                                                            
                                                            75,297Net
      loss
                                                            
                                                            —
                                                            
                                                            
                                                            —
                                                            
                                                            
                                                            —
                                                            
                                                            
                                                            (32,019,035
                                                            )
                                                            
                                                            —
                                                            
                                                            
                                                            —
                                                            
                                                            
                                                            
                                                            (32,019,035
                                                            )Balance
      -December
      31, 2009
                                                            
                                                            24,068,675
                                                            
                                                            $
                                                            2,407
                                                            
                                                            $
                                                            155,175,771
                                                            
                                                            $
                                                            (111,276,255
                                                            )
                                                            
                                                            (1,997,913
                                                            )
                                                            $
                                                            (15,661,464
                                                            )
                                                            
                                                            $
                                                            28,240,459
  The
accompanying notes are an integral part of these consolidated financial
statements.
  F-6
 
 PLATINUM
ENERGY RESOURCES, INC. AND SUBSIDIARIES
 
 CONSOLIDATED
STATEMENTS OF CASH FLOWS
 
 Year
      Ended December 31,2009
                                  
                                  
                                  2008Cash
      Flows From Operating ActivitiesNet
      loss
                                  
                                  $
                                  (32,019,035
                                  )
                                  
                                  $
                                  (80,819,595
                                  )Adjustments
      to reconcile net loss to net cash provided by (used in) operating
      activities:Depreciation,
      depletion and amortization
                                  
                                  
                                  7,101,352
                                  
                                  
                                  
                                  12,608,072Impairment
      of oil and gas properties and equipment
                                  
                                  
                                  16,597,257
                                  
                                  
                                  
                                  131,795,087Impairment
      of goodwill and intangible assets
                                  
                                  
                                  4,397,928
                                  
                                  
                                  
                                  8,040,179Accretion
      of asset retirement obligation and debt discount
                                  
                                  $
                                  561,619
                                  
                                  
                                  
                                  415,837Stock
      based compensation
                                  
                                  
                                  75,297
                                  
                                  
                                  
                                  36,332Deferred
      income taxes
                                  
                                  
                                  (10,459,000
                                  )
                                  
                                  
                                  (44,199,003
                                  )Commodity Derivatives
                                  
                                  
                                  12,525,540
                                  
                                  
                                  
                                  (22,565,418
                                  )Changes
      in operating assets and liabilities:Accounts
      receivable
                                  
                                  
                                  1,844,225
                                  
                                  
                                  
                                  698,640Inventory
                                  
                                  
                                  25,686
                                  
                                  
                                  
                                  (347,921
                                  )Prepaid
      expenses and other current assets
                                  
                                  
                                  136,236
                                  
                                  
                                  
                                  (290,477
                                  )Accounts
      payable
                                  
                                  
                                  (591,916
                                  )
                                  
                                  
                                  824,990Accrued
      liabilities and other
                                  
                                  
                                  (432,783
                                  )
                                  
                                  
                                  2,063,455Income
      taxes payable
                                  
                                  
                                  208,554
                                  
                                  
                                  
                                  (135,190
                                  )Commodity
      derivatives
                                  
                                  
                                  —
                                  
                                  
                                  
                                  (1,008,566
                                  )Net
      cash provided by (used in) operating activities
                                  
                                  
                                  (29,040
                                  )
                                  
                                  
                                  7,116,423Cash
      Flows From Investing ActivitiesAdditions
      to property and equipment
                                  
                                  
                                  (1,691,933
                                  )
                                  
                                  
                                  (20,663,083
                                  )Acquisition
      of other businesses - oil and gas properties
                                  
                                  
                                  —
                                  
                                  
                                  
                                  (7,939,139
                                  )Acquisition
      of Maverick, net of cash of $ 621,518
                                  
                                  
                                  —
                                  
                                  
                                  
                                  (5,640,601
                                  )Advance
      payment and costs, Pleasanton transaction
                                  
                                  
                                  —
                                  
                                  
                                  
                                  2,522,639Cash
      Received (Paid) on settlement of derivative contracts
                                  
                                  
                                  1,219,910
                                  
                                  
                                  
                                  —Net
      cash  used in investing activities
                                  
                                  
                                  (472,023
                                  )
                                  
                                  
                                  (31,720,184
                                  )Cash
      Flows From Financing ActivitiesProceeds
      of revolving credit facility
                                  
                                  
                                  1,000,000
                                  
                                  
                                  
                                  12,008,767Payments,
      long-term debt and capital leases
                                  
                                  
                                  (1,225,090
                                  )
                                  
                                  
                                  (166,533
                                  )Net
      cash provided by (used in) financing activities
                                  
                                  
                                  (225,090
                                  )
                                  
                                  
                                  11,842,234Net
      decrease in cash
                                  
                                  
                                  (726,153
                                  )
                                  
                                  
                                  (12,761,527
                                  )Cash
      and cash equivalents - beginning of the period
                                  
                                  
                                  3,668,092
                                  
                                  
                                  
                                  16,429,619Cash
      and cash equivalents - end of the period
                                  
                                  $
                                  2,941,939
                                  
                                  
                                  $
                                  3,668,092SUPPLEMENTAL
      DISCLOSURE OF CASH FLOW INFORMATIONCash
      paid during the period for:Interest
                                  
                                  $
                                  703,000
                                  
                                  
                                  $
                                  635,203Income
      taxesNon-Cash
      Investing and Financing Activities:Revision
      to estimate of asset retirement obligation
                                  
                                  
                                  2,378,882
                                  
                                  
                                  
                                  -Issuance
      of notes payable - Pleasanton acquisition
                                  
                                  $
                                  -
                                  
                                  
                                  $
                                  550,000Adjustment
      of purchase price of oil and gas properties and deferred
    taxes
                                  
                                  $
                                  -
                                  
                                  
                                  $
                                  4,640,000Acquisition
      of Maverick (cash flow notes, net of discount)
                                  
                                  $
                                  -
                                  
                                  
                                  $
                                  3,034,000Acquisition
      of Maverick in 2008:Cash
                                  
                                  $
                                  -
                                  
                                  
                                  $
                                  621,518Accounts
      receivable
                                  
                                  
                                  -
                                  
                                  
                                  
                                  4,296,033Other
      current assets
                                  
                                  
                                  -
                                  
                                  
                                  
                                  157,303Property
      and equipment
                                  
                                  
                                  -
                                  
                                  
                                  
                                  1,510,052Goodwill
                                  
                                  
                                  -
                                  
                                  
                                  
                                  5,912,611Intangible
      assets
                                  
                                  
                                  -
                                  
                                  
                                  
                                  5,522,250Accounts
      payable
                                  
                                  
                                  -
                                  
                                  
                                  
                                  (634,984
                                  )Accrued
      expenses
                                  
                                  
                                  -
                                  
                                  
                                  
                                  (1,765,404
                                  )Accrued
      payroll
                                  
                                  
                                  -
                                  
                                  
                                  
                                  (576,165
                                  )Term
      notes and revolving line of credit
                                  
                                  
                                  -
                                  
                                  
                                  
                                  (5,223,086
                                  )Capitalized
      lease obligations
                                  
                                  
                                  -
                                  
                                  
                                  
                                  (524,010
                                  )Total
      purchase price
                                  
                                  
                                  -
                                  
                                  
                                  
                                  9,296,118Less:
      Cash consideration paid to sellers
                                  
                                  
                                  -
                                  
                                  
                                  
                                  (6,000,000
                                  )Less:
      Transaction costs
                                  
                                  
                                  -
                                  
                                  
                                  
                                  (262,118
                                  )Non-cash
      consideration issued to sellers
                                  
                                  $
                                  -
                                  
                                  
                                  $
                                  3,034,000
  The
accompanying notes are an integral part of these consolidated financial
statements.
  F-7




PLATINUM
ENERGY RESOURCES, INC. AND SUBSIDIARIES
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 For
the Years Ended December 31, 2009 and 2008
 
 Note
1 - Organization, Business and Operations and Basis of
Presentation
  Platinum
Energy Resources, Inc. and subsidiaries (the “Company” or “Platinum”) was
incorporated in Delaware on April 25, 2005 as a blank check company for the
purpose of effecting a business combination with an unidentified operating
business in the global oil and natural gas industry. In October 2005, the
Company completed an initial public offering and raised gross proceeds of
approximately $115 million, as described in Note 12.  In October 2007,
the Company acquired substantially all of the assets and assumed all of the
liabilities of Tandem Energy Corporation (“Tandem”). Prior to the Tandem
transactions, the Company had no operations other than conducting an initial
public offering and seeking a business combination. Effective on April 29, 2008,
the Company acquired Maverick Engineering, Inc. (“Maverick”), an engineering
services enterprise which was incorporated in December 1993 in the State of
Texas, described in Note 4.
 
 Subsequent
to the Maverick acquisition, the Company considers itself to be in two lines of
business as follows:
 
 (i) The
oil and gas division operations have approximately 37,000 acres under lease in
relatively long-lived fields with well-established production histories, 21,000
of which were acquired as part of the Tandem acquisition. The Company’s
properties are concentrated primarily in the Gulf Coast region in Texas, the
Permian Basin in Texas and New Mexico and the Fort Worth Basin in
Texas;
 and
 
 (ii)
Maverick provides engineering and construction services primarily for three
types of clients: (1) upstream oil and gas, domestic oil and gas producers and
pipeline companies; (2) industrial, petrochemical and refining plants; and (3)
infrastructure, private and public sectors, including state municipalities,
cities, and port authorities. Maverick operates out of facilities headquartered
in Houston, Texas and operates primarily in Texas.
 
 Note
2 – Going Concern
 
 The
accompanying consolidated financial statements have been prepared assuming the
Company will continue as a going concern.  The Company has incurred
significant losses, resulting in cumulative losses of $111,276,255 through
December 31, 2009. Additionally, the Company’s outstanding loan with the Bank of
Texas matured on June 1, 2010 and remains unpaid as of June 30, 2010; however,
as of June 30, 2010, the Company has not received a notice of foreclosure from
the Bank of Texas. The Company’s current cash on hand is not adequate to satisfy
the Bank of Texas debt. These conditions raise substantial doubt about the
Company’s ability to continue as a going concern.
 
 Management’s
plan to resolve the uncertainty about our ability to continue as a going concern
includes cost reductions and seeking additional debt financing or the
refinancing of our existing Bank of Texas loan.  There is no assurance that
we will be able to obtain such additional funds through equity or debt
financing, or any combination thereof, or on satisfactory terms or at all.
Additionally, no assurance can be given that any such financing or refinancing,
if achievable, will be adequate to meet our ultimate capital needs and to
support our growth. If the Company is not able to obtain additional financing on
a timely basis and on satisfactory terms, our operations would be materially
negatively impacted.
 
 As a
result of the above discussed conditions, there exists substantial doubt about
our ability to continue as a going concern. Our consolidated financial
statements are presented on a going concern basis, which contemplates the
realization of assets and satisfaction of liabilities in the normal course of
business. The consolidated financial statements do not include any adjustments
relating to the recoverability of the recorded assets or the classification of
liabilities that may be necessary should it be determined that we are unable to
continue as a going concern.
  Note 3 — Summary of Significant
Accounting Policies
  Principles of
Consolidation
  The
consolidated financial statements include the accounts of the Company and its
wholly-owned subsidiaries. All material intercompany balances and transactions
have been eliminated.
  Acquisitions
  Acquisitions
have been accounted for using the purchase method of accounting. The acquired
companies’ results have been included in the accompanying financial statements
from their respective dates of acquisition. Allocation of the purchase price for
acquisitions was based on the estimates of fair value of the net assets
acquired.
  Estimates
and Assumptions
  The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and the disclosure of contingent assets and liabilities as of the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates. Significant estimates include volumes of oil and natural gas
reserves, abandonment obligations, impairment of oil and natural gas properties,
depreciation, depletion and amortization, income taxes, bad debts, derivatives,
contingencies and litigation.
  F-8
 
 PLATINUM
ENERGY RESOURCES, INC. AND SUBSIDIARIES
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 For
the Years Ended December 31, 2009 and 2008
 
 Oil and
natural gas reserve estimates, which are the basis for unit-of-production
depletion and the full cost ceiling test, have a number of inherent
uncertainties. The accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and judgment.
Results of drilling, testing, and production subsequent to the date of the
estimate may justify revision of such estimate. Accordingly, reserve estimates
are often different from the quantities of oil and natural gas that are
ultimately recovered. In addition, reserve estimates are vulnerable to changes
in wellhead prices of crude oil and natural gas. Such prices have been volatile
in the past and can be expected to be volatile in the future.
 
 Cash
and Cash Equivalents
 
 Cash and
cash equivalents include demand deposits and money market funds for purposes of
the statements of cash flows. The Company considers all highly liquid monetary
instruments with original maturities of three months or less to be cash
equivalents.  Financial instruments that potentially subject the
Company to concentrations of credit risk consist primarily of cash
deposits.  Accounts at each financial institution are insured by the
Federal Deposit Insurance Corporation (“FDIC”) up to $250,000.   As of
December 31, 2009, the Company had deposits with institutions in excess of the
insured limits totaling $2,311,178.
 
 Accounts
Receivable and Allowance for Doubtful Accounts
  Oil and Gas Operations - The
Company’s trade receivables consist primarily of receivables from first
purchasers of the Company’s share of oil and gas production
and  non-operators who own an interest in properties which the Company
operates.  The Company has the ability and the right to withhold oil
and gas revenues from any owner who is delinquent in their payments to the
Company for their share of well costs and receivables and receivables are
recorded when the Company incurs expenses on behalf of the
non-operators.
 
