form10k.htm

10-K 1 form10k.htm LUCAS ENERGY 10-K 3-31-2010 form10k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended March 31, 2010

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 0-51414

LUCAS ENERGY, INC.

(Exact name of registrant as specified in its charter)

Nevada	98-0417780
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

3555 Timmons Lane, Suite 1550

Houston, Texas 77027

(Address of principal executive offices)

(713) 528-1881

(Registrant's telephone number, including area code)

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

Securities registered pursuant to Section 12(g) of the Act: Common Stock, $0.001 par value

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section13 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 is not contained herein, and will not be contained, to the best of the 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 the definitions of “large accelerated filer”, “accelerated filer”, “non-accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer o

Accelerated filer o

Non-accelerated filer 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

Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of September 30, 2009 (the last business day of the registrant’s most recently completed second fiscal quarter)	$	4,987,282

Number of shares of registrant’s common stock outstanding as of June 29, 2010		13,603,490

LUCAS ENERGY, INC.

FORM 10-K

For the Fiscal Year Ended March 31, 2010

TABLE OF CONTENTS

		Page
PART 1
Item 1.	Business	2
Item 1A.	Risk Factors.	5
Item 2.	Properties.	12
Item 3.	Legal Proceedings.	16
Item 4.	(Removed and Reserved)	16

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.	17
Item 6.	Selected Financial Data.	18
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations.	19
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	27
Item 8.	Financial Statements and Supplementary Data.	27
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	28
Item 9A.	Controls and Procedures.	28
Item 9B.	Other Information.	29

Part III
Item 10.	Directors, Executive Officers and Corporation Governance.	30
Item 11.	Executive Compensation.	34
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	38
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	39
Item 14.	Principal Accounting Fees and Services.	39

Part IV

Item 15.	Exhibits, Financial Statement Schedules.	41
	Signatures	42
	Consolidated Financial Statements and Footnotes	F 1 – F 17
	Supplemental Information on Oil and Gas Producing Activities	F- 18

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Cautionary Statement

This report on Form 10-K and the documents or information incorporated by reference herein contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995, as amended. These forward-looking statements are subject to risks and uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from the results, performance or achievements expressed or implied by the forward-looking statements. You should not unduly rely on these statements. Factors, risks, and uncertainties that could cause actual results to differ materially from those in the forward-looking statements include, among others,

our growth strategies;

anticipated trends in our business;

our ability to make or integrate acquisitions;

our liquidity and ability to finance our exploration, acquisition and development strategies;

market conditions in the oil and gas industry;

the timing, cost and procedure for proposed acquisitions;

the impact of government regulation;

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

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

increases in oil and gas production;

the number of wells we anticipate drilling in the future;

estimates, plans and projections relating to acquired properties;

the number of potential drilling locations; and

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

We identify forward-looking statements by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate,” “hope,” “plan,” “believe,” “predict,” “envision,” “intend,” “will,” “continue,” “potential,” “should,” “confident,” “could” and similar words and expressions, although some forward-looking statements may be expressed differently. You should be aware that our actual results could differ materially from those contained in the forward-looking statements. You should consider carefully the statements under the “Risk Factors” section of this report and other sections of this report which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements, and the following factors:

the possibility that our acquisitions may involve unexpected costs;

the volatility in commodity prices for oil and gas;

the accuracy of internally estimated proved reserves;

the presence or recoverability of estimated oil and gas reserves;

the ability to replace oil and gas reserves;

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

environmental risks;

exploration and development risks;

competition;

the inability to realize expected value from acquisitions;

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

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

Forward-looking statements speak only as of the date of this report or the date of any document incorporated by reference in this report. Except to the extent required by applicable law or regulation, we do not undertake any obligation to update forward-looking statements to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.

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PART I

ITEM 1. BUSINESS.

General

Lucas Energy, Inc. (“we,” “us,” “Lucas”, “Lucas Energy”, the “Company” and words of similar meaning) is an independent oil and gas company based in Houston, Texas with approximately 12,500 gross acres (10,400 acres net) of oil and gas leases in South Texas primarily in the Gonzales County and Wilson County, Texas. We hold oil and gas interests in the Austin Chalk formation (proved and producing), Buda formation (proved and production), and Eagle Ford Shale formation (proved and undeveloped). We focus on building, revitalizing and developing a portfolio of oil and gas properties by acquiring what we believe are undervalued and underperforming oil and gas assets for which we believe we can increase production.

We operate thirty (30) producing wells that currently produce approximately 190-200 barrels of oil per day (“BOPD”), gross. In total we hold interests in sixty-three (63) producing, shut-in, and previously plugged and abandoned wellbores. Our oil production sales totaled 27,833 barrel oil equivalent, net to our interest for our fiscal year ended March 31, 2010. We operate all of our oil and gas properties with the exception of one property located in Jasper County, Texas.

Acquisitions of oil and gas properties are a core part of our growth strategy. We focus on acquiring shut-in wells that we believe have been overlooked by other companies and have, in our assessment, a high probability of additional recovery of reserves through our revitalization process or through the drilling of new laterals. Specifically, we seek out opportunities to acquire wells located in mature oil fields that we believe are underdeveloped and have the potential to recover significant oil reserves that are still in place. The term underdeveloped is an industry term meaning that the reservoirs of interest have either not been fully exploited through drilling, or the reserves in current well bores, whether active or plugged and abandoned, have not been fully recovered by primary recovery techniques. In many instances the fields that we target have lost some or all of the reservoir pressure required to drive the oil through the overlying rock and sand and into the well bores of the producing wells, or they have experienced mechanical problems.

Most of the acquisition prospects that we conduct initial screening on are sourced directly by our senior management or specialized third-party consultants with local area knowledge. Prospects that are of further interest to us after we complete of our initial review, are evaluated for technical and economic viability. We target well acquisitions that we estimate: (a) have a good opportunity and the appropriate acreage to drill additional laterals; (b) payback period of less than 12 months; and (c) projected internal rate of return on capital invested is accretive to earnings.

Our revitalization process is directed toward bringing wells back into production or enhance production through ordinary practices used in the oil and gas industry. Our revitalization procedures used on acquired wells include the installation of new or good used equipment on the well; cleaning out the well with open ended tubing, tubing with a bit, or tubing with a mule shoe; treating the well with acid, soapy water, or other proprietary chemicals sourced from third parties; re-entry of a plugged and abandoned well; and drilling of a new lateral extension on an existing well. Our well revitalization program enables us to generate short-term cash and to hold leases for additional future development. Additionally we have conducted reservoir engineering on a program to drill new laterals from existing well-bores or offset locations that we have already leased. The purpose of these laterals are to provide more aerial access to the formation in order to increase the flow rate and to recover additional oil and gas reserves not recoverable from the existing vertical (straight) holes.

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Our primary focus is to grow our portfolio of oil and gas properties. Our revenues are derived from the sale of the oil that we produce from our wells. We derive ancillary revenue from associated natural gas produced in connection with production from our oil wells. Our assets deplete as our oil and gas reserves are produced, and our business is capital intensive requiring substantial funding to make property acquisitions, to drill and complete wells and to conduct well revitalizations in order for us to maintain and increase our oil and gas reserve base. Our primary recurring costs are expenses associated with lease operations and with operating the Company.

Historically, we have retained substantially all our earnings to fund our capital program and to grow our oil and gas reserve base. Presented below are our actual sales of oil and gas production and average prices realized during the years ended March 31, 2010 and 2009:

	For the Year Ended March 31, 2010		For the Year Ended March 31, 2009		Increase / (Decrease)
Volumes, net:
Oil (bbls)		26,858		41,309		(14,451	)
Gas (mcf)		5,849		7,505		(1,656	)
Total (boe)		27,833		42,560		(14,727	)
Average price received:
Oil	$	65.60	$	80.82	$	(15.22	)
Gas	$	2.73	$	5.77	$	(3.04	)
Total Revenues:	$	1,777,736	$	3,382,060	$	(1,604,324	)

Our principal office is located at 3555 Timmons Lane, Suite 1550, Houston, Texas 77027. Our phone number is (713) 528-1881. The Company is authorized to transact business in the state of Texas, and is a bonded operator with the Texas Railroad Commission.

Research and Development

We have not allocated funds for conducting research and development activities. We do not anticipate allocating funds for research and development in the immediate future.

Marketing of Crude Oil and Natural Gas

We operate exclusively in the United States oil and gas industry. Crude oil production sales are made directly to GulfMark Energy, Inc. and Texon LP. Our sales are made on a month-to-month basis, and title transfer occurs at an individual property’s tank battery when loaded onto the oil purchaser’s truck. Crude oil prices realized from production sales are tied to published west Texas intermediate crude indexes.

Our natural gas production is associated gas resulting from crude oil production and is nominal. Natural gas is sold to Houston Pipeline Company on a month-to-month basis.

Although we believe that we are not dependent upon any one customer, our marketing arrangement with GulfMark accounted for approximately 87% and 88% of our revenue for the years ended March 31, 2010 and 2009, respectively. In the event that GulfMark is unwilling or unable to purchase our crude oil production, we believe alternative purchasers are readily available and sales would occur at competitive market prices.

Employees

As of our fiscal year ended March 31, 2010, we employed four full-time employees, consisting of the chief executive officer and the chief financial officer, and two administrative support staff. In conjunction with the continued ramp up of our activities for increased drilling and development initiatives, we have increased our full-time employee complement by four comprised of a land manager, accountant and two administrative support staff in our Gonzales, Texas field office. Other resource requirements are outsourced third parties through contractors and consultants that have specialized operational and technical skill sets, together with professional services for reserve estimations, audit, legal and public company compliance requirements.

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None of our employees are a member of any union, nor have they entered into any collective bargaining agreements. We believe that our relationship with our employees is good. With the successful implementation of our business plan, we may seek additional employees in the next year to handle anticipated potential growth.

