PLATINUM ENERGY RESOURCES INC - FORM 10-K

Attached files

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EX-23 - PLATINUM ENERGY RESOURCES INC	v189379_ex23.htm
EX-31.2 - PLATINUM ENERGY RESOURCES INC	v189379_ex31-2.htm
EX-31.1 - PLATINUM ENERGY RESOURCES INC	v189379_ex31-1.htm
EX-32.1 - PLATINUM ENERGY RESOURCES INC	v189379_ex32-1.htm
EX-32.2 - PLATINUM ENERGY RESOURCES INC	v189379_ex32-2.htm
EX-99.1 - PLATINUM ENERGY RESOURCES INC	v189379_ex99-1.htm

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 1000
Houston, 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.

Yes o No x

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

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

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). Yes o No 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 filer o Accelerated filer o Non-accelerated filer (Do not check if a smaller reporting company) o Smaller reporting company x

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

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, 2010
Common Stock, $0.0001 par value per share		22,606,475 shares

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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		146
Ball – Bird		-		1,282		214
Choate – Batson		142		-		142
Ira		59		-		59
Lothian		179		119		198
Tomball		624		912		776
USM – Ft. Stockton		83		214		118
Other		66		1,302		284
Proved Undeveloped:
Ball – Bird		-		1,761		294
Choate – Batson		27		-		27
Ira		875		-		875
Tomball		-		8,005		1,334
TOTAL 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:

	Proved Developed Producing		Proved Developed Non- producing		Proved Undeveloped		Total Proved

Crude oil (MBbl)		1,235		51		902		2,188
Natural gas (MMcf)		3,308		605		9,766		13,679
Barrel of oil equivalent (MBoe)		1,786		152		2,530		4,468
Undiscounted future net revenue (before CapEx)	$	32,777	$	3,495	$	59,277	$	95,549
Estimated future capital expenditures		-	$	447	$	23,308	$	23,755
Undiscounted future net revenue (net of CapEx)	$	32,777	$	3,048	$	35,969	$	71,794
Discounted 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 Wells
	Gross						Net
	Productive		Dry		Total		Productive		Dry		Total
2009		1.0		0.0		1.0		0.5		0.0		0.5
2008		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.

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 Period
	2009		2008
Oil and Gas Production Data:
Oil (MBls)		259.6		281.4
Gas (MMcfs)		709.6		811.1
Total (MBoe)		377.9		416.6
Average Realized Prices (a):
Oil ($/Bbl)	$	56.49	$	97.14
Gas ($/Mcf)	$	3.54	$	8.40
Average 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.

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.

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

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				Warrants
	High			Low			High		Low		High		Low
2009:
Fourth Quarter	$	n/a	1	$	n/a	1	$	0.73	$	0.30	$	0.025	$	0.004
Third Quarter	$	n/a	1	$	n/a	1	$	0.75	$	0.33	$	0.060	$	0.007
Second Quarter	$	n/a	1	$	n/a	1	$	0.75	$	0.35	$	0.058	$	0.003
First Quarter	$	0.51		$	0.51		$	0.78	$	0.42	$	0.050	$	0.003
2008:
Fourth Quarter	$	3.00		$	0.55		$	1.80	$	0.53	$	0.35	$	0.02
Third Quarter	$	6.39		$	3.00		$	4.70	$	1.65	$	0.96	$	0.20
Second Quarter	$	6.39		$	5.50		$	5.15	$	4.40	$	1.10	$	0.84
First 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.

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.

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.

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.

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, 2007
Production
Oil (Bls)		259,591		281,441		38,684
Gas (Mcf)		709,557		811,086		125,849
Boe (Bls)		377,850		416,622		59,659

Average Prices
Oil ($/Bbl)	$	56.49	$	97.14	$	85.24
Gas ($/Mcf)	$	3.54	$	8.40	$	8.03

Average Lifting Cost per Boe (1)	$	25.56	$	33.54	$	29.77

(1) Includes severance and ad valorem taxes.

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.

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	$	14,057,199
Payment of TEC indebtedness, including interest		41,704,635
Other payments		5,887,911
		61,649,745
Available cash to Platinum upon consummation of the TEC acquisition		50,650,255
Total	$	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.

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.

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;

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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.

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.

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.

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;

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.

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.

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.

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.

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 Class
Tim G. Culp	51	Chairman of the Board	2007	Class C
Al Rahmani	63	Interim Chief Executive Officer and Director	2009	Class A
William C. Glass	39	President and Director	2005	Class B
Bernard Albert Lang	73	Director	2008	Class A
Marc Berzins	70	Director	2009	Class A

(1) As of May 14, 2010.

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.

Marc Berzins has 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.