 Services - Revenues are
billed and accounts receivable recorded as services are performed. Most services
revenues are derived from time and material projects. Unbilled receivables
represent costs and estimated fees on work for which billings have not been
presented to customers. When billed, these amounts are included in accounts
receivable - trade. Unbilled accounts receivable include management’s best
estimates of the amounts expected to be realized on the work that has been
performed to date.
  Allowance for doubtful accounts –The Company’s reported balance of accounts receivable, net of allowance
for doubtful accounts, represents management’s estimate of the amount that
ultimately will be realized in cash.  The Company reviews the adequacy
of the allowance for doubtful accounts on an ongoing basis, using historical
payment trends and the age of the receivables and knowledge of the individual
customers.  When the analyses indicate, management increases or
decreases the allowance accordingly.  However, if the financial
condition of our customers were to deteriorate, additional allowances may be
required.
  Inventories
  Materials,
supplies and tubulars are valued at the lower of cost or market. The cost is
determined using the first-in, first-out method.
  Proved
Oil and Gas Reserves
  In
accordance with Rule 4-10(a) of SEC Regulation S-X, proved oil and gas reserves
are the estimated quantities of crude 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., average price in preceding 12 months. Prices include
consideration of changes in existing prices provided only by contractual
arrangements, but not on escalation based upon future conditions.
  (i)
              Reservoirs
      are considered proved if economic producibility is supported by either
      actual production or conclusive formation tests. The area of a reservoir
      considered proved includes (A) that portion delineated by drilling and
      defined by gas-oil and/or oil-water contacts, if any; and (B) the
      immediately adjoining portions not yet drilled, but which can be
      reasonably judged as economically productive on the basis of available
      geological and engineering data. In the absence of information on fluid
      contacts, the lowest known structural occurrence of hydrocarbons controls
      the lower proved limit of the
reservoir.
  F-9
 
 (ii)
              Reserves
      which can be produced economically through application of improved
      recovery techniques (such as fluid injection) are included in the “proved”
      classification when successful testing by a pilot project, or the
      operation of an installed program in the reservoir, provides support for
      the engineering analysis on which the project or program was
      based.
 
 (iii)
              Estimates
      of proved reserves do not include the
following:
  (A)
              oil
      that may become available from known reservoirs but is classified
      separately as “indicated additional reserves”;(B)
              crude
      oil, natural gas, and natural gas liquids, the recovery of which is
      subject to reasonable doubt because of uncertainty as to geology,
      reservoir characteristics, or economic
factors;
  (C)
              crude
      oil, natural gas, and natural gas liquids, that may occur in undrilled
      prospects.
 
 Oil
and gas properties
 
 The
Company uses the full cost method of accounting for exploration and development
activities as defined by the Securities and Exchange Commission (“SEC”). Under
this method of accounting, the costs of unsuccessful, as well as successful,
exploration and development activities are capitalized as oil and gas
properties. This includes any internal costs that are directly related to
exploration and development activities but does not include any costs related to
production, general corporate overhead or similar activities.
 
 Gain or
loss on the sale or other disposition of oil and gas properties is not
recognized, unless the gain or loss would significantly alter the relationship
between capitalized costs and proved reserves of oil and natural gas
attributable to a country. The Company has defined a cost center by country.
Currently, all of the Company’s oil and gas properties are located within the
continental United States.
  Properties
and equipment may include costs that are excluded from costs being depreciated
or amortized. Oil and gas costs excluded represent investments in unproved
properties and major development projects in which the Company owns a direct
interest. These unproved property costs include nonproducing leasehold,
geological and geophysical costs associated with leasehold or drilling interests
and exploration drilling costs. All costs excluded are reviewed at least
quarterly to determine if impairment has occurred.
 
 Depletion, depreciation and
amortization - Depletion is provided using the unit-of-production method
based upon estimates of proved oil and natural gas reserves with oil and natural
gas production being converted to a common unit of measure based upon their
relative energy content. Investments in unproved properties and major
development projects are not amortized until proved reserves associated with the
projects can be determined or until impairment occurs. If the results of an
assessment indicate that the properties are impaired, the amount of the
impairment is deducted from the capitalized costs to be amortized.
Once the assessment of unproved properties is complete and when major
development projects are evaluated, the costs previously excluded from
amortization are transferred to the full cost pool and amortization begins. The
amortizable base includes estimated future development costs and where
significant, dismantlement, restoration and abandonment costs, net of estimated
salvage value.
 
 In
arriving at rates under the unit-of-production method, the quantities of
recoverable oil and natural gas reserves are established based on estimates made
by the Company’s geologists and engineers which require significant judgment as
does the projection of future production volumes and levels of future costs,
including future development costs. In addition, considerable judgment is
necessary in determining when unproved properties become impaired and in
determining the existence of proved reserves once a well has been drilled. All
of these judgments may have significant impact on the calculation of depletion
expense. There have been no material changes in the methodology used by the
Company in calculating depletion of oil and gas properties under the full cost
method during the year ended December 31, 2009 and 2008.
 
 Ceiling
Test
  Under the
full cost method of accounting, a ceiling test is performed quarterly. The full
cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule
4-10. The ceiling test determines a limit on the carrying value of oil and gas
properties.  The capitalized costs of proved oil and gas properties,
net of accumulated depreciation, depletion, amortization, and
impairment and the related deferred income taxes, may not exceed the
estimated future net cash flows from proved oil and gas reserves, excluding
future cash outflows associated with settling asset retirement obligations that
have been accrued on the balance sheet, generally using average prices for the
preceding 12 months held flat for the life of production and including the
effect of derivative instruments that qualify as cash flow hedges, if any,
discounted at 10%, net of related tax effects, plus the cost of unevaluated
properties and major development projects excluded from the costs being
amortized. If capitalized costs exceed this limit, the excess is charged to
expense and reflected as additional accumulated depreciation, depletion,
amortization and impairment.
  F-10
 
 In
accordance with SEC Staff Accounting Bulletin ("SAB") No. 103,Update of Codification of Staff
Accounting Bulletins  , derivative instruments qualifying as
cash flow hedges are to be included in the computation of the limitation on
capitalized costs. The Company has not accounted for its derivative contracts as
cash flow hedges. Accordingly, the effect of these derivative contracts has not
been considered in calculating the full cost ceiling limitation as of December
31, 2009 or 2008.
 
 The
Company recorded a non-cash ceiling test impairment of oil and natural gas
properties of $16.6 million during the fourth quarter ended December 31,
2009 as a result of the substantial decline in commodity prices and negative
revisions in the Company's proved undeveloped reserve
quantities.
  Asset
Retirement Obligation
 
 The
Company to recognizes a liability for the present value of all legal obligations
associated with the retirement of tangible, long-lived assets and capitalize an
equal amount as a cost of the asset. The cost of the abandonment obligations,
less estimated salvage values, is included in the computation of depreciation,
depletion and amortization.
 
 Property
 
 Property
is recorded at cost. Improvements or betterments of a permanent nature are
capitalized. Expenditures for maintenance and repairs are charged to expense as
incurred. The cost of assets retired or otherwise disposed of and the related
accumulated depreciation are eliminated from the accounts in the year of
disposal. Gains or losses resulting from property disposals are credited or
charged to operations currently. Depreciation is computed using the
straight-line method over the estimated useful lives ranging from 3 to 15
years.
 
 Goodwill
and Intangible Assets
 
 Goodwill
represents the excess of cost over fair value of net assets acquired through
acquisitions. Goodwill recorded by the Company has not been amortized
and will be evaluated on an annual basis, or sooner if deemed necessary, in
connection with other long-lived assets, for potential impairment.
 
 In
accordance with ASC 360-10 Impairment or Disposal of Long-Lived
Assets(formerly SFAS No. 144,Accounting for the impairment or
Disposal of Long-Lived Assets), the Company evaluates the recoverability
of identifiable intangible assets whenever events or changes in circumstances
indicate that an intangible asset’s carrying amount may not be recoverable. Such
circumstances could include, but are not limited to (1) a significant decrease
in the market value of an asset, (2) a significant adverse change in the extent
or manner in which an asset is used, or (3) an accumulation of costs
significantly in excess of the amount originally expected for the acquisition of
an asset. The Company measures the carrying amount of the asset against the
estimated undiscounted future cash flows associated with it. Should the sum of
the expected future net cash flows be less than the carrying value of the asset
being evaluated, an impairment loss would be recognized. The impairment loss
would be calculated as the amount by which the carrying value of the asset
exceeds its fair value. The fair value is measured based on quoted market
prices, if available. If quoted market prices are not available, the estimate of
fair value is based on various valuation techniques, including the discounted
value of estimated future cash flows. The evaluation of asset impairment
requires the Company to make assumptions about future cash flows over the life
of the asset being evaluated. These assumptions require significant judgment and
actual results may differ from assumed and estimated amounts.
 
 As of
December 31, 2009, the Company recognized $4.4 million of impairment charges
related to the impairment of other intangible assets related to the acquisition
of Maverick based upon the business outlook for Maverick.  In 2008,
the Company recognized $7.8 million of goodwill impairment and $0.2 million
related to impairment of intangible assets.
 
 Stock-Based
Compensation
  The
Company accounts for stock-based compensation in accordance with ASC 718 Compensation—Stock
Compensation (formerly SFAS No. 123(R) Share Based Payment). This
codification addresses all forms of share based payment (“SBP”) awards including
shares issued under employee stock purchase plans, stock options, restricted
stock and stock appreciation rights. Under the codification, SBP awards are
measured at fair value on the awards’ grant date, based on the estimated number
of awards that are expected to vest and results in a charge to
operations
  F-11
 
 Non-Employee Stock Based
Compensation
  The
Company accounts for equity instruments issued to non-employees in accordance
with the provisions of ASC 505-50 Equity-Based Payments to
Non-Employees (formerly SFAS No. 123(R) and Emerging
Issues Task Force (“EITF”) Issue No. 96-18, “Accounting for Equity
Instruments That are Issued to Other Than Employees for Acquiring, or in
Conjunction with Selling, Goods or Services,”) which requires that such equity
instruments be recorded at their fair value on the measurement
date.
 
 Income
Taxes
  Deferred
tax assets and liabilities are recognized for the future tax consequences
attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases. Deferred tax
assets and liabilities are measured using enacted tax rates expected to apply to
taxable income in the years in which those temporary differences are expected to
be recovered or settled. The effect on deferred tax assets and liabilities of a
change in enacted tax rates is recognized in income in the period that includes
the enactment date.
 
 Management
has evaluated and concluded that there are no significant uncertain tax
positions requiring recognition in the Company’s financial statements as of
December 31, 2009.   The Company’s policy is to classify
assessments, if any, for tax related interest as interest expense and penalties
as interest expenses.
 
 Fair Value
Measurements
 
 Effective
January 1, 2008, the Company adopted  ASC 820 formerly SFAS No. 157,(“Fair Value Measurement”)which defines fair value, establishes a framework for measuring fair
value, establishes a fair value hierarchy based on the quality of inputs used to
measure fair value and enhances disclosure requirements for fair value
measurements. The implementation of ASC 820 did not cause a change in the method
of calculating fair value of assets or liabilities, with the exception of
incorporating a measure of the Company’s own nonperformance risk or that of its
counterparties as appropriate, which was not material. The primary impact from
adoption is disclosed in Note 8.
 
 In
conjunction with the adoption of ASC 820 formerly, the Company also adopted SFAS
No. 159,The Fair Value
Option for Financial Assets and Financial Liabilities—Including an Amendment of
FASB Statement No. 115,   effective January 1, 2008.
ASC 820 allows a company the option to value its financial assets and
liabilities, on an instrument by instrument basis, at fair value, and include
the change in fair value of such assets and liabilities in its results of
operations. The Company did not apply the provisions of ASC 820 to any of its
financial assets or liabilities. Accordingly, there was no impact to the
Company's consolidated financial statements resulting from the adoption of ASC
820.
 
 Income
(Loss) Per Share
  Earnings
(loss) per common share amounts (“basic EPS”) were computed by dividing earnings
(loss) by the weighted average number of common shares outstanding for the
period. Earnings per common share amounts, assuming dilution (“diluted EPS”),
were computed by reflecting the potential dilution from the exercise of dilutive
common stock equivalents, such as options or warrants. Due to losses
incurred for the years ending December 31, 2009 and 2008, basic and diluted EPS
are the same.
 
 Environmental
Expenditures
  The
Company is subject to extensive federal, state and local environmental laws and
regulations. These laws regulate the discharge of materials into the environment
and may require the Company to remove or mitigate the environmental effects of
the disposal or release of petroleum or chemical substances at various sites.
Environmental expenditures are expensed or capitalized depending on their future
economic benefit. Expenditures that relate to an existing condition caused by
past operations and that have no future economic benefits are
expensed.
 