Facilities

We currently occupy approximately 3,793 square feet of office space in Houston, Texas for $6,572 per month pursuant to a 22-month sublease agreement with an expiry of April 30, 2012. We have a Gonzales field office for which we pay $350 per month on a month-to-month basis.

Industry Segments

We are presently engaged in one industry segment, which is the exploration and production of oil and natural gas.

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ITEM 1A. RISK FACTORS.

An investment in our common stock involves a number of risks. These risks include those described in this confidential private placement memorandum and others we have not anticipated or discussed. Before you purchase the Securities you should carefully consider the information about risks identified below, as well as the information about risks stated in other parts of this memorandum and in our filings with the Commission that we have incorporated by reference in this memorandum. Any of the risks discussed below or elsewhere in this memorandum or in our Commission filings, and other risks we have not anticipated or discussed, could have a material impact on our business, results of operations, and financial condition. As a result, they could have an impact on our ability to pay any amounts due with respect to the Securities, or our stock price.

Risks Relating to Our Business

We have a limited operating history, and we may not be able to operate profitably in the near future, if at all.

We have a limited operating history. Businesses which are starting up or in their initial stages of development present substantial business and financial risks and may suffer significant losses from which they cannot recover. We will face all of the challenges of a new business enterprise, including but not limited to, locating and successfully developing oil and gas properties, locating suitable office space, engaging the services of qualified support personnel and consultants, establishing budgets and implementing appropriate financial controls and internal operating policies and procedures. We will need to attract and retain a number of key employees and other service personnel.

We have limited operating capital.

While we believe that we have sufficient cash on hand and cash flow from operations to fund recurring production operating expenses and base general and administrative requirements, over the longer term we may not. The amount of capital available to us is limited, and may not be sufficient to enable us to fully execute our capital expenditure program and growth initiatives with additional funding sources. Additional financing may also be required to achieve our objectives and provide working capital for organizational infrastructure developments necessary to achieve our growth plans and reach a level of oil and gas operating activities that allows us to take advantage of certain economies of scale inherent to our business which would provide us the ability to reduce costs on a per unit of production basis. There can be no assurance that we will be able to obtain such financing on attractive terms, if at all. We have no firm commitments for additional cash funding.

Our Credit Facility was secured with substantially all existing and after acquired assets, and was subject to financial covenants that we were required to meet.

Our Revolving Line of Credit and Letter of Credit Facility with Amegy Bank that we entered into on October 8, 2008 was secured by substantially all of our existing and after acquired assets. The availability of funds and repayments of borrowed funds were subject to periodic borrowing base determinations. Amegy Bank’s lending commitment and our borrowing capacity was subject to increases or decreases as the collateral value of the oil and gas properties securing the Credit Facility fluctuates with factors such as changes in commodity prices, revisions to reserve estimates, and changes in capital expenditure and operating cost estimates. On March 31, 2010, the Amegy Bank’s lending commitment to us was approximately $2.0 million while the outstanding principal balance due to Amegy Bank under Credit Facility was $2.15 million. The maturity of outstanding borrowings under the Credit Facility was three (3) years from closing the Credit Facility, or earlier if repayments are required pursuant to periodic borrow base redetermination. The Credit Facility contained financial covenants that we were required to meet and if not met, we would be required to request waiver(s).

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On May 5, 2010, Lucas paid off the outstanding balance under the Amegy Bank Credit Facility, and terminated the Facility. In connection with the repayment and termination of the Credit Facility, Amegy Bank released all liens. Future financings may necessitate that substantially all or a portion of our assets be pledged to a counterparty, and could include financial covenants requirements similar to the covenants that existed under the Amegy Credit Facility which we may or may not be able to meet.

We do not intend to pay dividends to our shareholders.

We do not currently intend to pay cash dividends on our common stock and do not anticipate paying any dividends at any time in the foreseeable future. At present, we will follow a policy of retaining all of our earnings, if any, to finance development and expansion of our business.

Our officers and directors have limited liability, and we are required in certain instances to indemnify our officers and directors for breaches of their fiduciary duties.

We have adopted provisions in our Articles of Incorporation and Bylaws which limit the liability of our officers and directors and provide for indemnification by us of our officers and directors to the full extent permitted by Nevada corporate law. Our articles generally provide that our officers and directors shall have no personal liability to us or our shareholders for monetary damages for breaches of their fiduciary duties as directors, except for breaches of their duties of loyalty, acts or omissions not in good faith or which involve intentional misconduct or knowing violation of law, acts involving unlawful payment of dividends or unlawful stock purchases or redemptions, or any transaction from which a director derives an improper personal benefit. Such provisions substantially limit our shareholders' ability to hold officers and directors liable for breaches of fiduciary duty, and may require us to indemnify our officers and directors.

We face intense competition.

We compete against many other energy companies, some of which have considerably greater resources and abilities. These competitors may have greater marketing and sales capacity, established distribution networks, significant goodwill and global name recognition.

We depend significantly upon the continued involvement of our present management.

Our success depends to a significant degree upon the involvement of our management, who are in charge of our strategic planning and operations. We may need to attract and retain additional talented individuals in order to carry out our business objectives. The competition for such persons could be intense and there are no assurances that these individuals will be available to us.

Our business is subject to extensive regulation.

As many of our activities are subject to federal, state and local regulation, and as these rules are subject to constant change or amendment, there can be no assurance that our operations will not be adversely affected by new or different government regulations, laws or court decisions applicable to our operations.

Government regulation and liability for environmental matters may adversely affect our business and results of operations.

Crude oil and natural gas operations are subject to extensive federal, state and local government regulations, which may be changed from time to time. Matters subject to regulation include discharge permits for drilling operations, 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 crude oil and natural gas wells below actual production capacity in order to conserve supplies of crude oil and natural gas. There are federal, state and local laws and regulations primarily relating to protection of human health and the environment applicable to the development, production, handling, storage, transportation and disposal of crude oil and natural gas, byproducts thereof and other substances and materials produced or used in connection with crude oil and natural gas operations. In addition, we may inherit liability for environmental damages caused by previous owners of property we purchase or lease. As a result, we may incur substantial liabilities to third parties or governmental entities. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The implementation of new, or the modification of existing, laws or regulations could have a material adverse effect on us.

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The crude oil and natural gas reserves we report in our SEC filings are estimates and may prove to be inaccurate.

There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their estimated values. The reserves we will report in our filings with the SEC will only be estimates and such estimates may prove to be inaccurate because of these uncertainties. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable crude oil and natural gas reserves depend upon a number of variable factors, such as historical production from the area compared with production from other producing areas and assumptions concerning effects of regulations by governmental agencies, future crude oil and natural gas prices, future operating costs, severance and excise taxes, development costs and work-over and remedial costs. Some or all of these assumptions may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of crude 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 but at different times may vary substantially. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

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

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

unexpected drilling conditions;

pressure or irregularities in formations;

equipment failures or accidents;

inability to obtain leases on economic terms, where applicable;

adverse weather conditions and natural disasters;

compliance with governmental requirements; and

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

Drilling or reworking is a highly speculative activity. Even when fully and correctly utilized, modern well completion techniques such as hydraulic fracturing and horizontal drilling do not guarantee that we will find crude oil and/or natural gas in our wells. Hydraulic fracturing involves pumping a fluid with or without particulates into a formation at high pressure, thereby creating fractures in the rock and leaving the particulates in the fractures to ensure that the fractures remain open, thereby potentially increasing the ability of the reservoir to produce oil or gas. Horizontal drilling involves drilling horizontally out from an existing vertical well bore, thereby potentially increasing the area and reach of the well bore that is in contact with the reservoir. Our future drilling activities may not be successful and, if unsuccessful, such failure would have an adverse effect on our future results of operations and financial condition. We cannot assure you that our overall drilling success rate or our drilling success rate for activities within a particular geographic area will not decline. We may identify and develop prospects through a number of methods, some of which do not include lateral drilling or hydraulic fracturing, and some of which may be unproven. The drilling and results for these prospects may be particularly uncertain. Our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted prospects will be dependent on a number of factors, including, but not limited to:

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

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

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

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

our financial resources and results;

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

the success of our drilling technology.

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

Crude oil and natural gas prices are highly volatile in general and low prices will negatively affect our financial results.

Our revenues, operating results, profitability, cash flow, future rate of growth and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of crude oil and natural gas. Lower crude oil and natural gas prices also may reduce the amount of crude oil and natural gas that we can produce economically. Historically, the markets for crude oil and natural gas have been very volatile, and such markets are likely to continue to be volatile in the future. Prices for crude oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for crude oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, including:

worldwide and domestic supplies of crude oil and natural gas;

the level of consumer product demand;

weather conditions and natural disasters;

domestic and foreign governmental regulations;

the price and availability of alternative fuels;

political instability or armed conflict in oil producing regions;

the price and level of foreign imports; and

overall domestic and global economic conditions.

It is extremely difficult to predict future crude oil and natural gas price movements with any certainty. Declines in crude oil and natural gas prices may materially adversely affect our financial condition, liquidity, ability to finance planned capital expenditures and results of operations. Further, oil and gas prices do not move in tandem.

Risks Related To Share Ownership

The market price for our common stock may be volatile, and you may not be able to sell our stock at a favorable price or at all.

Many factors could cause the market price of our common stock to rise and fall, including:

•

actual or anticipated variations in our quarterly results of operations;

•

changes in market valuations of companies in our industry;

•

changes in expectations of future financial performance;

•

fluctuations in stock market prices and volumes;

•

issuances of dilutive common stock or other securities in the future;

•

the addition or departure of key personnel;

•

announcements by us or our competitors of acquisitions, investments or strategic alliances; and

•

the increase or decline in the price of oil and natural gas.