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		142,478
Chairman of the Board(3)	2008	188,760							12,000		200,760

Al Rahmani	2009	182,533							16,309		198,842
Chief Executive Officer

Barry Kostiner	2009	81,400									81,400
Former Chief Executive Officer(4)	2008	188,760	2,750								191,510

Stephen Chalupka	2009	8,215									8,215
Former Chief Financial Officer(8)

Mickey Cunningham	2009	201,940							10,500		212,440
Former Chief Financial Officer(7)

Lisa Meier	2009	81,400									81,400
Former Chief Financial Officer and Treasurer(5)	2008	93,750	2,750		12,104				5,000		113,604

Robert L. Kovar	2008	125,510			19,494						145,004
Former 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.

(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.

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.

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 Awards

Name

Number of

Securities

Underlying

Unexercised

Options #

Exercisable

Number of

Securities

Underlying

Unexercised

Options #

Unexercisable

Option

Exercise

Price ($)

Option

Expiration

Date

Lisa Meier (1)

50,000

3.90

August 11, 2018

Robert 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		21,250
William Glass		-		42,750
Marc 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.

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	%

*	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 plans

Equity compensation plans approved by security holders		151,000	$	4.00		3,828,000
Equity compensation plans not approved by security holders		N/A		N/A		0
Total		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		2008
Audit fees	$	264,000	$	307,000
Audit-related fees	$	-	$	105,500
Tax 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.

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.

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 Description
2.1		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)

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)

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

31.2		Section 302 Certification of Principal Financial Officer

32.1		Section 906 Certification of Principal Executive Officer

32.2		Section 906 Certification of Principal Financial Officer

99.1		Report of Williamson Petroleum Consultants, Inc., Petroleum Consultants

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 RAHMANI
	Al Rahmani
	Interim 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, Director
Al Rahmani		(Principal Executive Officer)

/s/ AL RAHMANI		Principal Accounting Officer
Al Rahmani		(Principal Financial and Accounting Officer)

/s/ TIM G. CULP		Chairman of the Board
Tim G. Culp

/s/ WILLIAM C. GLASS		President, Director
William C. Glass

/s/ BERTRAM A. LANG		Director
Bertram A. Lang

/s/ Marc Berzins		Director
Marc Berzins

PLATINUM ENERGY RESOURCES, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Reports of Independent Registered Public Accounting Firms		F-2

Consolidated Balance Sheets as of December 31, 2009 and 2008		F-4

Consolidated Statements of Operations for the Years Ended December 31, 2009 and 2008		F-5

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2009 and 2008		F-6

Consolidated Statements of Cash Flows for the Years Ended December 31, 2009 and 2008		F-7

Notes 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.

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			2008

ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	2,941,939		$	3,668,092
Accounts receivable, net of $224,392 and $164,392 allowance for doubtful accounts as of December 31, 2009 and 2008, respectively
Oil and gas sales		2,079,201			1,629,931
Service		2,961,546			5,255,041
Inventory		410,791			436,477
Fair value of commodity derivatives - current		3,595,144			1,968,186
Prepaid expenses and other current assets		610,989			747,225

Total current assets		12,599,610			13,704,952

Property and equipment, at cost
Oil and gas properties, full cost method		208,291,206			204,372,437
Other property and equipment		5,565,746			5,492,072
Less accumulated depreciation, depletion, amortization and impairment		(167,973,630	)		(145,016,531	)
Property and equipment, net		45,883,322			64,847,978

Other assets
Intangible assets, net		-			5,061,066
Fair value of commodity derivatives		3,190,294			18,562,702
Real estate held for development		2,700,000			2,700,000

Total assets	$	64,373,226		$	104,876,698

LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
Accounts payable
Trade service	$	2,154,188		$	2,551,808
Oil and gas		920,818			1,115,114
Accrued liabilities and other		4,033,935			4,437,995
Income taxes payable		328,324			119,770
Current Portion of Asset Retirement Obligation		812,670			-
Current maturities of long-term debt, capital lease obligations and notes payable		17,802,925			13,403,731
Total current liabilities		26,052,860			21,628,418

Long-term debt and capital lease obligations, net of current portion	$	111,315			4,687,423
Notes payable - acquisitions		3,422,433			3,231,959
Other accrued liabilities		119,735			148,458
Asset retirement obligation	$	6,426,424			4,537,243
Deferred income taxes		-			10,459,000
Total long-term liabilities	$	10,079,907			23,064,083

COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred 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			2,407
Additional paid-in capital		155,175,771			155,100,474
Accumulated 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			60,184,197

Total 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			2008

Revenues
Oil and gas sales	$	17,173,709		$	34,156,974
Service revenues		18,520,324			19,025,921
		35,694,033			53,182,895
Costs and expenses
Lease and other operating expense		9,656,006			13,972,725
Cost of service revenues		17,542,774			16,698,860
Marketing, general and administrative expense		8,632,621			11,369,994
Depreciation, depletion and amortization expense		7,101,352			12,608,072
Impairment of oil and gas properties and equipment		16,597,257			131,795,087
Impairment of goodwill and intangible assets		4,397,928			8,040,179
Accretion of abandonment obligations		322,969			266,054