 Liabilities
for expenditures of a non-capital nature are recorded when environmental
assessment and/or remediation is probable, and the costs can be reasonably
estimated. Such liabilities are generally undiscounted unless the timing of cash
payments for the liability or component is fixed or reliably
determinable.
  F-12




Derivative Financial
Investments
  From time
to time, the Company may utilize derivative instruments, consisting of puts,
calls, swaps, and price collars, to attempt to reduce its exposure to changes in
commodity prices and interest rates. All derivative instruments are
recognized as assets or liabilities in the balance sheet, measured at fair
value. The accounting for changes in the fair value of a derivative depends on
both the intended purpose and the formal designation of the derivative.
Designation is established at the inception of a derivative, but subsequent
changes to the designation are permitted. The Company has elected not to
designate any of its derivative financial contracts as accounting  or
cash flow hedges and, accordingly, has accounted for these derivative financial
contracts using mark-to-market accounting. Changes in fair value of derivative
instruments which are not designated as cash flow hedges are recorded in other
income (expense) as changes in fair value of commodity
derivatives.
  Contingencies
 
 Certain
conditions may exist as of the date the financial statements are issued, which
may result in a loss to the Company but which will only be resolved when one or
more future events occur or fail to occur. The Company’s management and its
legal counsel assess such contingent liabilities, and such assessment inherently
involves an exercise of judgment. In assessing loss contingencies related to
legal proceedings that are pending against the Company or unasserted claims that
may result in such proceedings, the Company’s legal counsel evaluates the
perceived merits of any legal proceedings or unasserted claims as well as the
perceived merits of the amount of relief sought or expected to be sought
therein.
 
 If the
assessment of a contingency indicates that it is probable that a material loss
has been incurred and the amount of the liability can be estimated, then the
estimated liability would be accrued in the Company’s financial statements. If
the assessment indicates that a potentially material loss contingency is not
probable, but is reasonably possible, or is probable but cannot be estimated,
then the nature of the contingent liability, together with an estimate of the
range of possible loss if determinable and material, would be
disclosed.
 
 Loss
contingencies considered remote are generally not disclosed unless they involve
guarantees, in which case the nature of the guarantee would be
disclosed.
  Real Estate Held for
Development
  The
Company’s real estate held for development was recorded at fair market value
when the Company completed its purchase of the assets of Tandem Energy
Corporation on October 26, 2007 and relates to approximately 41 acres of
undeveloped land located near Tomball, Texas.
 
 Revenue
Recognition and Gas Balancing
  The
Company utilizes the sales method of accounting for oil, natural gas and natural
gas liquids revenues whereby revenues, net of royalties, are recognized as the
production is sold to purchasers and collectibility is assured. The amount of
gas sold may differ from the amount to which the Company is entitled based on
its revenue interests in the properties.
 
 Sales of
natural gas, natural gas liquids and oil are recognized when natural gas,
natural gas liquids and oil have been delivered to a custody transfer point,
persuasive evidence of a sales arrangement exists, the rights and responsibility
of ownership pass to the purchaser upon delivery, collection of revenue from the
sale is reasonably assured, and the sales price is fixed or determinable. We
sell natural gas, natural gas liquids and oil on a monthly basis. Virtually all
of our contracts’ pricing provisions are tied to a market index, with certain
adjustments based on, among other factors, whether a well delivers to a
gathering or transmission line, quality of the natural gas, natural gas liquid
or oil, and prevailing supply and demand conditions, so that the price of the
natural gas, natural gas liquid and oil fluctuates to remain competitive with
other available natural gas, natural gas liquid and oil supplies.
 
 The
Company has elected the entitlements method to account for gas production
imbalances. Gas imbalances occur when we sell more or less than our entitled
ownership percentage of total gas production. Any amount received in excess of
our share is treated as a liability. If we receive less than our entitled share
the underproduction is recorded as a receivable. The Company did not have
any significant gas imbalance positions at December 31, 2009 or
2008.
  F-13
 
 Revenue
Recognition -  Engineering
 
 Revenues
and profits on long-term contracts are recorded under the
percentage-of-completion method.
  Progress
towards completion on fixed price contracts is measured based on physical
completion of individual tasks for all contracts with a value of $5,000 or
greater. For contracts with a value less than $5,000, progress toward completion
is measured based on the ratio of costs incurred to total estimated contract
costs (the cost-to-cost method).
 
 Progress
towards completion on cost-reimbursable contracts is measured based on the ratio
of quantities expended to total forecasted quantities, typically man-hours.
Incentives are also recognized on a percentage-of-completion basis when the
realization of an incentive is assessed as probable. We include flow-through
costs consisting of materials, equipment or subcontractor services as both
operating revenues and cost of operating revenues on cost-reimbursable contracts
where we have overall responsibility as the contractor for the engineering
specifications and procurement or procurement services for such costs. There is
no contract profit impact of flow-through costs as they are included in both
operating revenues and cost of operating revenues at cost.
  Contracts
in process are stated at cost, increased for profits recorded on the completed
effort or decreased for estimated losses, less billings to the customer and
progress payments on uncompleted contracts.
  At any
point, we have numerous contracts in progress, all of which are at various
stages of completion. Accounting for revenues and profits on long-term contracts
requires estimates of total contract costs and estimates of progress toward
completion to determine the extent of revenue and profit recognition. We rely
extensively on estimates to forecast quantities of labor (man-hours), materials
and equipment, the costs for those quantities (including exchange rates), and
the schedule to execute the scope of work including allowances for weather,
labor and civil unrest. In determining the revenues, we must estimate the
percentage-of-completion, the likelihood that the client will pay for the work
performed, and the cash to be received net of any taxes ultimately due or
withheld by the jurisdiction where the work is performed. Projects are reviewed
on an individual basis and the estimates used are tailored to the specific
circumstances. In establishing these estimates, we exercise significant
judgment, and all possible risks cannot be specifically quantified
 
 The
percentage-of-completion method requires that adjustments or re-evaluations to
estimated project revenues and costs, including estimated claim recoveries, be
recognized on a project-to-date cumulative basis, as changes to the estimates
are identified. Revisions to project estimates are made as additional
information becomes known, including information that becomes available
subsequent to the date of the consolidated financial statements up through the
date such consolidated financial statements are filed with the SEC. If the final
estimated profit to complete a long-term contract indicates a loss, provision is
made immediately for the total loss anticipated. Profits are accrued throughout
the life of the project based on the percentage-of-completion. The project life
cycle, including project-specific warranty commitments, if any, can be up to
approximately six years in duration.
 
 The
actual project results can be significantly different from the estimated
results. When adjustments are identified near or at the end of a project, the
full impact of the change in estimate is recognized as a change in the profit on
the contract in that period. This can result in a material impact on our results
for a single reporting period. We review all of our material contracts on a
monthly basis and revise our estimates as appropriate for developments such as
earning project incentive bonuses, incurring or expecting to incur contractual
liquidated damages for performance or schedule issues, providing services and
purchasing third-party materials and equipment at costs differing from those
previously estimated and testing completed facilities, which, in turn,
eliminates or confirms completion and warranty-related costs. Project incentives
are recognized when it is probable they will be earned. Project incentives are
frequently tied to cost, schedule and/or safety targets and, therefore, tend to
be earned late in a project’s life cycle.
 
 Recently
Issued Accounting Pronouncements
 
 In July
2009, the FASB issued new accounting guidance under the Accounting Standards
Codification (ASC) Topic 105 (ASC 105), (formerly, SFAS No. 168, “The FASB Accounting Codification and
the Hierarchy of Generally Accepted Accounting Principles”). Under this
guidance, the ASC became the single source of authoritative U.S. generally
accepted accounting principles (GAAP) recognized by the FASB to be applied by
nongovernmental entities. Rules and interpretive releases of the Securities and
Exchange Commission (SEC) under authority of federal securities laws are also
sources of authoritative GAAP for SEC registrants. On the effective date of this
Statement, the ASC superseded all then-existing non-SEC accounting and reporting
standards. All other non-grandfathered non-SEC accounting literature not
included in the ASC became  non-authoritative.   This Statement
is effective for interim and annual periods ending after September 15, 2009. Our
accounting policies were not affected by the conversion to ASCOther than the
manner in which new accounting guidance is referenced, the adoption of this
guidance did not materially impact the Company’s consolidated financial
statements.
  F-14
  On
January 1, 2009, the Company adopted new accounting guidance under ASC
Topic 805 (ASC 805) on business combinations, (formerly SFAS No. 141 (R),
“Business Combinations” which replaced SFAS No. 141“ Business Combinations”).  ASC 805 retains the fundamental requirements in SFAS 141,
including that the purchase method be used for all business combinations and for
an acquirer to be identified for each business combination. ASC 805 defines the
acquirer as the entity that obtains control of one or more businesses in the
business combination and establishes the acquisition date as the date that the
acquirer achieves control instead of the date that the consideration is
transferred. ASC 805 requires an acquirer in a business combination, including
business combinations achieved in stages (step acquisition), to recognize the
assets acquired, liabilities assumed, and any non-controlling interest in the
acquiree at the acquisition date, to be measured at their fair values as of that
date, with limited exceptions. It also requires the recognition of assets
acquired and liabilities assumed arising from certain contractual contingencies
as of the acquisition date, measured at their acquisition-date fair values.
Additionally, ASC 805 requires acquisition-related costs to be expensed in the
period in which the costs are incurred and the services are received instead of
including such costs as part of the acquisition price. The adoption of ASC 805
did not have a material impact on the Company’s condensed consolidated financial
statements. The provisions of ASC 805 will be applied at such time when
measurement of a business acquisition is required.
  On
January 1, 2009, the Company adopted new accounting guidance under ASC
Topic 820 (ASC 820) on fair value measurements (formerly SFAS No. 157, “
Fair Value Measurements”),  as it relates to nonfinancial assets and nonfinancial
liabilities that are not recognized or disclosed at fair value in the
consolidated financial statements on at least an annual basis. ASC 820 defines
fair value, establishes a framework for measuring fair value in accounting
principles generally accepted in the United States of America (GAAP), and
expands disclosures about fair value measurements. The provisions of ASC 820
apply to other topics that require or permit fair value measurements and are to
be applied prospectively with limited exceptions. The adoption of ASC 820, as it
relates to nonfinancial assets and nonfinancial liabilities had no impact on the
Company’s consolidated financial statements. The provisions of ASC 820 will be
applied at such time as a fair value measurement of a nonfinancial asset or
nonfinancial liability is required, which may result in a fair value that is
materially different than would have been calculated prior to the adoption of
ASC 820.
  On
January 1, 2009, the Company adopted new accounting guidance under ASC
Topic 810 (ASC 810) on consolidation (formerly SFAS No. 160, “Noncontrolling Interests in
Consolidated Financial Statements—an amendment of ARB No. 51”).   ASC 810 establishes accounting and reporting
standards for the noncontrolling interest in a subsidiary and for the
deconsolidation of a subsidiary. This topic defines a noncontrolling interest,
previously called a minority interest, as the portion of equity in a subsidiary
not attributable, directly or indirectly, to a parent. ASC 810 requires, among
other items, that a noncontrolling interest be included in the consolidated
statement of financial position within equity separate from the parent’s equity;
consolidated net income to be reported at amounts inclusive of both the parent’s
and noncontrolling interest’s shares and, separately, the amounts of
consolidated net income attributable to the parent and noncontrolling interest
all on the consolidated statement of operations; and if a subsidiary is
deconsolidated, any retained noncontrolling equity investment in the former
subsidiary be measured at fair value and a gain or loss be recognized in net
income based on such fair value. The presentation and disclosure requirements of
ASC 810 were applied retrospectively. The adoption of ASC 810 had no impact on
the Company’s consolidated financial statements.
  On
January 1, 2009, the Company adopted new accounting guidance under ASC
Topic 815 (ASC 815) on derivatives and hedging (formerly SFAS No. 161, “
Disclosures about Derivative
Instruments and Hedging Activities—an amendment of FASB Statement No. 133”). ASC 815 requires enhanced disclosures about an entity’s derivative
and hedging activities, including (i) how and why an entity uses derivative
instruments, (ii) how derivative instruments and related hedged items are
accounted for under ASC 815, and (iii) how derivative instruments and
related hedged items affect an entity’s financial position, financial
performance, and cash flows. The adoption of ASC 815 had no impact on the
Company’s consolidated financial statements.
  On
January 1, 2009, the Company adopted new accounting guidance under ASC
Topic 350-35 (ASC 350-35) on intangibles (formerly FASB Staff Position (FSP) No.
FAS 142-3, “ Determination of
the Useful Life of Intangible Assets”).  ASC
350-35  identifies the factors that should be considered in developing
renewal or extension assumptions used to determine the useful life of a
recognized intangible asset on goodwill and other intangibles in order to
improve the consistency between the useful life of a recognized intangible asset
and the period of expected cash flows used to measure the fair value of the
asset. The adoption of ASC 350-35 had no impact on the Company’s consolidated
financial statements.
  On
January 1, 2009, the Company adopted new accounting guidance under ASC
Topic 260 (ASC 260) on earnings per share which established that unvested
share-based payment awards that contain nonforfeitable rights to dividends or
dividend equivalents (whether paid or unpaid) are participating securities and
shall be included in the computation of earnings per share pursuant to the
two-class method. The adoption of this guidance did not have a material impact
on the Company’s consolidated financial statements.
  F-15




On
January 1, 2009 the Company adopted new accounting guidance under ASC Topic
815 (ASC 815) on derivatives and hedging which provides that an entity should
use a two step approach to evaluate whether an equity-linked financial
instrument, or embedded feature, is indexed to its own stock, including
evaluating the instrument’s contingent exercise and settlement provisions. It
also clarifies on the impact of foreign currency denominated strike prices and
market-based employee stock option valuations. The adoption of this guidance did
not have a material impact on the Company’s consolidated financial
statements.