It is possible that the proceeds from sales of our common stock may not equal or exceed the prices you paid for it plus the costs and fees of making the sales.

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Substantial sales of our common stock, or the perception that such sales might occur, could depress the market price of our common stock.

We cannot predict whether future issuances of our common stock or resales in the open market will decrease the market price of our common stock. The impact of any such issuances or resales of our common stock on our market price may be increased as a result of the fact that our common stock is thinly, or infrequently, traded. The exercise of any options or the vesting of any restricted stock that we may grant to directors, executive officers and other employees in the future, the issuance of common stock in connection with acquisitions and other issuances of our common stock could have an adverse effect on the market price of our common stock. In addition, future issuances of our common stock may be dilutive to existing shareholders. Any sales of substantial amounts of our common stock in the public market, or the perception that such sales might occur, could lower the market price of our common stock.

Our common stock is considered "penny stock" securities under Exchange Act rules, which may limit the marketability of our securities.

Our securities are considered low-priced or "designated" securities under rules promulgated under the Exchange Act. Under these rules, broker/dealers participating in transactions in low-priced securities must first deliver a risk disclosure document which describes the risks associated with such stocks, the broker/dealer's duties, the customer's rights and remedies, certain market and other information, and make a suitability determination approving the customer for low-priced stock transactions based on the customer's financial situation, investment experience and objectives. Broker/dealers must also disclose these restrictions in writing to the customer and obtain specific written consent of the customer, and provide monthly account statements to the customer. The likely effect of these restrictions is a decrease in the willingness of broker/dealers to make a market in the stock, decreased liquidity of the stock and increased transaction costs for sales and purchases of the stock as compared to other securities.

IN ADDITION TO THE RISK FACTORS SET FORTH ABOVE, THE COMPANY IS SUBJECT TO NUMEROUS OTHER RISKS SPECIFIC TO THE PARTICULAR BUSINESS OF THE COMPANY, AS WELL AS GENERAL BUSINESS RISK. INVESTORS ARE URGED TO CONSIDER ALL OF THE RISKS INHERENT IN THE COMPANY'S SECURITIES PRIOR TO PURCHASING OR MAKING AN INVESTMENT DECISION. THE COMPANY'S SECURITIES ARE HIGHLY SPECULATIVE AND INVOLVE A VERY HIGH DEGREE OF RISK.

Competition

We are in direct competition with numerous oil and natural gas companies, drilling and income programs and partnerships exploring various areas of Texas and elsewhere competing for properties. Many competitors are large, well-known oil and gas and/or energy companies, although no single entity dominates the industry. Many of our competitors possess greater financial and personnel resources enabling them to identify and acquire more economically desirable energy producing properties and drilling prospects than us. Additionally, there is competition from other fuel choices to supply the energy needs of consumers and industry. Management believes that there exists a viable market place for smaller producers of natural gas and oil.

Government Regulation

In the United States, legislation affecting the oil and gas industry has been pervasive and is under constant review for amendment or expansion. Pursuant to such legislation, numerous federal, state and local departments and agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. These laws and regulations have a significant impact on oil and gas drilling, gas processing plants and production activities, increasing the cost of doing business and, consequently, affect profitability. Insomuch as new legislation affecting the oil and gas industry is common place and existing laws and regulations are frequently amended or reinterpreted, Lucas Energy may be unable to predict the future cost or impact of complying with these laws and regulations. Lucas Energy considers the cost of environmental protection a necessary and manageable part of its business. Lucas Energy has been able to plan for and comply with new environmental initiatives without materially altering its operating strategies.

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Exploration and Production

Lucas Energy's operations are subject to various types of regulation at the federal, state and local levels. These regulations include requiring permits for the drilling of wells; maintaining prevention plans; submitting notification and receiving permits related to the presence, use and release of certain materials incidental to oil and gas operations; and regulating the location of wells, the method of drilling and casing wells, the use, transportation, storage and disposal of fluids and materials used in connection with drilling and production activities, surface plugging and abandoning of wells and the transporting of production. Lucas Energy's operations are also subject to various conservation matters, including the number of wells which may be drilled in a unit, and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition state conservation laws establish maximum rates of production oil and gas wells, generally limit the venting or flaring of gas, and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and gas Lucas can produce from its wells and to limit the number of wells or the locations at which Lucas Energy can drill.

Environmental

Our exploration, development, and production of oil and gas, including our operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. Such laws and regulations can increase the costs of planning, designing, installing and operating oil and gas wells. Our domestic activities are subject to a variety of environmental laws and regulations, including but not limited to, the Oil Pollution Act of 1990 ("OPA"), the Clean Water Act ("CWA"), the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), the Resource Conservation and Recovery Act ("RCRA"), the Clean Air Act ("CAA"), and the Safe Drinking Water Act ("SDWA"), as well as state regulations promulgated under comparable state statutes. We are also subject to regulations governing the handling, transportation, storage, and disposal of naturally occurring radioactive materials that are found in our oil and gas operations. Civil and criminal fines and penalties may be imposed for non-compliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking certain activities, limit or prohibit other activities because of protected areas or species, and impose substantial liabilities for cleanup of pollution.

Under the OPA, a release of oil into water or other areas designated by the statute could result in the company being held responsible for the costs of remediating such a release, certain OPA specified damages, and natural resource damages. The extent of that liability could be extensive, as set forth in the statute, depending on the nature of the release. A release of oil in harmful quantities or other materials into water or other specified areas could also result in the company being held responsible under the CWA for the costs of remediation, and civil and criminal fines and penalties.

CERCLA and comparable state statutes, also known as "Superfund" laws, can impose joint and several and retroactive liability, without regard to fault or the legality of the original conduct, on certain classes of persons for the release of a "hazardous substance" into the environment. In practice, cleanup costs are usually allocated among various responsible parties. Potentially liable parties include site owners or operators, past owners or operators under certain conditions, and entities that arrange for the disposal or treatment of, or transport hazardous substances found at the site. Although CERCLA, as amended, currently exempts petroleum, including but not limited to, crude oil, gas and natural gas liquids from the definition of hazardous substance, our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA. Furthermore, there can be no assurance that the exemption will be preserved in future amendments of the act, if any.

RCRA and comparable state and local requirements impose standards for the management, including treatment, storage, and disposal of both hazardous and non-hazardous solid wastes. We generate hazardous and non-hazardous solid waste in connection with our routine operations. From time to time, proposals have been made that would reclassify certain oil and gas wastes, including wastes generated during drilling, production and pipeline operations, as "hazardous wastes" under RCRA which would make such solid wastes subject to much more stringent handling, transportation, storage, disposal, and clean-up requirements. This development could have a significant impact on our operating costs. While state laws vary on this issue, state initiatives to further regulate oil and gas wastes could have a similar impact. Because oil and gas exploration and production, and possibly other activities, have been conducted at some of our properties by previous owners and operators, materials from these operations remain on some of the properties and in some instances require remediation. In addition, in certain instances we have agreed to indemnify sellers of producing properties from which we have acquired reserves against certain liabilities for environmental claims associated with such properties. While we do not believe that costs to be incurred by us for compliance and remediating previously or currently owned or operated properties will be material, there can be no guarantee that such costs will not result in material expenditures.

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Additionally, in the course of our routine oil and gas operations, surface spills and leaks, including casing leaks, of oil or other materials occur, and we incur costs for waste handling and environmental compliance. Moreover, we are able to control directly the operations of only those wells for which we act as the operator. Management believes that the Company is in substantial compliance with applicable environmental laws and regulations.

We do not anticipate being required in the near future to expend amounts that are material in relation to our total capital expenditures program by reason of environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, we are unable to predict the ultimate cost of compliance. There can be no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future.

Occupational Health and Safety

Lucas Energy is also subject to laws and regulations concerning occupational safety and health. Due to the continued changes in these laws and regulations, and the judicial construction of many of them, Lucas Energy is unable to predict with any reasonable degree of certainty its future costs of complying with these laws and regulations. Lucas Energy considers the cost of safety and health compliance a necessary and manageable part of its business. Lucas Energy has been able to plan for and comply with new initiatives without materially altering its operating strategies.

Lucas Energy is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") and similar state statutes. In response to liabilities associated with these activities, accruals have been established when reasonable estimates are possible. Such accruals primarily include estimated costs associated with remediation. Lucas Energy has used discounting to present value in determining its accrued liabilities for environmental remediation or well closure, but no material claims for possible recovery from third party insurers or other parties related to environmental costs have been recognized in Lucas Energy's financial statements. Lucas Energy adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates must be adjusted to reflect new information.

Taxation

The operations of the Company, as is the case in the petroleum industry generally, are significantly affected by federal tax laws. Federal, as well as state, tax laws have many provisions applicable to corporations which could affect the future tax liability of the Company.

Commitments and Contingencies

Lucas Energy is liable for future restoration and abandonment costs associated with its oil and gas properties. These costs include future site restoration, post closure and other environmental exit costs. The costs of future restoration and well abandonment have not been determined in detail. State regulations require operators to post bonds that assure that well sites will be properly plugged and abandoned. Each state in which Lucas Energy operates requires a security bond varying in value from state to state and depending on the number of wells that Lucas Energy operates. Management views this as a necessary requirement for operations within each state and does not believe that these costs will have a material adverse effect on its financial position as a result of this requirement.

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ITEM 2. PROPERTIES.

Our properties consist of working and royalty interests owned by us in various oil and gas wells and oil and gas lease acreage located in Gonzales, Wilson, Karnes and Jasper Counties, Texas.

Oil and Gas Acreage

The following table sets forth the developed leasehold acreage held by us as of March 31, 2010 and 2009. Gross acres are the total number of acres we have a working interest. Net acres are the sum of our fractional working interests owned in the gross acres.

In certain leases, our ownership varies at different depths; therefore, the net acreage in these leases is calculated with consideration of the varying ownership interests.