Total costs and expenses		64,250,907			194,750,971

Operating loss		(28,556,874	)		(141,568,076	)

OTHER INCOME (EXPENSE)
Interest income		14,482			199,162
Interest expense		(1,283,525	)		(924,520	)
Change in fair value of commodity derivatives		(12,525,540	)		17,309,196
Other		7,678			(6,117	)
Total other income (expense)		(13,786,905	)		16,577,721

Loss 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			22,070,762

NET 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 stock
				Additional paid-		Retained earnings									Total stockholders'
	Shares	Amount		in capital		(deficit)			Shares			Amount			equity

Balance - January 1, 2008	24,068,675	$	2,407	$	155,064,142	$	1,562,375			(1,997,913	)	$	(15,661,464	)	$	140,967,460
Stock based compensation	—		—		36,332		—			—			—			36,332
Net 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	)	$	60,184,197
Stock based compensation	—		—		75,297		—			—			—			75,297
Net 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			2008

Cash Flows From Operating Activities
Net 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			12,608,072
Impairment of oil and gas properties and equipment		16,597,257			131,795,087
Impairment of goodwill and intangible assets		4,397,928			8,040,179
Accretion of asset retirement obligation and debt discount	$	561,619			415,837
Stock based compensation		75,297			36,332
Deferred 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			698,640
Inventory		25,686			(347,921	)
Prepaid expenses and other current assets		136,236			(290,477	)
Accounts payable		(591,916	)		824,990
Accrued liabilities and other		(432,783	)		2,063,455
Income taxes payable		208,554			(135,190	)
Commodity derivatives		—			(1,008,566	)
Net cash provided by (used in) operating activities		(29,040	)		7,116,423

Cash Flows From Investing Activities
Additions 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		—			2,522,639
Cash 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 Activities
Proceeds of revolving credit facility		1,000,000			12,008,767
Payments, long-term debt and capital leases		(1,225,090	)		(166,533	)
Net cash provided by (used in) financing activities		(225,090	)		11,842,234

Net decrease in cash		(726,153	)		(12,761,527	)

Cash and cash equivalents - beginning of the period		3,668,092			16,429,619

Cash and cash equivalents - end of the period	$	2,941,939		$	3,668,092

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the period for:
Interest	$	703,000		$	635,203
Income taxes
Non-Cash Investing and Financing Activities:
Revision to estimate of asset retirement obligation		2,378,882			-
Issuance of notes payable - Pleasanton acquisition	$	-		$	550,000
Adjustment of purchase price of oil and gas properties and deferred taxes	$	-		$	4,640,000
Acquisition of Maverick (cash flow notes, net of discount)	$	-		$	3,034,000

Acquisition of Maverick in 2008:
Cash	$	-		$	621,518
Accounts receivable		-			4,296,033
Other current assets		-			157,303
Property and equipment		-			1,510,052
Goodwill		-			5,912,611
Intangible assets		-			5,522,250
Accounts 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		-			9,296,118
Less: 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.

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.

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

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 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.

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 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.

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	$	6,262
Cash flow notes, net of working capital adjustment and present value discount		3,034
	$	9,296

Recognized amount of assets acquired and liabilities assumed
Assets acquired:
Cash	$	622
Accounts receivable		4,296
Other current assets		157
Property and equipment		1,510
Goodwill		7,845
Amortizable intangible assets		5,522
		19,952
Liabilities 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 Operations
	Revenue		(Loss) Before Income Taxes			Net Loss			Loss Per Share
Year 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		2008
Beginning balance:	$	204,372	$	170,572
Acquisition of properties
Proved		-		7,489
Unproved		-		1,000
Adjustment to purchase price of oil and gas properties		-		4,640
Exploration costs		-		1,130

Revision to Asset Retirement Obligation		2,339
Development costs		1,580		19,541

Balance 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	$	208,291
Costs not being amortized		0
		208,291
Accumulated 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		2008
Equipment	$	411	$	436

Balance 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			2008
Crude oil derivative realized settlements	$	1,164			(5,256	)
Crude oil derivative change in unrealized gains (losses)		(13,690	)		22,565
Gain (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		1,585
	Puts		110,000		75.00		2,011

2011	Swaps		120,000		95.25		1,098
	Puts		120,000		80.00		1,195

2012	Swaps		120,000		95.00		896

	Total 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	Total
Oil and natural gas derivatives	—	$	6,785	—	$	6,785

As of December 31, 2008
(in thousands)

	Level 1	Level 2		Level 3	Total
Oil 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		2008