In May,
2009 the Company adopted new accounting guidance under ASC Topic 855 (ASC 855)
on subsequent events, (formerly, SFAS No. 165, “Subsequent Events”.ASC 855
establishes general standards of accounting for and disclosure of events that
occur after the balance sheet date but before financial statements are issued or
are available to be issued. ASC 855 was effective for interim or annual periods
ending after June 15, 2009. Management has evaluated subsequent events to
determine if events or transactions occurring through the date at which the
financial statements were available to be issued and has determined that no such
events have occurred that would require adjustment to or disclosure in the
financial statements.




In August
2009, FASB issued Accounting Standards Update 2009-05 which includes amendments
to Subtopic 820-10, Fair Value Measurements and Disclosures—Overall. The update
provides clarification that in circumstances in which a quoted price in an
active market for the identical liability is not available, a reporting entity
is required to measure fair value using one or more of the techniques provided
for in this update. The amendments in this Update clarify that a reporting
entity is not required to include a separate input or adjustment to other inputs
relating to the existence of a restriction that prevents the transfer of the
liability and  also clarifies  that both a quoted price in
an active market for the identical liability at the measurement date and the
quoted price for the identical liability when traded as an asset in an active
market when no adjustments to the quoted price of the asset are required are
Level 1 fair value measurements. The adoption of this standard is not
expected to have a material impact on the Company’s consolidated financial
position or results of operations.




In
December 2008, the SEC issued the final rule,  "Modernization of Oil and Gas
Reporting," which adopts revisions to the SEC's oil and natural gas
reporting disclosure requirements and is effective for annual reports on
Forms 10-K for years ending on or after December 31, 2009. Early
adoption of the new rules is prohibited. The new rules are intended to provide
investors with a more meaningful and comprehensive understanding of oil and
natural gas reserves to help investors evaluate their investments in oil and
natural gas companies. The new rules are also designed to modernize the oil and
natural gas disclosure requirements to align them with current practices and
changes in technology. The new rules include changes to the pricing used to
estimate reserves, the ability to include nontraditional resources in reserves,
the use of new technology for determining reserves and permitting disclosure of
probable and possible reserves.




In June
2008, the FASB ratified Emerging Issue Task Force (“EITF”) 07-5,Determining Whether an Instrument
(or an Embedded Feature) is Indexed to an Entity’s Own
Stock  (“EITF 07-5”). EITF 07-5 provides framework for
determining whether an instrument is indexed to an entity’s own stock. EITF 07-5
is effective for fiscal years beginning after December 15, 2008. The
implementation of EITF 07-5 did not  have a material effect on the
Company’s consolidated financial statements.




Other
accounting standards that have been issued or proposed by the FASB or other
standards-setting bodies that do not require adoption until a future date are
not expected to have a material impact on our consolidated financial statements
upon adoption.  Additional text is needed for this area.




Note
4 — Acquisitions





On April
29, 2008, the Company completed the acquisition of Maverick pursuant to an
agreement and plan of merger entered into on March 18, 2008. Maverick is
a provider of project management, engineering, procurement, and
construction management services to both the public and private sectors,
including the oil and gas business in which the Company is engaged. Maverick is
based in south Texas with offices in Corpus Christi, Victoria, and
Houston.  Maverick provides services to the Company which would
otherwise be procured from third parties.  The aggregate consideration
paid in the merger was $6 million in cash and $5 million to be paid over the
next 5 years pursuant to non-interest bearing cash flow notes, subject to
certain escrows, holdbacks and post-closing adjustments. The cash flow notes are
payable quarterly at the rate of 50% of pre-tax net income, as it is defined in
the merger agreement, generated by the Maverick business on a stand-alone basis
in the preceding quarter. Payment can be accelerated by certain events,
including change in control of the Company.





The
purchase price was subject to adjustment for any change in working capital as
defined in the agreement, between October 31, 2007 and the closing date, as well
as other adjustments associated with changes in indebtedness. The cash flow
notes were reduced by the amount of the working capital post closing adjustment
which was determined by the Company to be $645,596. This amount may be subject
to modification as may be agreed between the parties. At the time the
acquisition was completed, a discount to present value in the amount of
$1,320,404 was recorded and deducted from the cash flow notes as these notes are
non-interest bearing for the initial 5 years of their term. As a result, the net
book value of the notes on April 29, 2008 was $3,034,000.





In
addition, the sellers agreed to satisfy and assume Maverick's bank indebtedness
in the aggregate amount of $4,889,538 consisting of a $2,960,155 revolving line
of credit maturing April 2008, a $1,584,375 term note due April 2011, and
$345,008 oil and gas note due May 2009, using a portion of the cash received by
them at closing. Following the closing, the Company was indebted to the sellers
for these amounts under terms identical to those of the bank loan agreements. On
April 30, 2008, Maverick entered into extension and modification agreements with
the sellers pursuant to which the sellers agreed to defer principal payments of
the $1.6 million term loan for six months and extend the maturity date to April
2013. The sellers also agreed to extend the maturity date of the revolving line
of credit to 2010. In addition, as of December 31, 2008, Maverick was not in
compliance with the debt service coverage ratio contained in the loan
agreements. On August 14, 2008, the sellers waived the Company's obligation to
maintain this ratio through September 30, 2009 (See Note 11).





The
aggregate purchase price for Maverick reflected in the financials, including
legal and other items, was $9,296,118. Our consolidated results of operations
for the year ended December 31, 2008 include the results of operations of
Maverick for the period from April 29, 2008 (the date of acquisition) through
December 31, 2008.





The
following table details the allocation of the purchase price of the Maverick
acquisition (stated in thousands):


F-16




Consideration:Cash,
      including acquisition costs
                  
                  $
                  6,262Cash
      flow notes, net of working capital adjustment and present value
      discount
                  
                  
                  3,034$
                  9,296Recognized
      amount of assets acquired and liabilities assumedAssets
      acquired:Cash
                  
                  $
                  622Accounts
      receivable
                  
                  
                  4,296Other
      current assets
                  
                  
                  157Property
      and equipment
                  
                  
                  1,510Goodwill
                  
                  
                  7,845Amortizable
      intangible assets
                  
                  
                  5,52219,952Liabilities
      assumed:Accounts
      payable
                  
                  
                  (635
                  )Accrued
      expenses
                  
                  
                  (2,341
                  )Deferred
      tax liability
                  
                  
                  (1,933
                  )Term
      notes and revolving line of credit
                  
                  
                  (5,223
                  )Capitalized
      lease obligations
                  
                  
                  (524
                  )(10,656
                  )Total
      net assets acquired
                  
                  $
                  9,296




Unaudited
Pro-Forma Financial Information




The
following unaudited pro forma consolidated results of operations assume that the
Maverick acquisition was completed as of January 1, 2008 for the periods shown
below (stated in thousands, except for per share amount):





Pro Forma Consolidated Results of OperationsRevenue
                                        
                                        
                                        (Loss)
                                          Before
                                          Income
                                          Taxes
                                        
                                        
                                        Net Loss
                                        
                                        
                                        Loss
                                          Per ShareYear
      Ended December 31, 2008
                                        
                                        $
                                        63,828
                                        
                                        
                                        $
                                        (125,192
                                        )
                                        
                                        $
                                        (80,950
                                        )
                                        
                                        $
                                        (3.67
                                        )





The pro
forma combined results are not necessarily indicative of the results that
actually would have occurred if the Maverick acquisition had been completed as
of the beginning of 2008, nor are they necessarily indicative of future
consolidated results. The impact on pro forma results of other transactions
entered into by the Company other than Maverick was immaterial.





The
assets and liabilities related to the foregoing acquisitions were recorded in
the Company’s consolidated balance sheet at their estimated fair values at the
date of acquisition.





Goodwill
and intangible assets acquired were evaluated during the fourth quarter of 2009
and 2008 for potential impairment.  Based on its evaluation as of
December 31, 2009 and 2008, the Company recognized $4.4 million in impairment
charges of intangible assets for 2009, and $7.8 million of goodwill impairment
charges, as well as an additional charge of $0.2 million related to the
impairment of amortizable intangible assets related to the acquisition of
Maverick in 2008.


F-17




PLATINUM
ENERGY RESOURCES, INC. AND SUBSIDIARIES


NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the Years Ended December 31, 2009 and 2008




Note
5 - Oil and Gas Properties




The
following table sets forth the Company’s costs incurred in oil and gas property
acquisition, exploration and development activities for years ended December 31,
2009 and 2008 (stated in thousands):





2009
                            
                            
                            2008Beginning
      balance:
                            
                            $
                            204,372
                            
                            
                            $
                            170,572Acquisition
      of propertiesProved
                            
                            
                            -
                            
                            
                            
                            7,489Unproved
                            
                            
                            -
                            
                            
                            
                            1,000Adjustment
      to purchase price of oil and gas properties
                            
                            
                            -
                            
                            
                            
                            4,640Exploration
      costs
                            
                            
                            -
                            
                            
                            
                            1,130Revision
      to Asset Retirement Obligation
                            
                            
                            2,339Development
      costs
                            
                            
                            1,580
                            
                            
                            
                            19,541Balance
      at December 31:
                            
                            $
                            208,291
                            
                            
                            $
                            204,372




The
following table sets forth the Company’s capitalized costs relating to oil and
gas producing activities at December 31, 2009 (stated in
thousands):




Costs
      being amortized
                    
                    $
                    208,291Costs
      not being amortized
                    
                    
                    0208,291Accumulated
      depletion and impairment (1)
                    
                    
                    (164,497
                    )Net
      capitalized costs at December 31, 2009
                    
                    $
                    43,794




(1)
Includes ceiling limitation impairment charges of $16.6 and $130.1 million
incurred during the years ended December 31, 2009 and 2008,
respectively.





Note
6 – Inventory





The
following table describes the content of our inventory during each of the years
ended December 31, 2009 and 2008 (stated in


thousands):




2009
                    
                    
                    2008Equipment
                    
                    $
                    411
                    
                    
                    $
                    436Balance
      at December 31:
                    
                    $
                    411
                    
                    
                    $
                    436




Note
7 – Derivative Financial Instruments




The
Company engages in price risk management activities from time to
time.  We utilize derivative instruments, consisting of swaps, floors
and collars, to attempt to reduce our exposure to changes in commodity
prices. All derivative instruments are recognized as assets or
liabilities in the balance sheet, measured at fair value. The accounting for
changes in the fair value of a derivative depends on both the intended purpose
and the formal designation of the derivative. Designation is established at the
inception of a derivative, but subsequent changes to the designation are
permitted. We have elected not to designate any of our derivative financial
contracts as accounting hedges and, accordingly, account for these derivative
financial contracts using mark-to-market accounting. Changes in fair value of
derivative instruments which are not designated as cash flow hedges are recorded
in other income (expense) as changes in fair value of derivatives. The
obligations under the derivatives contracts are collateralized by the same
assets that collateralize the Senior Credit Facility, and the contracts are
cross-defaulted to the Senior Credit Facility.  Substantially all of
the derivative financial instruments are collateral for the Senior Credit
Facility.


F-18




While the
use of these arrangements may limit the Company's ability to benefit from
increases in the price of oil and natural gas, it is also intended to reduce the
Company's potential exposure to significant price declines. The Company had
approximately 44% of its 2009 crude oil production and 0% of its gas production
covered by derivative contracts. These derivative transactions are generally
placed with major financial institutions that the Company believes are
financially stable; however, in light of the recent global financial crisis,
there can be no assurance of the foregoing.





For the
years ended December 31, 2009 and 2008, the Company included in other
income realized and unrealized losses related to its derivative contracts as
follows (stated in thousands):




2009
                  
                  
                  2008Crude
      oil derivative realized settlements
                  
                  $
                  1,164
                  
                  
                  
                  (5,256
                  )Crude
      oil derivative change in unrealized gains (losses)
                  
                  
                  (13,690
                  )
                  
                  
                  22,565Gain
      (loss) on derivatives
                  
                  $
                  (12,526
                  )
                  
                  
                  17,309




Presented
below is a summary of the Company’s crude oil derivative financial contracts at
December 31, 2009:





Period Ending
                      December 31,
                    
                    Instrument Type
                    
                    Total Volumes
                      (BBL)
                    
                    
                    Contract
                      Price
                    
                    
                    Fair Value Asset
                      (stated in thousands)2010
                    
                    Swaps
                    
                    
                    120,000
                    
                    
                    
                    95.50
                    
                    
                    
                    1,585Puts
                    
                    
                    110,000
                    
                    
                    
                    75.00
                    
                    
                    
                    2,0112011
                    
                    Swaps
                    
                    
                    120,000
                    
                    
                    
                    95.25
                    
                    
                    
                    1,098Puts
                    
                    
                    120,000
                    
                    
                    
                    80.00
                    
                    
                    
                    1,1952012
                    
                    Swaps
                    
                    
                    120,000
                    
                    
                    
                    95.00
                    
                    
                    
                    896Total
      fair value
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    $
                    6,785





Note
8 – Fair Value Measurements





As
defined in ASC 820, fair value is the price that would be received to sell an
asset or paid to transfer a liability in an orderly transaction between market
participants at the measurement date (exit price). In determining the fair value
of its derivative contracts the Company evaluates its counterparty and third
party service provider valuations and adjusts for credit risk when appropriate,
ASC 820 establishes a framework for measuring fair value and expands disclosure
about fair value measurements. The statement requires fair value measurements be
classified and disclosed in one of the following categories:





Level
      1:
            Unadjusted
      quoted prices in active markets that are accessible at the measurement
      date for identical, unrestricted assets or liabilities. The Company
      considers active markets as those in which transactions for the assets or
      liabilities occur in sufficient frequency and volume to provide pricing
      information on an ongoing basis.