All Acreage in Texas	March 31, 2010		March 31, 2009

Gross acreages, approximate		12,526		15,159

Net acreage, approximate		10,429		12,620

Reserves

Our proved and probable reserves and the standardized measure of discounted future net cash flows of our interests in proved oil and gas reserves at March 31, 2010 are set forth below:

Proved Reserves	Oil (Bbls)		Natural Gas (MCF)		Discounted Future Net Cash Flow (at 10% per year)

Developed Producing		73,010		11,760	$	1,614,720

Developed Non Producing		63,540		19,410		2,549,300

Undeveloped		1,833,680		-		43,354,360

Total, before income taxes		1,970,230		31,170	$	47,518,380

Less: Estimated income taxes on future net cash flows (discounted at 10% per year)		n/a		n/a	$	(8,311,887	)

Total, March 31, 2010		1,970,230		31,170	$	39,206,493

Probable Reserves	Oil (Bbls)		Natural Gas (MCF)		Discounted Future Net Cash Flow (at 10% per year)

Undeveloped		680,770		-	$	4,464,910

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Revisions to SEC Oil and Gas Reserve Reporting Requirements.

Effective December 31, 2008, the SEC effected revisions designed to modernize the oil and gas company reserves reporting requirements. The revisions are effective for annual reports filed on or after December 15, 2009. Among other things, the revised reporting requirements include:

•

Commodity Prices—Economic predictibility of reserves and discounted cash flows are now based on a 12-month average commodity price unless contractual arrangements designate the price to be used.

•

Disclosure of Unproved Reserves—Probable and possible reserves may be disclosed separately on a voluntary basis.

•

Proved Undeveloped Reserves—Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years.

•

Reserves Estimation Based on New Technologies—Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.

•

Reserve Personnel and Estimation Process Disclosure—Additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process and internal controls used to assure the objectivity of the reserve estimates.

The required revisions to modernize the oil and gas reserve disclosures have been incorporated into our March 31, 2010 reserve reports and in the aggregate were not considered material to our reserves.

Our proved reserves and the standardized measure of discounted future net cash flows of our interests in proved oil and gas reserves at March 31, 2009 are set forth below:

Proved Reserves	Oil (Bbls)		Natural Gas (MCF)		Discounted Future Net Cash Flow (at 10% per year)

Developed Producing		218,200		67,510	$	4,337,550

Developed Non Producing		11,900		-		171,110

Undeveloped		2,008,760		-		23,290,550

Total, before income taxes		2,238,860		67,510	$	27,799,210

Less: Estimated income taxes on future net cash flows (discounted at 10% per year)		n/a		n/a	$	(3,812,075	)

Total, March 31, 2009		2,238,860		67,510	$	23,987,135

The proved reserves estimates contained in the above tables at March 31, 2010 and 2009 are based primarily on reserve reports prepared by of Forest A. Garb & Associates, independent petroleum consultants to the Company. The present values of the proved reserves as of March 31, 2010 identified in the tables are prepared by discounting future projected net cash flows computed with constant oil and gas prices of $69.54 per barrel (Bbl) and $3.96 per thousand cubic feet (Mcf), respectively and constant future production and development costs less estimated future income tax expense. The constant oil and gas prices used at March 31, 2009 were $48.16 per barrel and $3.64 per thousand cubic feet, respectively. The estimated future net cash flows are then discounted at a rate of 10 percent per year.

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Reserve reports prepared by petroleum engineers and used by the Company are, by their very nature, inexact and subject to changes and revisions. Proved developed reserves are reserves expected to be recovered from existing wells with existing equipment and methods. Proved undeveloped reserves are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production. No estimates of reserves have been included in any reports to any federal agency other than the SEC.

See Supplemental Information on Oil and Gas Producing Activities included as part of our consolidated financial statements. A copy of the Forrest A. Garb & Associates, Inc. report “Estimated Reserves and Future Net Revenue as of April 1, 2010, Attributable to Interests Owned by Lucas Energy, Inc. In Certain Properties Located in Texas (SEC Case)” is attached as Exhibit 99.1 to this Annual Report on Form 10-K.

Wells

The following summarizes the Company's productive oil and gas wells as of March 31, 2010 and 2009. Productive wells are producing wells and wells capable of production. Gross wells are the total number of wells in which the company has an interest. Net wells are the sum of the Company's fractional working interests owned in the gross wells.

	Year ended March 31, 2010		Year ended March 31, 2009
Oil and gas wells, Texas:		30		43
Gross		30		43
Net		26		40

The following summarizes our net production sold and capital expenditures for the years ended March 31, 2010 and 2009:

	March 31, 2010		March 31, 2009
Production sales:
Oil (barrels)		26,858		41,309
Natural gas (thousands cubic feet)		5,849		7,505
Total (barrels oil equivalent)		27,833		42,560

Capital Expenditures (Cash and Non-Cash)	$	3,372,881	$	4,004,694

The following is a list of our oil and natural gas producing properties at March 31, 2010 and 2009 and the crude oil and the natural gas production sales for the years then ended, all volumes are net to our interest in the properties:

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(Operated by Lucas Unless Otherwise Noted)		Fiscal Years Ending
Lease Name	County	March 31, 2010		March 31, 2009
		(Unaudited)		(Unaudited)
Oil (bbls):
Ali-O No. 1	Gonzales		61		77
Barnett, W.L. et al #1	Gonzales		794		525
Barnett, W.L. et al #4	Gonzales		194		299
Bates # 2R	Wilson		50		-
Burnett #1	Gonzales		70		-
Cone-Dubose Unit #1	Gonzales		59		2,039
Copeland Karnes #1	Karnes		550		384
Ervin Et Al 1	Gonzales		828		-
FT Shauer	Gonzales		-		224
Green	Baylor		-		225
Griffin Oil Unit #2	Gonzales		4,349		7,117
Griffin Oil Unit #5	Gonzales		220		1,197
Griffin Ruddock #1	Gonzales		1,530		1,264
Hagen Ranch Unit	Gonzales		572		730
Hagen Ranch Unit #3	Gonzales		3,001		6,811
Henry Christian	Gonzales		-		1,207
Hindes	Atoscosa		818		725
Hindman #2	Gonzales		53		365
Hines Unit #1	Gonzales		549		1,070
Jim Davis #1	Gonzales		741		655
Kuntschik#1	Gonzales		997		1,363
Kuntschik#2	Gonzales		1,127		1,057
Mary Martha #1	Gonzales		464		513
Matthews #1	Atascosa		215		293
Merit-RVS #1	Gonzales		911		614
Norris #1	Gonzales		531		-
Paul Foerster #1	Gonzales		414		447
Perkins Oil Unit #1	Gonzales		3,155		6,340
Rozella Kifer No. 1	Gonzales		57		51
RVS Oil Unit	Gonzales		62		-
RVS #2	Gonzales		248		212
RVS #3	Gonzales		356		1,715
Sloan	Gonzales		-		119
Team Bank	Wilson		2,109		1,709
Upton Ruddock	Gonzales		606		1,079
Wright #1	Gonzales		245		273
Zavadil #1	Gonzales		175		114
Zavadil #2st	Gonzales		747		496
Total oil sales (bbls)			26,858		41,309

Natural Gas (Mcf):
Copeland Karnes #1H	Karnes		-		40
Griffin-Ruddock Oil Unit #1	Gonzales		4,270		1,269
Ruddock, Upton #1	Gonzales		-		3,765
Kaspar CP	Gonzales		1,579		2,431
Total natural gas sales (Mcf)			5,849		7,505

Total barrels oil equivalent			27,833		42,560

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The following summarizes the Company’s drilling activities for the years ending March 31, 2010, and 2009:

For the year ended March 31, 2010	Productive Wells		Dry Wells

Exploratory wells, net		0		0

Development wells, net		1		0

For the year ended March 31, 2009	Productive Wells		Dry Wells

Exploratory wells, net		0		0

Development wells, net		1		0

Set forth in the following schedule is the average sales price per unit of oil, expressed in barrels ("bbl"), and of natural gas, expressed in thousand cubic feet ("mcf") and average cost of production produced by us for the past two fiscal years.

	Year ended March 31,
	2010		2009
Average sales price:
Gas (per mcf)	$	2.73	$	5.77
Oil (per bbl)	$	65.60	$	80.82
Average cost of production:
Gas (per mcf)	$	-	$	-
Oil (per bbl)*	$	37.66	$	31.62

*Gas sold is a byproduct of oil production; costs associated with the gas sold are included in the cost of oil production.

The following schedule sets forth the capitalized costs relating to oil and gas producing activities by us for the past two fiscal years.

	March 31,
	2010			2009
Proved oil and gas producing properties and related lease and well equipment	$	24,699,722		$	22,794,893
Accumulated depletion		(2,482,433	)		(1,721,580	)
Net Capitalized Costs	$	22,217,289		$	21,073,313

We do not anticipate investing in or purchasing assets and/or property for the purpose of capital gains. It is our intention to purchase assets and/or property for the purpose of enhancing our primary business operations. We are not limited as to the percentage amount of our assets we may use to purchase any additional assets or properties.

ITEM 3. LEGAL PROCEEDINGS.

The Company is not aware of any pending or threatened litigation.

ITEM 4 (REMOVED AND RESERVED)

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PART II

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

Market Information

Our common stock is quoted on the NYSE Amex (“AMEX”) under the symbol LEI. Set forth in the table below are the quarterly high and low prices of our common stock for the past two fiscal years.