Intangible assets at January 1	$	5,061	$	376
Additions during period		—		13,367
Amortization 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	$	964
2011		966
2012		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		2008
Oil and gas revolving line of credit	(a)	$	13,029	$	12,009
Notes payable - acquisitions	(b)		3,422		3,537
Revolving line of credit to former shareholders – Maverick	(c)(f)		2,917		3,249
Term note to former shareholders - Maverick	(d)(f)		252		281
Second term note to former shareholders - Maverick	(e)(f)		1,404		1,474
Notes payable to third party – Maverick	(g)		-		305
Other			0		468
			21,024	$	21,323
Less: Current maturities			17,602		13,404
Long-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 ½ 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	$	17,602
2011		—
2012		—
2013	$	3,422
Thereafter		—
	$	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	$	181
2011		123
2012		46
Total minimum lease payments		350
Less: Amount representing interest		(38	)
Current value of minimum lease payments		312
Less: 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:

			Weighted
	Number		Average
	of Share Options		Exercise Price
Outstanding at December 31, 2007		-		-
Granted		140,000		3.86
Outstanding at December 31, 2008		140,000		3.86
Granted		32,000		0.61
Exercised		—		—
Canceled		(21,000)		1.39

Outstanding 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			2008
Risk-free interest rates			3.85	%		3.9	%
Dividend yield			0	%		0	%
Volatility			107.5	%		68.8	%
Expected life	6.3 year				6.4 years
Weighted average grant date fair value		$	0.61		$	2.39
Total options granted			32,000			140,000
Total 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			2008
Numerator:
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			22,070,762
Effect 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			22,070,762

Basic 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		2008
ARO liability at January 1	$	4,537	$	3,577
Abandonments during period		(24)		(3)
Accretion expense		326		266
Obligations arising during period		11		697
Changes 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			2008
Taxes 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		2008
Deferred expenses - start-up costs	$	537	$	537
Other (includes asset retirement obligation)		1,612		1,499
Allowance for bad debts		79		-
Net operating loss carry-forward		9,737		6,061
Depletion carry-forward		1,924		1,924
Less: valuation allowance		(8,735)		(3,045	)
		5,154		6,976

Other		-		(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									Consolidated
For the Year Ended December 31, 2009:	and Production			Engineering			Parent			Total
Revenues	$	17,174		$	18,597		$	-		$	35,771
Intersegment revenues		-			(77	)		-			(77	)
Total revenues	$	17,174		$	18,520		$	-		$	35,694
Income (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									Consolidated
For the Year Ended December 31, 2008:	and Production			Engineering			Parent			Total
Revenues	$	34,849		$	20,529		$	-		$	55,378
Intersegment revenues		-			(2,195	)		-			(2,195	)
Total revenues	$	34,849		$	18,334		$	-		$	53,183
Income (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

Hyman Litigation

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.

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Citgo Litigation

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.

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.

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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

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	2009									2008
	Oil			Gas			MBoe			Oil			Gas			MBoe

Proved reserves:
Beginning of period		2,310			16,042			4,983			6,526			21,812			10,161
Revisions		138			(1,655	)		(138	)		(4,084	)		(5,647	)		(5,025	)
Extensions and discoveries		—			—			—			120			—			120
Sales of minerals-in-place		—			—			—			—			—			—
Purchases of minerals-in-place		—			—			—			29			688			144
Production		(260	)		(710	)		(378	)		(281	)		(811	)		(417	)
End of period		2,188			13,677			4,467			2,310			16,042			4,983

Proved developed reserves:
Beginning of period		916			5,333			1,805			2,639			6,497			3,722
End of period		1,287			3,912			1,939			916			5,333			1,805

Proved undeveloped reserves:
Beginning of period		1,394			10,709			3,178			3,887			15,315			6,439
End 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		$	181,725
Future costs:
Production		(72,821	)		(82,806	)
Development		(23,755	)		(26,396	)
Income taxes		(17,008	)		—
Future net cash inflows		54,786			72,523
10% discount factor		(29,280	)		(28,177	)
Standardized measure of discounted net cash flows	$	25,506		$	44,346

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

End 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		Gas
2009 (average price)	$	56.64	$	3.25
2008 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			2008

Revenues	$	17,173		$	34,157
Production costs		(9,656	)		(13,973	)
Depreciation, depletion, amortization and impairment (1)		(21,997	)		(141,349	)
Income tax benefit		-			44,178
Results 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.

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

	2009			2008
Proved oil and gas properties	$	206,033		$	204,372
Unproved oil and gas properties		2,258			2,258
Accumulated 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		2008
Acquisition of properties
Proved		-		12,129
Unproved		-		1,000
Exploration costs		-		1,130
Development costs		1,580		19,541
Balance at December 31:		1,580	$	33,800

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Attached files

PLATINUM ENERGY RESOURCES INC Reports

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