Level
      2:
            Quoted
      prices in markets that are not active, or inputs which are observable,
      either directly or indirectly, for substantially the full term of the
      asset or liability. This category includes those derivative instruments
      that are valued using observable market data. Substantially all of these
      inputs are observable in the marketplace throughout the full term of the
      derivative instrument, can be derived from observable data, or supported
      by observable levels at which transactions are executed in the
      marketplace.


F-19




Level
      3:
            Measured
      based on prices or valuation models that require inputs that are both
      significant to the fair value measurement and less observable from
      objective sources (i.e., supported by little or no market activity). Level
      3 instruments can include derivative instruments where the Company does
      not have sufficient corroborating market evidence of significant inputs to
      the valuation model to support classifying these instruments as Level 1 or
      Level 2.




As
required by ASC 815, financial assets and liabilities are classified based on
the lowest level of input that is significant to the fair value measurement. The
Company’s assessment of the significance of a particular input to the fair value
measurement requires judgment, and may affect the valuation of the fair value of
assets and liabilities and their placement within the fair value hierarchy
levels.





The
following table presents information about the Company’s assets and liabilities
that are measured at fair value on a recurring basis as of December 31, 2009,
and indicates the fair value hierarchy of the valuation techniques utilized by
the Company to determine such fair value.  The fair value of
derivative financial instruments is determined based on counterparties’
valuation models that utilize market-corroborated inputs.





As of December 31, 2009(in thousands)Level 1
                      
                      Level 2
                      
                      Level 3
                      
                      TotalOil
      and natural gas derivatives
                      
                      —
                      
                      $
                      6,785
                      
                      —
                      
                      $
                      6,785




As of December 31, 2008(in thousands)Level 1
                      
                      Level 2
                      
                      Level 3
                      
                      TotalOil
      and natural gas derivatives
                      
                      —
                      
                      $
                      20,531
                      
                      —
                      
                      $
                      20,531





The
determination of the fair values above incorporates various factors required
under ASC 815. These factors include the impact of our nonperformance risk and
the credit standing of the counterparties involved in the Company’s derivative
contracts.





Gains and
losses (realized and unrealized) included in earnings for the year ended
December 31, 2009 are reported in other income on the Consolidated Statement of
Operations.




During
periods of market disruption, including periods of volatile oil and natural gas
prices, rapid credit contraction or illiquidity, it may be difficult to value
certain of the Company’s derivative instruments if trading becomes less frequent
and/or market data becomes less observable. There may be certain asset classes
that were in active markets with observable data that become illiquid due to the
current financial environment. In such cases, derivative instruments may fall to
Level 3 and thus require more subjectivity and management judgment. As such,
valuations may include inputs and assumptions that are less observable or
require greater estimation as well as valuation methods which are more
sophisticated or require greater estimation thereby resulting in valuations with
less certainty. Further, rapidly changing commodity and unprecedented credit and
equity market conditions could materially impact the valuation of derivative
instruments as reported within our consolidated financial statements and the
period-to-period changes in value could vary significantly. Decreases in value
may have a material adverse effect on our results of operations or financial
condition.





Cash and
cash equivalents, receivables, accounts payable and accrued liabilities were
each estimated to have a fair value approximating the carrying amount due to the
short maturity of those instruments.  Indebtedness under the Company’s
secured revolving bank credit facility and loans related to the acquisition of
Maverick were estimated to have a fair value approximating the carrying amount
since the interest rate is generally market sensitive.





Note 9 – Intangible
Assets





In 2009
and 2008, we realized a non-cash impairment of intangible assets of $4.4 million
and $8 million, respectively, based upon an analysis of the net profits of the
underlying business.




The
following table describes changes in intangible assets during each of the years
ended December 31, 2009 and 2008 (stated in thousands):


F-20




2009
                
                
                2008Intangible
      assets at January 1
                
                $
                5,061
                
                
                $
                376Additions
      during period
                
                
                —
                
                
                
                13,367Amortization
      and Impairments
                
                
                (5,061)
                
                
                
                (8,682)Intangible
      assets at December 31,
                
                $
                —
                
                
                $
                5,061




Note 10 – Commitments and
Contingencies




Consulting
Agreement




Effective
with the Tandem acquisition on October 26, 2007, the Company entered into a
consulting agreement with Mr. Lance Duncan, for consulting services, including
investigation and evaluation of possible future acquisitions for the Company.
Under the terms of the consulting agreement, the Company agreed to issue to Mr.
Duncan a total of 714,286 shares of the Company’s restricted common stock as
consideration over the period of service. These shares are fixed in number
(except for stock splits or other recapitalizations). These shares were to be
issued in semi-annual installments over the eighteen month term of the agreement
beginning with the closing of the Tandem acquisition.




On
October 26, 2007, the first installment of 178,572 of irrevocable shares was
issued to Mr. Duncan.  These shares were valued at $1,250,000 which
was charged to operations during the year ended December 31,
2007.  The Company was required to issue the remaining 535,714 shares
of its common stock in 2008. The Company did not issue these shares due to a
dispute between the Company and Mr. Duncan.  In February 2010, all
claims between the Company and Mr. Duncan were resolved and the balance of the
shares was distributed accordingly, See Note 18.




Employment
Agreements




The
Company is obligated for minimum salaries pursuant to all executive and
non-employment agreements. Excluding the cost of employee health benefits,
payments of bonuses that are either discretionary or contingent upon performance
criteria and stock based compensation arrangement the total obligation under
these agreements is $162,000, all of which is payable during the year ended
December 31, 2010.




Operating
leases





The
Company leases its general office space and equipment under non-cancellable
operating leases that expire through August 2012. The total obligation under
existing operating leases is as follows:





For
      the Year Ending December 31:2010
                      
                      $
                      9642011
                      
                      
                      9662012
                      
                      
                      539$
                      2,469




Capitalized
leases




Maverick
leases office equipment and vehicles under capital lease agreements.
Depreciation expense for capital leases is included with depreciation on
property.  The cost, net of accumulated depreciation of capital leases
included in property and equipment was $342,318 and $499,667 at December 31,
2009 and 2008, respectively. The total minimum lease payments under capitalized
leases together with the present value of the net minimum lease payments was
$492,512 and $467,908 at December 31, 2009 and 2008,
respectively.  The effective interest rate on capitalized leases
ranges from 5% - 31%.




Note
11 - Long-Term Debt and Capital Lease Obligations




The
following table sets forth the Company’s long-term debt position as of December
31 (stated in thousands):


F-21




2009
                    
                    
                    
                    2008Oil
      and gas revolving line of credit
                    (a)
                    
                    $
                    13,029
                    
                    
                    $
                    12,009Notes
      payable - acquisitions
                    (b)
                    
                    
                    3,422
                    
                    
                    
                    3,537Revolving
      line of credit to former shareholders – Maverick
                    (c)(f)
                    
                    
                    2,917
                    
                    
                    
                    3,249Term
      note to former shareholders - Maverick
                    (d)(f)
                    
                    
                    252
                    
                    
                    
                    281Second
      term note to former shareholders - Maverick
                    (e)(f)
                    
                    
                    1,404
                    
                    
                    
                    1,474Notes
      payable to third party – Maverick
                    (g)
                    
                    
                    -
                    
                    
                    
                    305Other
                    
                    
                    
                    0
                    
                    
                    
                    46821,024
                    
                    
                    $
                    21,323Less:
      Current maturities
                    
                    
                    
                    17,602
                    
                    
                    
                    13,404Long-term
      debt
                    
                    
                    
                    3,422
                    
                    
                    $
                    7,919




(a)   On March
14, 2008, Tandem and PER Gulf Coast, Inc. (“Borrower”) which are wholly-owned
subsidiaries of the Company, entered into a Senior Secured Revolving Credit
Facility (“Senior Credit Facility”) with Bank of Texas. The Senior Credit
Facility provided for a revolving credit facility up to the lesser of the
borrowing base and $100 million. The initial borrowing base was set at $35
million.  The facility is collateralized by substantially all of the
Company’s proved oil & gas assets as well as substantially all of the
derivative financial instruments discussed in Note 7.  The Senior
Credit Facility originally matured on March 14, 2012, at which time all
outstanding borrowings would have to be repaid.





Under the
terms of the Senior Credit Facility, the Borrower must maintain certain
financial ratios, must repay any amounts due in excess of the borrowing base,
and may not declare any dividends or enter into any transactions resulting in a
change in control, without the bank’s consent.  A financial covenant under
the Senior Credit Facility requires us to maintain a ratio of indebtedness to
cash flow of no more than 3 to 1. The Company, as the parent company, is not a
co-borrower or guarantor of the line, and transfers from the Borrower to the
parent company are limited to (i) $1 million per fiscal year to the parent for
management fees, and (ii) the repayment of up to $2 million per fiscal year in
subordinate indebtedness owed to the parent.





In June
2009, the borrowing base was reduced to $15 million and the Senior Credit
Facility was amended to change the interest rate provisions. Under the amended
loan agreement, outstanding debt bears interest at LIBOR, plus a margin, which
varies according to the ratio of the Borrower’s outstanding borrowings against
the defined borrowing base, ranging from 2.5% to 3.50 %, provided the interest
rate does not fall below a floor rate of 4.5% per annum.  In addition,
the Borrower is obligated to the bank for a monthly fee of any unused portion of
the line of credit at the rate of 0.50% per annum.  The maturity date
was also modified to June 1, 2010.  As of December 31, 2009, the $13
million outstanding under the revolving line of credit was bearing interest
at the bank’s base rate, which was 4.5 %.





On June
1, 2010, the Senior Credit Facility matured and the Borrower has not repaid the
amounts due under the Senior Credit Facility and is currently in
default.  Additionally, the Borrower is in default of the financial
reporting covenant, requiring the timely reporting of financial information, due
no more than 90 days after the end of the fiscal period.  The Borrower
is also in default of quarterly financial covenant 9.1(b), which requires us to
maintain a ratio of indebtedness to cash flow of no more than 3 to 1. As of June
30, 2010, the Borrowers have not received any notice of foreclosure on the
assets collateralizing the Senior Credit Facility.





(b)Maverick-As part of the
acquisition of Maverick the Company agreed to pay $5 million over 5 years
pursuant to non-interest bearing cash flow notes, subject to certain escrows,
holdbacks and post-closing adjustments. The cash flow notes are payable
quarterly at the rate of 50% of pre-tax net income generated by the Maverick
business on a stand-alone basis in the preceding quarter. At the five year
anniversary of the cash flow notes, if the aggregate quarterly payments made
pursuant to the formula described in the preceding sentence are less than $5
million, any shortfall will be converted into a one year term note, bearing
interest at the prime rate plus 2% per annum, with principal and interest due in
equal monthly installments over the twelve month
term.    The cash flow notes can be accelerated by certain
events, including change in control of Maverick.  It is the Company’s
position no event in 2009 or 2008 triggered such an event.





The
purchase price was subject to adjustment for any change in working capital as
defined in the agreement, between October 31, 2007 and the closing date, as well
as other adjustments associated with changes in indebtedness. The cash flow
notes were reduced by the amount of the working capital post closing adjustment
which was determined by the Company to be $645,596. This amount may be subject
to modification as may be agreed between the parties. At the time the
acquisition was completed, a discount to present value in the amount of
$1,320,404 was recorded and deducted from the cash flow notes as these notes are
non-interest bearing for the initial 5 years of their term. As a result, the net
carrying value of the notes on April 29, 2008 was $3,034,000.  During
the years ended December 31, 2009 and 2008, accretion of the discount related to
the Cash Flow Notes of $238,650 and $149,783, respectively, was recognized as
interest expense.


F-22


On April
16, 2009, the Company received a written notice of acceleration from Robert L.
Kovar Services, LLC, as the stockholder representative, claiming that the
Company failed to make timely mandatory prepayments in the amount of $110,381
due under the terms of the Cash Flow Notes.  The Cash Flow Notes are
payable quarterly at the rate of 50% of pre-tax net income, as defined in the
merger agreement, generated by the Maverick business on a stand-alone basis in
the preceding quarter. The Company has not reclassified the long-term portion of
these Cash Flow Notes included in Notes payable – acquisitions to current
liabilities.  It is the Company’s position that Maverick generated a
pretax loss during the period April 29, 2008 through December 31, 2009, and as
such the Company was not obligated to make a mandatory payment to the note
holders.   Generally Accepted Accounting Principles in the United
States of America (“GAAP”) require intangible assets to be amortized over their
useful lives.  In addition, goodwill and intangible assets are
evaluated annually for potential impairment.  The pretax income as
calculated by Robert L. Kovar Services, LLC, as the stockholder representative,
did not include amortization expense or impairment charges related to intangible
assets and goodwill in accordance with GAAP.  These Cash Flow Notes
are now the subject of litigation between Kovar and the Company as further
described in Note 16.




Pleasanton- In connection with the Pleasanton acquisition, the Company entered into
a settlement agreement for $1,000,000 in order to secure clear title to the
properties acquired, of which it paid $450,000 cash and issued a note for the
balance in the amount of $550,000. The note bears interest at 12% per annum, and
is subject to monthly payments beginning June 1, 2008 of an amount equal to 1⁄2 of
the net proceeds from production attributable to the Company’s interest in the
purchased leasehold or $30,000, whichever is greater, until the note is paid in
full. The current and long-term portion of the note at December 31, 2009 and
2008 was $20,015 and $306,034, respectively.