2010	High		Low

Quarter ended June 30, 2009	$	1.13	$	0.80
Quarter ended September 30, 2009	$	1.98	$	0.69
Quarter ended December 31, 2009	$	0.67	$	0.44
Quarter ended March 31, 2010	$	0.96	$	0.61

2009	High		Low

Quarter ended June 30, 2008	$	6.16	$	2.81
Quarter ended September 30, 2008	$	3.91	$	1.45
Quarter ended December 31, 2008	$	1.54	$	0.51
Quarter ended March 31, 2009	$	0.86	$	0.38

Holders

As of March 31, 2010, there were approximately 2,202 certificate and non-objecting beneficial holders of record of our common stock. This does not take into account those shareholders who object to disclosure on the non-objecting beneficial owners disclosure list.

Dividend Policy

We have not declared, paid cash dividends, or made distributions in the past. We do not anticipate that we will pay cash dividends or make distributions in the foreseeable future. We currently intend to retain and reinvest future earnings to finance operations.

Issuance of Unregistered Shares of Common Stock

On April 29, 2010 a warrant holder that purchased 25,000 shares of common stock and attached warrants for a share of common stock at $1.00 per share exercised his warrants and the Company issued 25,000 shares of common stock for total proceeds of $25,000.

All of the share issuances were conducted in compliance with the exemption from registration provided by Rule 4(2).

Purchases of Treasury Stock

On September 8, 2008, Lucas repurchased 10,000 shares of its common stock in the open market trading at a cost of $21,087. On October 29, 2008, Lucas repurchased 26,900 shares of its common stock in the open market trading at a cost of $28,072. The shares are held by Lucas’ transfer agent as treasury stock, and the shares are treated as issued but not outstanding at March 31, 2010.

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These share purchases were effected through a Rule 10B-18 program with a third-party brokerage firm.

ITEM 6. SELECTED FINANCIAL DATA.

Not applicable.

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

The following information should be read in conjunction with the consolidated financial statements and notes thereto appearing elsewhere in this Form 10-K. The terms “Lucas Energy,” “Lucas,” “we,” “us” and “our” refer to Lucas Energy, Inc.

Forward-Looking and Cautionary Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements may relate to such matters as anticipated financial performance, future revenues or earnings, business prospects, projected ventures, new products and services, anticipated market performance and similar matters. When used in this report, the words "may," "will," "expect," "anticipate," "continue," "estimate," "project," "intend," and similar expressions are intended to identify forward-looking statements regarding events, conditions, and financial trends that may affect our future plans of operations, business strategy, operating results, and financial position. We caution readers that a variety of factors could cause our actual results to differ materially from the anticipated results or other matters expressed in forward-looking statements. These risks and uncertainties, many of which are beyond our control, include:

the sufficiency of existing capital resources and our ability to raise additional capital to fund cash requirements for future operations;

uncertainties involved in the rate of growth of our business and acceptance of any products or services;

volatility of the stock market, particularly within the energy sector; and

general economic conditions.

Although we believe the expectations reflected in these forward-looking statements are reasonable, such expectations cannot guarantee future results, levels of activity, performance or achievements.

All forward-looking statements included in this report and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made, other than as required by law, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Oil and Gas Properties

We hold approximately 12,500 gross acres (10,400 acres net) of oil and gas leases in South Texas primarily in the Gonzales County and Wilson County, Texas. We hold oil and gas interests in the Austin Chalk formation (proved and producing), Buda formation (proved and production), and Eagle Ford Shale formation (proved and undeveloped).

We operate thirty (30) producing wells that currently produce approximately 190-200 barrels of oil per day (“BOPD”), gross. Our oil production sales totaled 27,833 barrel oil equivalent, net to our interest for our fiscal year ended March 31, 2010. We operate all of our oil and gas properties with the exception of one property located in Jasper County, Texas.

Hilcorp Energy I, L.P. Purchase and Sale Agreement dated April 1, 2010

On April 1, 2010 Lucas entered into a purchase and sale agreement with HilCorp Energy, I, L.P. (“HilCorp”) for the development of Lucas’ Eagle Ford Shale properties located in Gonzales County, Texas. The agreement provides for HilCorp to acquire an undivided eighty-five (85%) working interest in the “deep rights” held by Lucas in Gonzales County, Texas. On May 5, 2010 Lucas and HilCorp held the first closing with total gross proceeds to Lucas of $7,520,560. The second closing of the “deep rights” sale transaction occurred on June 28, 2010 at which time gross proceeds to Lucas totaled $1,381,270 for total gross proceeds to date of $8,901,830. Net proceeds to Lucas for the first and second closings were $7,492,200, after distribution to Lucas’ working interest participants their proportionate share of proceeds totaling $1,409,630. A third closing of the remainder of the Company’s Eagle Ford Shale rights is expected to occur by the end of July 2010.

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Our agreement with HilCorp provides for us to have a “carried” working interest in the initial two wells drilled by HilCorp on oil and gas properties purchased by them under the April 1, 2010 purchase and sale agreement.

A portion of the proceeds from the May 5, 2010 first closing was used to fully repay and terminate the Amegy Bank Credit Facility. In connection with the repayment Amegy Bank it released all liens and security interests held by Amegy Bank in Lucas’ oil and gas properties.

LEI 2009-II Capital Program

Lucas began the LEI 2009-II capital program in July 2009. There are two working interest participants in the program. One program participant holds an eighty percent (80%) working interest (before payout) in the six well program and bears eighty percent (80%) of the capital costs expended in the program. In connection with the “buy-in” (i.e., “farm-in”) to the capital program, the working interest participant paid Lucas $872,100. The amount paid by the participant to Lucas for its interest in the six wells was reflected by Lucas as a reduction to the full cost pool with no gain or loss reported on the sale. A second participant holds a ten percent (10%) interest. Lucas retained a ten percent (10%) working interest in the program prior to payout, and has an additional ten percent (10%) “back in” after payout to the 80% working interest participant (or a total 20% working interest, after payout). Lucas is the operator of all wells in the program, and five wells are located in Gonzales County, Texas while the sixth well is located in Wilson County, Texas.

Through March 31, 2010, a total of approximately $3,035,000 has been expended in the LEI 2009-II capital program, with Lucas’ share of the capital expenditures totaling approximately $606,900. Commercial sales of crude oil production have occurred from five wells in the program.

LEI 2009-III Capital Program

The LEI 2009-III capital program is comprised of four wells located in Gonzales County and Wilson County, Texas. In November 2009 the principal working interest participant in the LEI 2009-II capital program, agreed to participate in the LEI 2009-III four well program through paying eighty percent (80%) of the capital costs to earn a seventy percent (70%) working interest in the wells. In connection with the working interest participant’s “buy-in” (i.e., “farm-in”) to the four wells they paid Lucas approximately $682,352 for the interest in the wells. The amount paid to Lucas for the interests acquired was reflected as a reduction to the full cost pool with no gain or loss recorded by Lucas on the sale.

Total projected capital expenditures for the LEI 2009-III capital program are approximately $4.3 million. Through March 2010, a total of approximately $366,700 has been expended in the capital program, with Lucas’ share of the capital expenditures totaling approximately $73,300. Fund received by Lucas pursuant to cash calls to the working interest participant in excess of funds expended in the capital program are reflected in Lucas’ financial statement as a current liability – “Advances from working interest owner”.

Acquisition of Oil and Gas Properties Located in Wilson County, Texas

Lucas entered into an agreement to acquire approximately 2,771 gross oil and gas lease acreage (approx. 2,078 acres net to our interest) located in Wilson County, Texas from El Tex Petroleum, LLC (“El Tex”). The leases have eight shut-in or plugged wellbores that the Company believes are good candidates for restoration and revitalization procedures. The leasehold, wellbore and surface equipment acquisition price totaled approximately $1.0 million with $490,000 of the consideration paid through the issuance of Lucas common stock to El Tex (specifically 637,887 shares of common stock at $0.77 per share); Lucas’ assumption of $500,000 in debt plus accrued interest; and remittance of $68,000 in cash.

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One director of Lucas holds an approximate 25.2% interest in El Tex while a second Lucas director holds an indirect beneficial ownership interest of approximately 18.8% in El Tex. Pursuant to NYSE Amex exchange rules, Company shareholders were required to approve the issuance of shares of common stock to El Tex due to the directors holding in the aggregate more than five percent (5%) indirect interest in the assets being acquired by Lucas from El Tex. Additionally, the note holder of the debt assumed by Lucas from El Tex is a director of Lucas and in connection with the Lucas acquisition agreed to convert the debt plus accrued interest due him by El Tex into shares of common stock. Pursuant to NYSE Amex exchange rules Company shareholders were required to approve the issuance of the shares of common stock to the director.

At the Lucas shareholder meeting held on March 30, 2010, the Lucas shareholders approved the issuance of the shares of common stock to El Tex and the issuance of shares of common stock to the Company director in conversion of debt plus accrued interest assumed by Lucas from El Tex. NYSE Amex approved the listing application for the shares to be issued and on May 25, 2010 Lucas issued 637,887 shares of common stock to El Tex and 683,686 shares of common stock to the Lucas director that held the debt assumed by Lucas. The shares of common stock were issued at $0.77 per share which was the fair value of the shares at the time the acquisition was agreed and effected in September 2009.

Three wells acquired by Lucas from El Tex are part of the LEI 2009-III capital program, while one well is part of the LEI 2009-II six well program.

Working Interest Acquisition in Three Previously Non-operated Wells

We held nominal non-operating working interests in three wells located in Gonzales County, Texas (i.e., Rozella Kifer No. 1, Louis Zavadil No. 1 and Ali-O No. 1) of approximately 10% which were operated by Savoy Energy Corporation (“Savoy”). The wells had not produced commercial quantities of production for several months. We have increased our working interest in the wells through the acquisition of an incremental 22.5% from the secured debt holder of one working interest owner’s interests in the wells through the issuance of 220,000 shares of common stock (valued at $165,000), and an incremental 16% from Savoy in exchange for amounts due us by Savoy. In connection with increasing our working interests in the three wells, we assumed operatorship of the wells effective November 1, 2009, and are in the process of restoring the wells to production.

Our capital program is comprised of development activities that involve: (i) drilling of new laterals from existing wells bores in the Austin Chalk formation, (ii) re-entry of shut-in or previously plugged wellbores; and (iii) workovers and stimulations of existing wells. We also will participate in the drilling of the oil and gas acreage purchased by HilCorp, with a “carried interest” in the initial two wells drilled.

A portion of the capital projects we intend to undertake are:

New Laterals in Austin Chalk
		Development		Projected Initial
Well	County	Costs		Production (1)
Barnett, WL 1	Gonzales	$	450,000	100 bbl/day

Shut In & Re-entry Wells
		Development		Projected Initial
Well	County	Costs		Production (1)
Ebrom (Pilarczyk) 1	Wilson	$	135,000	50 bbl/day
Ebrom 1	Wilson	$	90,000	50 bbl/day
Ebrom 1-B	Wilson	$	90,000	50 bbl/day
Gescheidle 1	Gonzales	$	105,000	100 bbl/day
Mills Oil Unit 1	Gonzales	$	15,000	50 bbl/day
Milton Hines No.1	Gonzales	$	330,000	150 bbl/day
Snoga 1	Wilson	$	90,000	100 bbl/day
Snoga A et al	Wilson	$	90,000	100 bbl/day
Valcher Emma 1	Wilson	$	300,000	100 bbl/day
Wall Darden 1	Wilson	$	90,000	50 bbl/day

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Workovers & Stimulations
		Development		Projected Initial
Well	County	Costs		Production (1)
Cone-BuBose Unit	Gonzales	$	8,000	2 bbl/day
Hagen Ranch 3	Gonzales	$	75,000	10 bbl/day
Hines Unit 1	Gonzales	$	23,000	4 bbl/day
Perkins Oil Unit 1	Gonzales	$	75,000	170 bbl/day
Ruddock, Upton 1	Gonzales	$	8,300	4 bbl/day
RVS Oil Unit No. 1	Gonzales	$	5,000	2 bbl/day

(1) Initial production is calculated at 8/8th interest.

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Results of Operations

The following table sets forth the revenue and production data for continuing operations for the two most recent fiscal years ended March 31, 2010 and 2009.

	For the Year Ended March 31,						Amount Increase/			% Increase/
	2010			2009			(Decrease)			(Decrease)

OIL AND GAS REVENUES:	$	1,777,736		$	3,382,060		$	1,604,324	)		-47	%

PRODUCTION SALES:
Oil (barrels)		26,858			41,309			(14,451	)		-35	%
Natural gas (thousand cubic feet)		5,849			7,505			(1,656	)		-22	%
Total (barrels oil equivalent)		27,833			42,560			(14,727	)		-35	%

Oil (barrels per day)		74			113			(40	)		-35	%
Natural gas (thousand cubic feet per day)		16			21			(5	)		-24	%
Total (barrels oil equivalent per day)		76			117			(40	)		-35	%

AVERAGE SALES PRICES:
Oil (per barrel)	$	65.60		$	80.82		$	(15.22	)		-19	%
Natural gas (per thousand cubic feet)	$	2.73		$	5.77		$	(3.04	)		-53	%

Lease operating expenses		1,048,333			1,345,928			(297,595	)		-22	%
Severance and property taxes		129,432			171,688			(42,256	)		-25	%
Depreciation, depletion, and amortization		787,340			899,949			(112,609	)		-13	%
General and administrative		1,690,170			1,594,598			95,572			6	%

Total Expenses		3,655,275			4,012,163			(356,888	)		-9	%

LOSS FROM OPERATIONS		(1,877,539	)		(630,103	)		(1,247,436	)		198	%

OTHER INCOME (EXPENSES)
Unrealized loss on investments		(110,606	)		(2,095,019	)		1,984,413			-95	%
Realized loss on investments, net		(30,785	)		(121,273	)		94,488			-75	%
Interest income		-			1,970			(1,970	)		-100	%
Interest expense		(301,787	)		(89,193	)		(212,594	)		238	%
Total Other Income (Expenses)		(443,178	)		(2,303,515	)		1,860,337			-81	%

NET INCOME BEFORE INCOME TAXES		(2,320,717	)		(2,933,618	)		612,901			-21	%

INCOME TAX BENEFIT		-			(834,127	)		(834,127	)		-100	%

NET LOSS	$	(2,320,717	)	$	(2,099,491	)	$	(221,226	)		11	%

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For the Year Ended March 31, 2010 Compared to the Year Ended March 31, 2009

Management Analysis of Operation

Results of Operations:

Oil and Gas Revenue

The $1,604,324 decrease in our oil and gas revenues during the year ended March 31, 2010 was primarily attributable to a decline of $15.22 per barrel (19%) in the price realized for oil sales and a 14,451 barrel (35%) decrease in barrels of oil sold during the current year as compared to the prior fiscal year ended March 31, 2009. The decrease in oil volumes sold was due to lower production levels during the current fiscal year as compared to the prior year. The lower production levels during the current period is the result of wells being down for work-over and treatments, and our allocation of discretionary expenditures to our capital expenditure requirements associated with the LEI 2009-II and LEI 2009-III capital programs.

Lease Operating Expenses

Lease operating expenses decreased by $297,595 during the year ended March 31, 2010 as compared to the prior year period principally due to: reductions in work-over and treatment costs; reductions in variable costs of production (e.g., fuel and water hauling) reflecting the lower levels of oil production; and attention and discretionary resources being directed to the LEI 2009-II and III capital programs.

General and Administrative Expenses

General and administrative expenses increased $95,572 for the year ended March 31, 2010 as compared to the prior period primarily due to reductions in field administration expenses, professional fees and stock based compensation offset with higher costs for investor awareness initiatives.

Depreciation, Depletion, Amortization and Accretion (“DD&A”)

DD&A decreased $112,609 primarily due to a decrease of 14,727 barrels of oil equivalent in production sales for the year ended March 31, 2010 as compared to the prior year period primarily resulting from lower production during the current year; partially offset by an increase in the DD&A rate per unit of production of $26.28 per barrel oil equivalent as compared to $20.56 barrel oil equivalent for the prior year.

Unrealized and Realized Losses

The unrealized loss on investments for the year ended March 31, 2010 of $110,606 is due to the mark-to-market accounting for shares held by Lucas in Bonanza Oil and Gas, Inc. The unrealized loss compares to a net unrealized loss totaling $2,095,019 for the same period ended March 31, 2009 on shares of common stock held in Bonanza that were the result of mark-to-market accounting for Bonanza shares held by Lucas. Lucas sold 1,516,000 shares of Bonanza common stock during the current year period with cash proceeds of $92,495, and 1,000,000 shares of Bonanza common stock was transferred to a consultant for services valued at $38,000. In the aggregate we had a total realized loss of $30,785 for the current fiscal year. No sales of Bonanza shares of common stock were made during the same period in the prior year.

We reported a realized loss totaling $30,785 for the year ended March 31,2010 as compared to a realized loss of $121,273 for the prior year ended March 31, 2009. The prior year realized loss was the result of a May 2008 purchase of six commodity contracts that were linked to NYMEX crude oil futures contracts. The loss was realized at the time the contracts were closed out. Lucas did not hold any similar contracts during the current year period.

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Interest Expense

Interest expense increased by $212,594 due to interest, commitment fees and other fees associated with the Amegy Credit Facility executed in October 2008. On May 5, 2010, Lucas paid off the outstanding balance under the Amegy Credit Facility, and terminated the credit agreement.

Interest Income

Interest income for the current year ended was -$0- compared to $1,970 for the prior year ended. The interest income for the prior year was earnings on cash raised in a September 2007 private equity placement that remained to be expended as of March 31, 2008.

Income Tax Expense

Income tax expense was zero for the current period compared to a tax benefit of $834,127 for the same period in the prior year. The prior year tax benefit was the result of expected future reductions to income tax liability for the net loss for the prior year period and the associated reduction in deferred income taxes. Current year tax benefits from operating losses have been fully reserved in our valuation allowance.

Net Loss

The $221,226 increase in the net loss for the current year as compared to the prior year is primarily attributable to the $1,984,413 decrease in the unrealized loss on Bonanza shares of common stock between the current year and the prior year, and the reduction of $1,604,324 in revenues from oil and gas sales a reduction of $297,595 in lease operating costs offset with the $834,127 income tax benefit in the prior year due to a reduction in deferred income taxes due to the net loss in the prior year.

Liquidity and Capital Resources

From the end of our prior fiscal year of March 31, 2009 to March 31, 2010, our cash increased by $1,685,939 with cash at March 31, 20109 totaling $1,822,780. With the inclusion of the total outstanding principal balance on the Amegy Credit Facility totaling $2,150,000 classified as a current liability, we had negative working capital at March 31, 2010 of $$4,149,283. At March 31, 2009, our negative working capital totaled $513,240, which included $300,000 of the then total outstanding balance under the Credit Facility with Amegy of $2,650,000.

During the year ended March 31, 2010, we raised approximately $1.6 million in proceeds through working interest buy-in participation in our LEI 2009-II and LEI 2009-III capital programs and sales of interests in four non producing or marginally producing wellbores that did not meet our technical screening requirements for inclusion in our future drilling and development programs. We also received net proceeds of $277,500 from private equity placements. We used $500,000 to reduce the outstanding principal balance on our Credit Facility with Amegy Bank. On May 5, 2010 we repaid the outstanding balance on the Credit Facility and terminated Facility.