(c) $3,250,000 revolving line
of credit, payable to the Maverick former shareholders in monthly interest
payments at prime plus .25%, principal and unpaid interest due at maturity in
September 2010.   No payments were made in 2009.  The interest
rate applicable under this agreement during December 31, 2009 was
3.5%.





(d) Term note, payable to
the Maverick former shareholders in monthly principal and interest payments of
$10,280 with interest at prime plus .75%, unpaid principal and interest due at
maturity in May 2009. No payments were made in 2009.





(e) Second term note, payable
to the Maverick former shareholders in monthly interest payments at prime plus
..50% beginning in April 2008 and beginning in October 2008, principal payments
of $23,390 plus interest until maturity in April 2013. No payments were made in
2009.  The interest rate applicable under this agreement during
December 31, 2009 was 3.75%.





(f) On April 29, 2009,
Maverick received a notice of acceleration (the “Acceleration Letter”) with
respect to the revolving line of credit, the term note and the second term note
payable to the Maverick former shareholders (the”Maverick Notes”) and governed
by a Loan Agreement and related Security Agreement originally dated April 30,
2005 and April 29, 2005, respectively.  The Acceleration Letter
alleges that Maverick failed to comply with certain covenants under the terms of
the Loan Agreement and that Maverick failed to make payments due under the
Notes.  The outstanding principal, accrued interest and late charges
alleged to be owed by Maverick in the Acceleration Letter total
$4,659,227.  The Acceleration Letter also contends that interest
continues to accrue at the default rate of 18% per annum.  In a
separate letter, dated May 1, 2009, Robert L. Kovar Services, LLC, as the
stockholder representative for the sellers, purported to terminate the revolving
credit facility under the Loan Agreement and demanded turnover of all collateral
securing indebtedness under the Loan Agreement, including the Maverick Notes. No
payments were made in 2009.




The
Company and Maverick have asserted claims in litigation against the holders of
the Maverick Notes, Robert L. Kovar Services, LLC, Robert L. Kovar,
individually, and others.  The litigation is in its early stages and,
accordingly, the Company cannot predict the outcome of these
matters.  See Note 16.  The Company is not accruing interest
on the Maverick Notes while the claims are resolved.




(g) Note payable to a third
party in monthly installments, with interest paid at 12%, principal due at
maturity in September 2009, collateralized by the guaranty of the Maverick
former majority stockholder and substantially all assets. This note was paid off
in its entirety in September 2009.




Annual
maturities of indebtedness at December 31, 2009 are as follows (stated in
thousands):





For
      the Year Ending December 31:2010
                      
                      $
                      17,6022011
                      
                      
                      —2012
                      
                      
                      —2013
                      
                      $
                      3,422Thereafter
                      
                      
                      —$
                      21,024





The
following is a schedule of future minimum lease payments under capitalized
leases together with the present value of the net minimum lease payments at
December 31, 2009 (stated in thousands):


F-23




For
      the Year Ending December 31:2010
                      
                      $
                      1812011
                      
                      
                      1232012
                      
                      
                      46Total
      minimum lease payments
                      
                      
                      350Less:  Amount
      representing interest
                      
                      
                      (38
                      )Current
      value of minimum lease payments
                      
                      
                      312Less:  Current
      maturities
                      
                      
                      (201
                      )$
                      111





The
effective interest rate on capitalized leases ranges from 5% - 31%.




Note 12 – Equity and Stock
Plans




Public Offering
2005 — On October 28, 2005, the Company sold to the public
14,400,000 units (“Units”) at an offering price of $8.00 per Unit. Each Unit
consisted of one share of the Company’s common stock, $0.0001 par value, and one
Redeemable Common Stock Purchase Warrant (“Warrants”). Of the 14,400,000 common
shares issued in the offering, 2,878,560 shares were initially not recorded in
stockholders equity.  Commensurate with the closing of the Tandem
acquisition, 1,076,355 common shares were reclassified to stockholders equity
and holders of 1,802,205 shares elected to redeem their shares for
cash.  Each Warrant entitled the holder to purchase from the Company
one share of common stock at an exercise price of $6.00 and expired on October
23, 2009. Separate trading of the common stock and Warrants comprising the Units
commenced on or about December 9, 2005.  None of the warrants were
exercised and as of December 31, 2009, there were no outstanding warrants to
purchase the Company’s common stock.





Share
Based Compensation— On March 20, 2006, the Board of
Directors of the Company approved a 2006 Long-Term Incentive Plan. Pursuant to
the plan, the Company may grant up to 4 million incentive and non-qualified
stock options, stock appreciation rights, performance units, restricted stock
awards and performance bonuses, or collectively, awards, to officers and key
employees. In addition, the plan authorizes the grant of non-qualified stock
options and restricted stock awards to directors and to any independent
contractors and consultants.  Options to purchase the Company’s common
stock have been granted to officers, employees, non-employee directors and
certain key individuals. Options generally become exercisable in 20% to
25% cumulative annual increments beginning with the date of grant and
expire at the end of ten years. As of December 31, 2009 a total of 151,000 stock
option grants have been issued under the plan with an estimated fair value at
grant date of  $235,192.  During the years ended December
31, 2009 and 2008 the Company recorded stock-based compensation attributable to
the options of $75,297 and $36,332, respectively. No portion of this expense has
been capitalized.




At
December 31, 2009, unrecognized compensation expense related to non-vested
options totaled $137,487, which will be recognized in accordance with the
vesting provisions of the underlying grants over the following 4
years.  Outstanding options had an intrinsic value of $1,920 at
December 31, 2009.




Summaries
of share-based awards transactions follow:





WeightedNumber
                  
                  
                  Averageof Share
                    Options
                  
                  
                  Exercise
                    PriceOutstanding
      at December 31, 2007
                  
                  
                  -
                  
                  
                  
                  -Granted
                  
                  
                  140,000
                  
                  
                  
                  3.86Outstanding
      at December 31, 2008
                  
                  
                  140,000
                  
                  
                  
                  3.86Granted
                  
                  
                  32,000
                  
                  
                  
                  0.61Exercised
                  
                  
                  —
                  
                  
                  
                  —Canceled
                  
                  
                  (21,000)
                  
                  
                  
                  1.39Outstanding
      at December 31, 2009
                  
                  
                  151,000
                  
                  
                  $
                  3.52


F-24


Fair
value of share options was estimated at the date of grant using the
Black-Scholes option pricing model. Certain assumptions were used in determining
the fair value of share options using this model. The Company calculated the
estimated volatility by averaging the historical volatility of the Company’s
stock and the historic volatility of a selected group of comparable peer
companies. The risk-free interest rate is based on observed U.S. Treasury rates
at date of grant, appropriate for the expected lives of the options. The
expected life of options was determined based on the method provided in Staff
Accounting Bulletin 107, as we do not have an adequate exercise history to
determine the average life for the options with the characteristics of those
granted.  Weighted averages of the assumptions used in the
Black-Scholes option pricing model were as follows for grants of options in the
year ended December 31, 2009 and 2008:





2009
                                
                                
                                2008Risk-free
      interest rates
                                
                                
                                3.85
                                %
                                
                                
                                3.9
                                %Dividend
      yield
                                
                                
                                0
                                %
                                
                                
                                0
                                %Volatility
                                
                                
                                107.5
                                %
                                
                                
                                68.8
                                %Expected
      life
                                6.3
      year
                                
                                
                                6.4
      yearsWeighted
      average grant date fair value
                                
                                $
                                0.61
                                
                                
                                $
                                2.39Total
      options granted
                                
                                
                                32,000
                                
                                
                                
                                140,000Total
      weighted average fair value of options granted
                                
                                $
                                15,360
                                
                                
                                $
                                335,000





Computation of
Earnings per Share—The Company accounts for earnings per share in
accordance with ASC 260 Earnings Per Share, which
establishes the requirements for presenting earnings per share ("EPS"). ASC 260
requires the presentation of "basic" and "diluted" EPS on the face of the
statement of operations. Basic EPS amounts are calculated using the weighted
average number of common shares outstanding during each period. Diluted EPS
assumes the exercise of all stock options, warrants and convertible securities
having exercise prices less than the average market price of the common stock
during the periods, using the treasury stock method. When a loss from continuing
operations exists, as in the periods presented, potential common shares are
excluded in the computation of diluted EPS because their inclusion would result
in an anti-dilutive effect on per share amounts.





Reconciliations
between the numerators and denominators of the basic and diluted EPS
computations for each period are as follows (in thousands, except per share
data):





Year Ended December 31,2009
                        
                        
                        2008Numerator:Net
      (loss) applicable to common stockholders
                        
                        $
                        (32,019,035
                        )
                        
                        $
                        (80,819,595)Denominator:Denominator
      for basic (loss) per share — weighted-average shares
      outstanding
                        
                        
                        22,070,762
                        
                        
                        
                        22,070,762Effect
      of potentially dilutive common shares:Warrants
                        
                        
                        —
                        
                        
                        
                        —Employee
      and director stock options
                        
                        
                        —
                        
                        
                        
                        —Denominator
      for diluted (loss) per share — weighted-average shares outstanding
      and assumed conversions
                        
                        
                        22,070,762
                        
                        
                        
                        22,070,762Basic
      earnings (loss) per share
                        
                        $
                        (1.45
                        )
                        
                        $
                        (3.66)Diluted
      earnings (loss) per share
                        
                        $
                        (1.45
                        )
                        
                        $
                        (3.66)





The
Company has determined that the warrants contained in the units sold in its
initial public offering would be anti -dilutive and thus excluded the effects of
the warrants for the year ended December 31, 2008.   For the
years ended December 31, 2009 and 2008, options to purchase 151,000 and 140,000
shares of common stock were not considered in calculating diluted earnings per
share because the effect would be anti-dilutive.





Note
13 – Asset Retirement Obligation


For the
Company, asset retirement obligations (“ARO”) represent the systematic, monthly
accretion and depreciation of future abandonment costs of tangible assets such
as wells, service assets, and other facilities. The fair value of a
liability for an asset’s retirement obligation is recorded in the period in
which it is incurred if a reasonable estimate of fair value can be made, and
that the corresponding cost is capitalized as part of the carrying amount of the
related long-lived asset. The liability is accreted to its then present value
each period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, an adjustment is made to the full cost pool, with no gain or loss
recognized, unless the adjustment would significantly alter the relationship
between capitalized costs and proved reserves. The Company’s policy with respect
to ARO is to assign depleted wells to a salvager for the assumption of
abandonment obligations before the wells have reached their economic limits; the
Company has estimated its future ARO obligation with respect to its operations.
The ARO assets, which are carried on the balance sheet as part of the full cost
pool, have been included in our amortization base for the purposes of
calculating depreciation, depletion and amortization expense.


F-25




The
following table describes changes in our asset retirement liability during each
of the years ended December 31, 2009 and 2008. The ARO liability in the
table below includes amounts classified as long-term at December 31, 2009
and 2008 (stated in thousands):




2009
                
                
                2008ARO
      liability at January 1
                
                $
                4,537
                
                
                $
                3,577Abandonments
      during period
                
                
                (24)
                
                
                
                (3)Accretion
      expense
                
                
                326
                
                
                
                266Obligations
      arising during period
                
                
                11
                
                
                
                697Changes
      in estimates
                
                
                2,389
                
                
                
                -ARO
      liability at December 31
                
                $
                7,239
                
                
                $
                4,537




At December 31, 2009, the Company
reviewed its abandonment cost estimates and determined an upward revision in
those estimates was required,  In accordance with the provisions of
ASC 410, the Company recorded an additional liability of $2,389,000 at December
31, 2009, with a corresponding increase to the carrying value of the Company’s
oil and gas properties.




Note
14 – Income Taxes




The
Company utilizes an asset liability approach to determine the extent of any
deferred income taxes.  This method gives consideration to the future
tax consequences associated with differences between financial statement and tax
basis of assets and liabilities.




A
reconciliation of the federal statutory income tax rate to the Company’s
effective tax rate as reported is as follows:




2009
                
                
                2008Taxes
      at federal statutory rate
                
                
                (34.5
                )%
                
                
                (34.0
                )%State
      income tax net of federal benefit
                
                
                (1.0
                )%
                
                
                (1.0
                )
      %Non
      taxable income - interest
                
                
                -
                
                
                
                -Non
      deductible expenses (principally goodwill impairment)
                
                
                (2.3
                )%
                
                
                2.3
                %Increase
      and true-up of valuation allowance
                
                
                13.4
                %
                
                
                (2.6
                )
      %Effective
      income tax rate
                
                
                (24.4
                )%
                
                
                (35.3
                )
      %




Significant
components of deferred tax assets and liabilities at December 31, 2009 and 2008
are as follows:





2009
                
                
                2008Deferred
      expenses - start-up costs
                
                $
                537
                
                
                $
                537Other
      (includes asset retirement obligation)
                
                
                1,612
                
                
                
                1,499Allowance
      for bad debts
                
                
                79
                
                
                
                -Net
      operating loss carry-forward
                
                
                9,737
                
                
                
                6,061Depletion
      carry-forward
                
                
                1,924
                
                
                
                1,924Less:
      valuation allowance
                
                
                (8,735)
                
                
                
                (3,045
                )5,154
                
                
                
                6,976Other
                
                
                -
                
                
                
                (1,633
                )Commodity
      derivatives
                
                
                (1,839)
                
                
                
                (6,223
                )Difference
      between carrying value of property and equipment and tax
    basis
                
                
                (3,315)
                
                
                
                (9,579
                )Net
      deferred tax assets (liabilities)
                
                $
                -
                
                
                $
                (10,459
                )


F-26




At
December 31, 2009, the Company had, subject to the limitations discussed below,
$28 million of net operating loss carryforwards for U.S. purposes. These loss
carryforwards will expire from 2026 through 2029 if not utilized.