We anticipate that cash flows from operating activities; proceeds from the farm-out of 85% of Eagle Ford formation deep rights in Gonzales County, Texas; equity placements under our S-3 shelf registration through at-the-market public placements; and cash on hand will be sufficient to repay the $2.15 million outstanding balance of our Amegy credit facility, fund our capital expenditure requirements for our interests in the LEI 2009-II and 2009-III capital programs, and cover our operating and general and administrative requirements for our fiscal year ended March 31, 2011. Additionally, we expect to fund our oil and gas capital expenditure requirements through a combination of joint venture arrangements, working interest participants’ buy-in to existing wells and programs, and other sources of capital such as private equity and debt placements, public offerings, and traditional reserve based financing and credit facilities.

We currently have no definitive agreements or arrangements for additional funding, and financings could result in significant dilution to our shareholders or not be available on acceptable terms in the time frame necessary, or may not be available or acceptable to us at all.

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Cash flow from operating activities

For the year ended March 31, 2010, net cash used in operating activities was $717,967 compared to net cash provided from operating activities of $581,929 for the prior year ended. The $1,299,896 decrease in net cash was primarily due to a decline in revenues for the current year compared to the prior year.

Cash flow from investing activities

For the year ended March 31, 2010 net cash used in investing activities was $298,974 compared to net cash used in investing activities for the prior year of $3,921,369. Cash provided by investing activities was principally derived from the sale of working interests in connection with the LEI 2009-II and 2009-III capital programs. Cash used in investment activities declined to due to a scaling back and reduction in capital expenditures associated with our oil and gas properties as the price for crude oil declined.

Cash flow from financing activities

For the year ended March 31, 2010, net cash flow provided by financing activities was $2,702,880. Funds provided by financing activities were associated with advances from working interest owners totaling $2,305,292, short term borrowings of $740,000 and $277,500 raised through a private equity placement. Funds totaling $500,000 were used to reduce the outstanding principal balance on the Amegy Bank Credit Facility during the year ended March 31, 2010.

Hedging

We did not hedge any of our oil or natural gas production during fiscal 2010 or 2009 and have not entered into any such hedges from March 31, 2010 through the date of this filing.

Contractual Commitments

None

Off-Balance Sheet Arrangements

As of March 31, 2010, we had no off-balance sheet arrangements.

Related Party Transactions

As discussed under the “Nature of Operations – Acquisition of Oil and Gas Properties Located in Wilson County, Texas” one Lucas board of director member (J. Fred Hofheinz) holds an approximate 25.2% interest in El Tex Petroleum, LLC (the “El Tex”) while a second Lucas board of director member (W. Andrew Krusen, Jr.) holds an indirect beneficial ownership interest in the Seller of approximately 18.8%. We entered into an agreement to acquire approximately 2,771 gross oil and gas lease acreage (approx. 2,078 net to our interest) located in Wilson County, Texas. The leasehold, wellbore and surface equipment acquisition price totals approximately $1.0 million with approximately $490,000 of the consideration comprised from the issuance of Lucas common stock to El Tex (specifically 637,887 shares of common stock at $0.77 per share), assumption of $500,000 in debt and $68,000 in cash. Pursuant to NYSE Amex exchange rules, issuance of shares of common stock in connection with the acquisition of the oil and gas properties from El Tex requires shareholders’ approval. Lucas shareholders approved the share issuance in the annual shareholder meeting held on March 30, 2010. Upon exchange approval of the listing application for the shares to be issued, the shares of common stock were issued on May 25, 2010.

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities and expenses. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

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In February 2007, the Financial Accounting Standards Board (“FASB”) issued ASC 825 “Financial Instruments.” This pronouncement permits entities to use the fair value method to measure certain financial assets and liabilities by electing an irrevocable option to use the fair value method at specified election dates. After election of the option, subsequent changes in fair value would result in the recognition of unrealized gains or losses as period costs during the period the change occurred. ASC 825 becomes effective as of the beginning of the first fiscal year that begins after November 15, 2007, with early adoption permitted. However, entities may not retroactively apply the provisions of ASC 825 to fiscal years preceding the date of adoption. We are currently evaluating the impact that ASC 825 may have on our financial position, results of operations or cash flows.

In December 2008, the SEC released Final Rule, “Modernization of Oil and Gas Reporting .” The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require that companies 1) report the independence and qualifications of its reserves preparer or auditor, 2) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit, 3) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new disclosure requirements are effective for financial statements for fiscal years ending on or after December 31, 2009. Early adoption is not permitted. We are currently assessing the impact, if any, that the adoption of the pronouncement will have on our operating results, financial position or cash flows.

In June 2009, the FASB issued ASC 105-10 “Generally Accepted Accounting Principles.” ASC 105-10 will become the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under the authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date, ASC 105-10 will supersede all then existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in ASC 105-10 will become non-authoritative. ASC 105-10 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of ASC 105-10 did not impact our results of operations or financial condition.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Not applicable.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Our consolidated financial statements as of March 31, 2010 and 2009 and for the fiscal years ended March 31, 2010 and 2009 have been audited by GBH CPAs, PC, an independent registered public accounting firm, and have been prepared in accordance with generally accepted accounting principles pursuant to Regulation S-X as promulgated by the SEC. The aforementioned financial statements are included herein starting with page F-1.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) are designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures.

Evaluation of Disclosure Controls and Procedures

In connection with the preparation of this Annual Report on Form 10-K, our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, carried out an evaluation of the effectiveness of our disclosure controls and procedures as of March 31, 2010, as required by Rule 13a-15 of the Exchange Act. Based on the evaluation described above, our management, including our principal executive officer and principal financial officer, has concluded that, as of March 31, 2010, our disclosure controls and procedures were effective.

We concluded that the consolidated financial statements in this Annual Report on Form 10-K present fairly, in all material respects, the Company’s financial condition, results of operations and cash flows for the year ended March 31, 2010 in conformity with U.S. generally accepted accounting principals (“GAAP”).

Management’s Report on Internal Control over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting is a process designed under the supervision of our principal executive and principal financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

Due to inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable, not absolute, assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate as a result of changes in conditions or deterioration in the degree of compliance.

Under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of March 31, 2010 based on the criteria framework established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on the assessment, our management has concluded that our internal control over financial reporting was effective as of March 31, 2010.

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

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Changes in Internal Control Over Financial Reporting.

There have not been any changes in our internal control over financial reporting during the year ended March 31, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10 DIRECTORS, EXECUTIVE OFFICERS, and CORPORATE GOVERNESS

The following table sets forth the names, ages, and offices held by our directors and executive officers:


Name	Position	Date First Elected	Age
J. Fred Hofheinz	Chairman of Board	September 18, 2008	72
William A. Sawyer	Chief Executive Officer, Director	April 6, 2005	62
Donald L. Sytsma	Chief Financial Officer, Treasurer	April 14, 2009	52
Peter K. Grunebaum	Director	January 29, 2007	76
W. Andrew Krusen, Jr.	Director	October 8, 2009	62

Information Concerning the Board of Directors and its Committees.

All directors hold office until the next annual meeting of stockholders and until their successors have been duly elected and qualified. There are no agreements with respect to the election of directors. We have historically compensated our directors for service on the Board of Directors and committees thereof through the issuance of shares of common stock and nominal cash compensation for meeting fees. Additionally, we reimburse directors for expenses incurred by them in connection with the attendance at meetings of the Board and any committee thereof. The Board of Directors appoint annually the executive officers of the Company and the executive officers serve at the discretion of the Board. The Executive Committee of the Board of Directors, to the extent permitted under Nevada law, exercises all of the power and authority of the Board in the management of the business and affairs of the Company between meetings of the Board.

The business experience of each of the persons listed above during the past five years is as follows:

FRED J. HOFHEINZ, CHAIRMAN OF BOARD, Chair of Nominating Committee

Mr. Hofheinz, the former Mayor of the City of Houston (1974-1978), began his business career with his late father, Roy Hofheinz, Sr., who built the Houston Astrodome. Mr. Hofheinz played a key role in the family real estate development projects surrounding the Astrodome, including an amusement park – Astroworld and four hotels. He was the senior officer of Ringling Brothers Barnum and Bailey Circus, which was owned by the Hofheinz family. In 1971, Mr. Hofheinz co-founded a closed circuit television company, Top Rank, which is now the leading professional boxing promotion firm in the nation. He has served as President of the Texas Municipal League and served on the boards of numerous other state and national organizations for municipal government elected officials. In addition to his law practice, Mr. Hofheinz also owned several direct interests in oil and gas companies. He has also dealt extensively with business interests, primarily oil and gas related, in the People’s Republic of China and in the Ukraine.

For the past five years Mr. Hofheinz has been an investor and a practicing attorney with the firm of Williams, Birnberg & Anderson LLP in Houston, Texas, and the city that he served as mayor from 1974 to 1978. While he has numerous investments in real estate, his principal investment interest is in oil and gas. He has been actively engaged in successful exploration and production ventures, both domestic and international. He holds a PhD in economics, from the University of Texas and takes an active interest in Houston’s civic and charitable affairs. He was admitted to the Texas bar in 1964, having received his preparatory education at the University of Texas, (B.A., M.A., Ph.D., 1960-1964); and his Legal education at the University of Houston, (J.D., 1964).

WILLIAM A. SAWYER, DIRECTOR, PRESIDENT AND CHIEF EXECUTIVE OFFICER

Mr. Sawyer has been a director of the Company since April 6, 2005. Mr. Sawyer has over 30 years of diversified experience in the energy industry with firms such as; ARCO, Houston Oil & Minerals, Superior Oil (Mobil), and ERCO. Mr. Sawyer founded the petroleum consulting firm of Exploitation Engineers, Inc. and his clients included private investors, independent oil companies, banking institutions, major energy and chemical companies, and the US government. In connection with Exploitation Engineers, Mr. Sawyer evaluated and managed large projects such as a private trust that held working interests in several hundred producing and non-producing oil and gas properties. Mr. Sawyer has been an expert witness in federal court, state court, and before several state agencies in Texas and Oklahoma, and he has testified as to the fair market value of mineral interests and sub-surface storage interests. Mr. Sawyer co-founded the Company and was originally appointed to a position with the Company on June 13, 2006. Mr. Sawyer has served as a Director of the Company and as its chief operating officer, until his appointment to president and chief executive officer on January 22, 2009.