In
addition to any Section 382 limitation for change of control uncertainties exist
as to the future utilization of the operating loss carryforwards under the
criteria set forth under ASC 140, Income Taxes. Therefore, the Company has
established a valuation allowance of $8.7 million in deferred tax assets at
December 31, 2009 and $3 million at December 31, 2008.




There are
no uncertain income tax positions required to be recorded. The Company files
income tax returns in the U.S. (federal and state jurisdictions). Tax years 2006
to 2009 remain open for all jurisdictions. The Company’s accounting policy is to
recognize interest and penalties, if any, related to unrecognized tax benefits
as income tax expense. The Company does not have an accrued liability for
interest and penalties at December 31, 2009.




Note
15 - Segment Information




With the
consummation of the Maverick acquisition, the Company considers itself to be in
two lines of business - (i) as an independent oil and gas exploration and
production company and (ii) as an engineering services company.




(i)
            The
      Company sells substantially all of its crude oil production under
      short-term contracts based on prices quoted on the New York Mercantile
      Exchange (“NYMEX”) for spot West Texas Intermediate contracts, adjusted by
      agreed-upon increases or decreases which vary by grade of crude oil. The
      majority of the Company’s natural gas production is sold under short-term
      contracts based on pricing formulas which are generally market responsive.
      From time to time, the Company may also sell a portion of the gas
      production under short-term contracts at fixed prices. For the year ended
      December 31, 2009, three customers accounted for approximately 47%,
      16% and 11% of the Company’s crude oil and natural gas
      revenues.  The Company believes that the loss of any of its oil
      and gas purchasers would not have a material adverse effect on its results
      of operations due to the availability of other
  purchasers.





(ii)
            Maverick
      provides engineering and construction services primarily for three types
      of clients: (1) upstream oil & gas, domestic oil and gas producers and
      pipeline companies; (2) industrial, petrochemical and refining plants; and
      (3) infrastructure, private and public sectors, including state
      municipalities, cities, and port authorities. Maverick operates out of
      facilities headquartered in Victoria, Texas and operates primarily in
      Texas. The types of services provided include project management,
      engineering, procurement, and construction management services to both the
      public and private sectors, including the oil and gas business in which
      the Company is engaged. For the year ended December 31, 2009, one customer
      accounted for approximately 11% of the Company’s service
      revenues.




The
following table presents selected financial information for the Company’s
operating segments (stated in thousands):




Exploration
                
                
                
                
                
                
                
                
                ConsolidatedFor the Year Ended December 31, 2009:
                
                and Production
                
                
                Engineering
                
                
                Parent
                
                
                TotalRevenues
                
                $
                17,174
                
                
                $
                18,597
                
                
                $
                -
                
                
                $
                35,771Intersegment
      revenues
                
                
                -
                
                
                
                (77
                )
                
                
                -
                
                
                
                (77
                )Total
      revenues
                
                $
                17,174
                
                
                $
                18,520
                
                
                $
                -
                
                
                $
                35,694Income
      (loss) before income taxes
                
                $
                (25,881
                )
                
                $
                (7,747
                )
                
                $
                (8,716
                )
                
                $
                (42,344
                )As
      of December 31, 2009:Total
      assets
                
                $
                55,350
                
                
                $
                5,581
                
                
                $
                3,441
                
                
                $
                64,372




Exploration
                
                
                
                
                
                
                
                
                ConsolidatedFor the Year Ended December 31, 2008:
                
                and Production
                
                
                Engineering
                
                
                Parent
                
                
                TotalRevenues
                
                $
                34,849
                
                
                $
                20,529
                
                
                $
                -
                
                
                $
                55,378Intersegment
      revenues
                
                
                -
                
                
                
                (2,195
                )
                
                
                -
                
                
                
                (2,195
                )Total
      revenues
                
                $
                34,849
                
                
                $
                18,334
                
                
                $
                -
                
                
                $
                53,183Income
      (loss) before income taxes
                
                $
                (111,765
                )
                
                $
                (8,959
                )
                
                $
                (4,265
                )
                
                $
                (124,990
                )As
      of December 31, 2009:Total
      assets
                
                $
                82,390
                
                
                $
                12,141
                
                
                $
                10,346
                
                
                $
                104,877




Note
16 — Litigation





From time
to time, the Company is party to certain legal actions and claims arising in the
ordinary course of business. While the outcome of these events cannot be
predicted with certainty, management does not anticipate these matters to have a
materially adverse effect on the financial position or results of operations of
the Company.


F-27




Exxon
Litigation




On January
16th, 2008, Exxon Mobil Corporation filed a petition in the 270 th
District Court of Harris County, Texas, naming us as a defendant along with TEC
and a third party, Merenco Realty, Inc., demanding environmental remediation of
certain properties in Tomball, Texas. In 1996, pursuant to an assignment
agreement, Exxon Mobil sold certain oil and gas leasehold interests and real
estate interests in Tomball, Texas to TEC’s predecessor in interest, Merit
Energy Corporation. In 1999, TEC assigned its 50% undivided interest in one of
the tracts in the acquired property to Merenco, an affiliate of TEC, owned 50%
by our Chairman of the Board, Tim Culp. In October 2007, the Texas Railroad
Commission notified Exxon Mobil of an environmental site assessment alleging
soil and groundwater contamination for a site in the area of Tomball, Texas.
Exxon Mobil believes that the site is one which was sold to TEC and claims that
TEC is obligated to remediate the site under the assignment agreement. Exxon
Mobil has requested that the court declare the defendants obligated to restore
and remediate the properties and has requested any actual damages arising from
breach and attorneys’ fees. We believe that Exxon Mobil’s claim that TEC is
responsible for any remediation of such site is without merit and we intend to
vigorously defend ourselves against this claim. However, no assurance can be
given that we will prevail in this matter. We acquired substantially all the
assets and liabilities of TEC in the TEC acquisition. Merenco was not acquired
by us in the TEC acquisition and our Chairman, Tim Culp, continues to have a 50%
ownership interest in Merenco.




Hyman
Litigation





On
November 11, 2008, Mr. Hyman, a former employee of KD Resources, filed a claim
against KD Resources and Platinum Energy stating that he was discharged from KD
Resources in violation of the Sarbanes-Oxley Act of 2002, Section 806,
Protection for Employees of Publicly Traded Companies Who Provide Evidence of
Fraud.  In December, 2008, the Department of Labor (“DOL”) dismissed
the complaint as not being timely filed.  On or about January 8, 2009, Mr.
Hyman appealed the ruling of the DOL. On January 16, 2009, the DOL filed an
Order to Show Cause whereby Mr. Hyman was ordered to show why his case should
not have been dismissed.  On February 14, 2009, Mr. Hyman filed his
response to the Order to Show Cause stating that he failed to file within the
required time because he was engaged in negotiations with the Respondents. 
On March 18, 2009, the Department of Labor dismissed Mr. Hyman’s claim for
failure to file within the 90-day filing period.   Mr. Hyman filed a
Petition for Review of the Decision and Order Dismissing Complaint issued March
18, 2009.  A Notice of the Appeal was filed April 10, 2009 which was
granted.  On March 31, 2010, in a split decision, the Administrative Review
Board Reversed the decision of the Administrative Law Judge and Remanded the
case for further consideration.  It is the Company's contention that Mr.
Hyman did not file his complaint within the time required by Sarbanes-Oxley, and
in any case, was never an employee of Platinum Energy Resources or any of its
subsidiaries; as such we are not liable for any issues between Mr. Hyman and his
employer, KD Resources.  It is the Company's further contention that the
only reason Platinum Energy is listed in this action is because it is a public
company and Mr. Hyman needs a public company in order to obtain his status under
the Sarbanes-Oxley Act.





Kovar
Litigation





On
December 3, 2008, Robert Kovar filed suit against Platinum alleging that he
“Resigned for Good Reason” according to his employment contract.  Mr.
Kovar is seeking a Declaration Judgment that he had “Good Reason” to resign his
employment at Platinum Energy and Maverick Engineering.  Mr. Kovar is
also requesting payment of the severance package, accelerated vesting of options
and accelerated payment of the Cash Flow Note (as described in the Platinum
Energy, Maverick Engineering Merger Agreement and Note 11 above) as described in
his employment agreement, plus attorney fees and court costs.  It is
our contention that Mr. Kovar resigned his position without good reason and is
therefore, not entitled to severance or accelerated vesting of
options.  It is our additional conviction that the Cash Flow Note has
been cancelled and that Platinum Energy in no longer obligated to make any
payments there under, pursuant to the terms of Mr. Kovar’s employment agreement.
We are currently in the discovery phase of this matter.  We believe
that Mr. Kovar’s claim that he resigned with “Good Reason” is without merit and
we intend to vigorously defend ourselves against this claim.




On April
16, 2009, the Company received a written notice of acceleration from Robert L.
Kovar Services, LLC, as the stockholder representative, claiming that the
Company failed to make timely mandatory prepayments in the amount of $110,381
due under the terms of the Cash Flow Notes.  On April 29, 2009,
Maverick received a notice of acceleration (the “Acceleration Letter”) with
respect to the Maverick Notes governed by a Loan Agreement and related Security
Agreement originally dated April 30, 2005 and April 29, 2005, respectively. The
Acceleration Letter alleges that Maverick failed to comply with certain
covenants under the terms of the Loan Agreement and that Maverick failed to make
payments due under the Maverick Notes. The outstanding principal, accrued
interest and late charges alleged to be owed by Maverick in the Acceleration
Letter total $4,659,227. The Acceleration Letter also contends that interest
continues to accrue at the default rate of 18% per annum. In a separate letter,
dated May 1, 2009, Robert L. Kovar Services, LLC, as the stockholder
representative for the sellers, purported to terminate the revolving credit
facility under the Loan Agreement and demanded turnover of all collateral
securing indebtedness under the Loan Agreement, including the Maverick Notes.
The Company and Maverick have asserted claims in litigation against the holders
of the Maverick Notes, Robert L. Kovar Services, LLC, Robert L. Kovar,
individually, and others. This litigation is in its early stages and,
accordingly, the Company cannot predict the outcome of these
matters.


F-28




On May 3.
2009, Platinum and Maverick Engineering. Inc. filed suit against Robert L.
Kovar Services. LLC (“RKS”), Robert L. Kovar (“Kovar”), Rick J. Guerra
(“Guerra”), and Walker, Keeling, & Carroll. L.L.P. (“WKC”)
collectively (the Defendants”) alleging, among other things, a
suit for declaratory judgment asking the court to declare that Platinum and
Maverick are entitled to indemnification from the former Maverick
stockholders, including Guerra and Kovar, for any damages they suffer as a
result of a default on any note contained in the Maverick and PermSUB
Merger Agreement. In addition, Platinum and Maverick have asked the Court
to declare that WKC has breached the merger agreement by not stepping down
as the Merger Escrow Agent.  Platinum and Maverick
have also sued to recover costs of court and attorneys’ fees.





In
October, 2009, Platinum and Maverick Engineering filed a Second Amended Petition
with the following Causes of Action against the Defendants:  Kovar
fraudulently induced Platinum to enter into the Merger Agreement; Common-Law
Fraud; Statutory Fraud; Breach of Fiduciary Duty; Tortious Interference with
Merger Agreement; Civil Conspiracy; and Breach of Contract.   As
this case is still in the discovery phase of litigation, at this time, it is
impossible for us to provide an informed assessment of the likelihood of a
favorable or unfavorable outcome in this case.





Citgo
Litigation





On
October 14, 2009, Maverick Engineering filed suit in Harris County against CITGO
Refining & Chemical Company, LP for Breach of Contract.  According
to the Petition, Maverick provided engineering services to CITGO and CITGO has
refused to pay for those services.  Maverick is suing for $357,538.16
plus damages, costs, attorney fees, interest, and other relief.  While
Maverick has performed all terms, conditions, and covenants required under its
contract with CITGO, it is too early in this litigation to be able to predict
the outcome.





Meier
Litigation





On
October 20, 2009, Lisa Meier filed suit for breach of her employment
contract.  According to the Petition, Ms. Meier resigned for “good
cause” and she is seeking severance pay.  On June 10, 2009, Ms. Meier
delivered to the Board of Directors of Platinum energy Resources, her second
notice of intent to resign for “Good Reason.” Ms. Meier’s first notice was
submitted on October 23, 2008, less than three months after entering into her
employment agreement, and subsequently withdrawn.





The Board
of Directors accepted Ms. Meier’s resignation, but stated that “good reason” did
not exist.  This matter is currently is the early phase of
litigation.  We believe that Ms. Meier’s claims are without merit and
we intend to vigorously defend ourselves against these
claims.




Note
17 - Benefit Plan





Prior to
its acquisition by the Company, Maverick adopted a defined contribution plan
under Section 401(k) of the Internal Revenue Code for the benefit of all
employees who have met certain length-of-service requirements. Under this plan,
Maverick employees may elect to make contributions pursuant to a salary
reduction agreement. Each year, Maverick may make a matching contribution to the
plan on behalf of the participating employees. Employer contributions to the
plan are discretionary. For the years ended December 31, 2009 and 2008 employer
contributions charged to operations totaled approximately $180,000 and $432,000,
respectively.





Note
18 – Subsequent Events




In
October 2007, the Company entered into a consulting agreement with Mr. Lance
Duncan, for consulting services, including investigation and evaluation of
possible future acquisitions for the Company. Under the terms of the consulting
agreement, the Company agreed to issue to Mr. Duncan a total of 714,286 shares
of the Company’s restricted common stock as consideration over the period of
service. These shares are fixed in number (except for stock splits or other
recapitalizations). These shares are to be issued in semi-annual installments
over the eighteen month term of the agreement beginning with the closing of the
Tandem acquisition.  The first installment was issued to Mr. Duncan in
October 2007.  The remaining 535,714 shares of restricted common stock
where to be issued in 2008.  However, the Company did not issue these
shares due to a dispute between the Company and Mr. Duncan.  In February
2010, all claims between the Company and Mr. Duncan were resolved and the
balance of the shares was distributed from the Company’s’ treasury stock
holdings. The Company accrued a liability of $300,000 to settle with Mr.
Duncan.




In May
2010, the Company paid down $1.5 million on the Bank of Texas Senior Credit
Facility.  In June 2010 the Company liquidated $1.65 million in
derivative contracts, the proceeds from which were used to pay down an
additional $2 million on the Senior Credit Facility.


F-29




Note
19 – Oil and Gas Reserve Information (Unaudited)





In
December 2008, the Securities and Exchange Commission (“SEC”) announced
revisions to its regulations on oil and gas reporting. In January 2010, the
Financial Accounting Standards Board issued an accounting standards update which
was intended to harmonize the accounting literature with the SEC’s new
regulations. The revised regulations were applied in estimating and reporting
our reserves as of December 31, 2009.




The
estimates of proved oil and gas reserves utilized in the preparation of the
consolidated financial statements were prepared by Williamson Petroleum
Consultants (Williamson), independent petroleum engineers.




Future
cash inflows for 2009 were computed by applying average price for the year to
the year-end quantities of proved reserves. The 2009 average price for the year
was calculated using the 12-month period prior to the ending date of the period
covered by the report, determined as an unweighted arithmetic average of the
first-day-of-the-month price for each month within such
period.  Future cash inflows for 2008 were computed by the year end
spot price to the year-end quantities of proved reserves.  The
difference in average versus year end pricing for 2009 versus 2008,
respectively, is reflected as a component of change in prices in the table
below.  Future development, abandonment and production costs were
computed by estimating the expenditures to be incurred in developing and
producing proved oil and gas reserves at the end of the year, based on year-end
costs. Future income taxes were computed by applying statutory tax rates to the
estimated net pre-tax cash flows after consideration of tax basis and tax
credits and carryforwards. All of the Company’s reserves are located in the
United States. For information about the Company’s results of operations from
oil and gas producing activities, see the consolidated statements of
operations.




There are
numerous uncertainties inherent in estimating quantities of proved reserves,
projecting future rates of production and projecting the timing of development
expenditures, including many factors beyond our control.  The reserve
data represents only estimates.  Reservoir engineering is a subjective
process of estimating underground accumulations of natural gas and oil that
cannot be measured in an exact manner.  The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretations and judgment.  All estimates of proved
reserves are determined according to the rules prescribed by the
SEC.  These rules indicate that the standard of “reasonable certainty”
be applied to the proved reserve estimates.  This concept of
reasonable certainty implies that as more technical data becomes available, a
positive, or upward, revision is more likely that a negative, or downward,
revision.  Estimates are subject to revision based upon a number of
factors, including reservoir performance, prices, economic conditions and
government restrictions.  In addition, results of drilling, testing
and production subsequent to the date of an estimate may justify revision of
that estimate.  Reserve estimates are often different from the
quantities of natural gas and oil that are ultimately recovered.  The
meaningfulness of reserve estimates is highly dependent on the accuracy of the
assumptions on which they were based.  In general, the volume of
production from natural and oil properties we own declines as reserves are
depleted.  Except to the extent we conduct successful development
activities or acquire additional properties containing proved reserves, or both,
our proved reserves will decline as reserves are
produced.    There have been no major discoveries or other
events, favorable or adverse, that may be considered to have caused a
significant change in the estimated proved reserves since December 31,
2009.  The Company emphasizes that reserve estimates are inherently
imprecise. Accordingly, the estimates are expected to change as more current
information becomes available. In addition, a portion of the Company’s proved
reserves are proved developed non-producing and proved undeveloped, which
increases the imprecision inherent in estimating reserves which may ultimately
be produced.





Estimated Quantities of Proved Oil
and Gas Reserves





The
following table sets forth proved oil and gas reserves together with the changes
therein , proved developed reserves and proved undeveloped reserves for the
years ended December 31, 2009 and 2008 (in thousands).  Units of oil
are in thousands of barrels (MBbls) and units of gas are in millions of cubic
feet (MMcf).  Gas is converted to barrels of oil equivalent (MBoe)
using a ratio of six Mcf of gas per Bbl of oil


F-30




2009
                
                
                2008Oil
                
                
                Gas
                
                
                MBoe
                
                
                Oil
                
                
                Gas
                
                
                MBoeProved
      reserves:Beginning
      of period
                
                
                2,310
                
                
                
                16,042
                
                
                
                4,983
                
                
                
                6,526
                
                
                
                21,812
                
                
                
                10,161Revisions
                
                
                138
                
                
                
                (1,655
                )
                
                
                (138
                )
                
                
                (4,084
                )
                
                
                (5,647
                )
                
                
                (5,025
                )Extensions
      and discoveries
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                120
                
                
                
                —
                
                
                
                120Sales
      of minerals-in-place
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                —Purchases
      of minerals-in-place
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                29
                
                
                
                688
                
                
                
                144Production
                
                
                (260
                )
                
                
                (710
                )
                
                
                (378
                )
                
                
                (281
                )
                
                
                (811
                )
                
                
                (417
                )End
      of period
                
                
                2,188
                
                
                
                13,677
                
                
                
                4,467
                
                
                
                2,310
                
                
                
                16,042
                
                
                
                4,983Proved
      developed reserves:Beginning
      of period
                
                
                916
                
                
                
                5,333
                
                
                
                1,805
                
                
                
                2,639
                
                
                
                6,497
                
                
                
                3,722End
      of period
                
                
                1,287
                
                
                
                3,912
                
                
                
                1,939
                
                
                
                916
                
                
                
                5,333
                
                
                
                1,805Proved
      undeveloped reserves:Beginning
      of period
                
                
                1,394
                
                
                
                10,709
                
                
                
                3,178
                
                
                
                3,887
                
                
                
                15,315
                
                
                
                6,439End
      of period
                
                
                901
                
                
                
                9,765
                
                
                
                2,528
                
                
                
                1,394
                
                
                
                10,709
                
                
                
                3,178





Development
of proved undeveloped (PUD) reserves  has fluctuated since our
acquisition of the assets of Tandem Energy Corporation in 2007.




Our major
PUD projects are in our Tomball field, which account for 8,003 MMcf of our
proved undeveloped reserves as of December 31, 2009.  We acquired
these reserves in our 2007 acquisition of Tandem Energy
Corporation.  Since that time we have engaged in limited development
of these reserves.  Our plan is to generate and secure sufficient
funding to complete development of these reserves over the next two
years.





Some
PUD reserves located in the Ballard and USM fields were drilled during the first
half of 2008 when oil prices reached over $100 per barrel.  Many of
the remaining PUD reserves in those fields, as well as the Ira field, were
dropped from the 2008 year end reserve report due primarily to the subsequent
decline in oil prices late in 2008.





During
2009, several factors have delayed the development of the Company’s remaining
PUD reserves; namely, low commodity prices during the 1st quarter 2009, the
subsequent transfer of operations from Midland, Texas to Houston, and
constraints on capital related to the Company’s credit facility.




Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas
Reserves





The
standardized measure of discounted future net cash flows, in management’s
opinion, should be examined with caution. The basis for this table is the
reserve studies prepared by independent petroleum engineering consultants, which
contain imprecise estimates of quantities and rates of production of reserves.
Revisions of previous year estimates can have a significant impact on these
results. Also, exploration costs in one year may lead to significant discoveries
in later years and may significantly change previous estimates of proved
reserves and their valuation. Therefore, the standardized measure of discounted
future net cash flow is not necessarily indicative of the fair value of the
Company’s proved oil and natural gas properties.




Future
income tax expense was computed by applying statutory rates less the effects of
tax credits for each period presented to the difference between pre-tax net cash
flows relating to the Company’s proved reserves and the tax basis of proved
properties and available net operating loss and percentage depletion
carryovers.





The
following table sets forth standardized measure of discounted future net cash
flows (stated in thousands) relating to proved reserves for the years ended
December 31, 2009 and 2008:




2009
                
                
                2008(in thousands)Future
      cash inflows
                
                $
                168,370
                
                
                $
                181,725Future
      costs:Production
                
                
                (72,821
                )
                
                
                (82,806
                )Development
                
                
                (23,755
                )
                
                
                (26,396
                )Income
      taxes
                
                
                (17,008
                )
                
                
                —Future
      net cash inflows
                
                
                54,786
                
                
                
                72,52310%
      discount factor
                
                
                (29,280
                )
                
                
                (28,177
                )Standardized
      measure of discounted net cash flows
                
                $
                25,506
                
                
                $
                44,346


F-31




Summary
of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves


The
following table sets forth the changes in the future net cash inflows discounted
at 10% per annum (stated in thousands):


2009
                
                
                2008Beginning
      of period
                
                $
                44,346
                
                
                $
                171,022Sales
      of oil and natural gas produced, net of production costs
                
                
                (7,518
                )
                
                
                (21,145
                )Extensions
      and discoveries
                
                
                -
                
                
                
                1,050Net
      change of prices and production costs
                
                
                15,727
                
                
                
                (163,695
                )Change
      in future development costs
                
                
                (1,998
                )
                
                
                29,520Previous
      estimated development costs incurred
                
                
                1,546Revisions
      of previous quantity estimates
                
                
                (17,630
                )
                
                
                (90,603
                )Accretion
      of discount
                
                
                4,435
                
                
                
                26,412Change
      in income taxes
                
                
                (13,402
                )
                
                
                89,576Purchases
      of reserves in place
                
                
                -
                
                
                
                2,209End
      of period
                
                $
                25,506
                
                
                $
                44,346





Results
of Operations for Oil and Gas Producing Activities




Under
full-cost accounting rules, the Company reviews the carrying value of its proved
oil and gas properties each quarter. Under these rules, capitalized costs of
proved oil and gas properties, net of accumulated DD&A and deferred income
taxes, may not exceed the present value of estimated future net cash flows from
proved oil and gas reserves, discounted at 10%, plus the lower of cost or fair
value of unproved properties included in the costs being amortized, net of
related tax effects (the “ceiling”). These rules generally require pricing
future oil and gas production at the unescalated oil and gas prices at the end
of each fiscal quarter and require a write-down if the “ceiling” is
exceeded.





The
Company recorded a non-cash ceiling test impairment of oil and natural gas
properties of $16.2 million ($5.5 million, net of tax) and $130.1 million
($84.6 million, net of tax) during the years ended December 31, 2009
and 2008, respectively, as a result of declines in commodity prices and negative
revisions in the Company's proved reserve quantities.





The
estimated present value of future cash flows relating to proved reserves is
extremely sensitive to prices used at any measurement period. The prices used
for each commodity for the year ended December 31, 2009 and 2008, as adjusted,
were as follows:




As of December 31,
                
                Oil
                
                
                Gas2009
      (average price)
                
                $
                56.64
                
                
                $
                3.252008
      end of year price
                
                $
                41.92
                
                
                $
                5.29





The
following table sets forth the results of operations for producing activities
for the years ended December 31, 2009 and 2008 (stated in
thousands):





2009
                  
                  
                  2008Revenues
                  
                  $
                  17,173
                  
                  
                  $
                  34,157Production
      costs
                  
                  
                  (9,656
                  )
                  
                  
                  (13,973
                  )Depreciation,
      depletion, amortization and impairment (1)
                  
                  
                  (21,997
                  )
                  
                  
                  (141,349
                  )Income
      tax benefit
                  
                  
                  -
                  
                  
                  
                  44,178Results
      of operations from producing activities (excluding corporate overhead and
      interest costs)
                  
                  $
                  (14,480
                  )
                  
                  $
                  (76,987
                  )




(1)
            Includes
      ceiling limitation impairment charge of $16.2 million and $130.1 million
      for years ended December 31, 2009 and 2008,
  respectively.


F-32




Capitalized
Costs and Accumulated Depreciation, Depletion and Amortization
($000’s)


2009
                    
                    
                    2008Proved
      oil and gas properties
                    
                    $
                    206,033
                    
                    
                    $
                    204,372Unproved
      oil and gas properties
                    
                    
                    2,258
                    
                    
                    
                    2,258Accumulated
      depreciation, depletion and impairment
                    
                    
                    (164,497
                    )
                    
                    
                    (142,500
                    )$
                    43,794
                    
                    
                    $
                    61,873




Costs
Incurred in Oil and Gas Property Acquisition, Exploration and Development
Activities ($000’s)





2009
                  
                  
                  2008Acquisition
      of propertiesProved
                  
                  
                  -
                  
                  
                  
                  12,129Unproved
                  
                  
                  -
                  
                  
                  
                  1,000Exploration
      costs
                  
                  
                  -
                  
                  
                  
                  1,130Development
      costs
                  
                  
                  1,580
                  
                  
                  
                  19,541Balance
      at December 31:
                  
                  
                  1,580
                  
                  
                  $
                  33,800


F-33