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PETER K. GRUNEBAUM – DIRECTOR, Chair of Audit Committee

Mr. Grunebaum is an independent investment banker with over 40 years of experience in the energy sector with a specialty in exploration and production. Previously he was the Managing Director of Fortrend International, an investment firm headquartered in New York, New York, a position he held from 1989 until the end of 2003. From 2003 to present, Mr. Grunebaum has been an independent investment banker. Mr. Grunebaum is a graduate of Lehigh University, and in addition to being a board member of Lucas, he is also on the Board of Prepaid Legal Services, Inc. [NYSE:PPD] and Stonemor Partners LP. [NASDAQ: STON].

W. ANDREW KRUSEN, JR. – DIRECTOR, Chair of the Compensation Committee

Mr. Krusen has been Chairman and Chief Executive Officer of Dominion Financial Group, Inc. since 1987. Dominion Financial is a merchant banking organization that provides investment capital to the natural resources, communications and manufacturing and distribution sectors. Mr. Krusen is currently a director and chairman of Florida Capital Group, Inc. – a Florida bank holding company, as well as Florida Capital Bank, N.A. its wholly owned subsidiary. He also serves as a director of publicly traded Highpine Oil and Gas Ltd., a Canadian oil and gas concern; and Raymond James Trust Company, a subsidiary of Raymond James Financial, Inc. – and numerous privately held companies, including Beall’s Inc., Telovations, Inc., CoAdvantage Resources, Inc. and Romark Laboratories, LLC. Mr. Krusen is a former member of the Young Presidents’ Organization, and he is currently a member of the World President’s Organization, Society of International Business Fellows and a Trustee of the International Tennis Hall of Fame. He is past Chairman of Tampa's Museum of Science and Industry and a member of the Florida Council of 100. Mr. Krusen graduated from Princeton University in 1970.

DONALD L. SYTSMA, CHIEF FINANCIAL OFFICER, AND TREASURER

Mr. Sytsma was appointed Chief Financial Officer and Treasurer of the Company on April 14, 2009, and he serves as the principal accounting and financial officer for the Company. From January 2005 to October 2008, Mr. Sytsma was a director, Treasurer and Chief Financial Officer of Gulf Western Petroleum (formerly Wharton Resources). Since April 2003, Mr. Sytsma has been president of DLS Energy Associates, LLC, an independent consulting company. From November 2003 to June 2005, Mr. Sytsma was Chief Financial Officer of Altus, and from November 2003 through February 2006, Mr. Sytsma was a director of Altus. From May 2001 to April 2003, Mr. Sytsma was Vice-President of R.J. Rudden Associates. Mr. Sytsma has over 25 years’ experience in the energy industry in the upstream midstream and downstream segments. Mr. Sytsma received his bachelor’s of science in accounting from Indiana University in May 1979 with highest distinction. Mr. Sytsma is a former Executive Committee Member of the North America Energy Standards Board and Co-Chaired multiple industry subcommittees, developing standards for the U.S. energy markets. Mr. Sytsma is a certified public accountant.

There are no family relationships among our directors or our executive officers. No director or executive officer has been a director or executive officer of any business which has filed a bankruptcy petition or had a bankruptcy petition filed against it.

DIRECTOR INDEPENDENCE

During the year ended March 31, 2010, the Board has determined that a majority of the Board is independent under the definition of independence and in compliance with the listing standards of the NYSE Amex listing requirements. Based upon these standards, the Board has determined that all of the directors are independent, with the exception of Mr. Sawyer, our President and Chief Executive Officer.

MEETINGS AND COMMITTEES OF THE BOARD OF DIRECTORS

During the fiscal year that ended on March 31, 2010, the Board held four meetings. All directors attended all meetings of the Board and all committee meetings on which the Director served during fiscal year 2010. All of the current directors attended our fiscal year 2009 annual shareholder meeting held on March 30, 2010.

The Board has a standing Audit Committee, Compensation Committee, and Nominating Committee.

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The Audit Committee currently consists of Mr. Grunebaum (chair), Mr. Hofheinz and Mr. Krusen, each of whom is independent as defined in Section 803(A) of the NYSE Amex LLC Company Guide. The Audit Committee’s function is to provide assistance to the Board in fulfilling the Board’s oversight functions relating to the integrity of the Company’s financial statements, the Company’s compliance with legal and regulatory requirements, the independent auditor’s qualifications and independence and the performance of the Company’s independent auditors, and perform such other activities consistent with its charter and our By-laws as the Committee or the Board deems appropriate. The Audit Committee produces an annual report for inclusion in our proxy statement. The Audit Committee is directly responsible for the appointment, retention, compensation, oversight and evaluation of the work of the independent registered public accounting firm (including resolution of disagreements between our management and the independent registered public accounting firm regarding financial reporting) for the purpose of preparing or issuing an audit report or related work. The Audit Committee shall review and pre-approve all audit services, and non-audit services that exceed a de minims standard, to be provided to us by our independent registered public accounting firm. The Audit Committee carries out all functions required by the NYSE AMEX, the SEC and the federal securities laws. The Board has determined that Mr. Grunebaum, Mr. Hofheinz and Mr. Krusen are “independent,” and at least one member is an “audit committee financial expert” as defined in the SEC’s Regulation S-K, Item 407(d). During fiscal year 2010, the Audit Committee held four meetings. The Audit Committee’s charter is available on our website at www.lucasenergy.com.

The Compensation Committee is comprised of Mr. Krusen (chair), Mr. Grunebaum and Mr. Hofheinz, each of whom is independent as defined in Section 803(A) of the NYSE Amex LLC Company Guide. The purpose of the Compensation Committee is to oversee the responsibilities relating to compensation of our executives and produce a report on executive compensation for inclusion in our proxy statement. The Compensation Committee may delegate its authority to subcommittees of independent directors, as it deems appropriate. During fiscal year 2010, the Compensation Committee held four meetings. The Compensation Committee’s charter is available on our website at www.lucasenergy.com.

The Nominating Committee is comprised of Mr. Hofheinz (chair), Mr. Grunebaum and Mr. Krusen, each of whom is independent as defined in Section 803(A) of the NYSE Amex LLC Company Guide. This Committee is responsible for (1) establishing criteria for selection of new directors and nominees for vacancies on the Board, (2) approving director nominations to be presented for shareholder approval at the Company annual meeting, (3) identifying and assisting with the recruitment of qualified candidates for Board membership and for the positions of Chairman of the Board and Chairmen of the committees of the Board, (4) recommending to the Board to accept or decline any tendered resignation of a director, (5) considering any nomination of director candidates validly made by shareholders, (6) reviewing any director conflict of interest issues and determining how to handle such issues, (7) insuring a review of incumbent directors’ performance and attendance at Board and committee meetings in connection with the independent directors’ decision regarding directors to be slated for election at the Company’s annual meeting, (8) providing appropriate orientation programs for new directors, (9) reviewing and assessing the adequacy of the Company’s corporate governance policies and practices and recommending any proposed changes to the Board, and (10) proposing any necessary actions to the Board. We have not paid any third party a fee to assist in the process of identifying and evaluating candidates for director. During fiscal year 2010, the Nominating Committee held one meeting. The Nominating Committee’s charter is available on our website at www.lucasenergy.com.

COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT

Section 16(a) of the Exchange Act requires our directors and officers, and the persons who beneficially own more than ten percent of our common stock, to file reports of ownership and changes in ownership with the SEC. Copies of all filed reports are required to be furnished to us pursuant to Rule 16a-3 promulgated under the Exchange Act. Except as described below and based solely on the reports received by us and on the representations of the reporting persons, we believe that all complied with all applicable filing requirements during the fiscal year ended March 31, 2010.

CODE OF ETHICS

The Company adopted a code of ethics (“Code”) that applies to all of its directors, officers, employees, consultants, contractors and agents of the Company. The Code of Ethics has been reviewed and approved by the Board of Directors. The Company’s Code of Ethics is incorporated by reference to the Form 10-K dated March 31, 2009 filed with the SEC on June 29, 2009 as Exhibit 14.1. Original copies of the Code of Ethics are available, free of charge, by submitting a written request to the Company at 3555 Timmons Lane, Suite 1550, Houston, Texas 77027.

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WHISTLEBLOWER PROTECTION POLICY

The Company adopted a Whistleblower Protection Policy (“Policy”) that applies to all of its directors, officers, employees, consultants, contractors and agents of the Company. The Whistleblower Policy has been reviewed and approved by the Board of Directors. The Company’s Whistleblower Policy is incorporated by reference to the Form 10-K dated March 31, 2009 filed with the SEC on June 29, 2009 as Exhibit 14.2. Original copies of the Whistleblower Policy are available, free of charge, by submitting a written request to the Company at 3555 Timmons Lane, Suite 1550, Houston, Texas 77027.

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ITEM 11. EXECUTIVE COMPENSATION

The following table sets for compensation information with respect to our chief executive officer, our highly compensated executive officers at the end of our fiscal year, and individuals for whom disclosure would have been provided herein but for the fact they were not serving as an executive officer of the Company at the end of our fiscal year.

Summary Compensation Table

Name and Principal Position	Fiscal Year	Salary ($)		Stock Awards ($)		Option Awards ($)		All Other Comp ($)		Total ($)

William A. Sawyer (1) (2) (3)	2010	$	162,250	$	29,000	$	-	$	6,000	$	197,250
President and	2009		150,000		-		-		2,000		152,000
Chief Executive Officer

Donald L. Sytsma (1) (4)	2010	$	120,000	$	22,677	$	-	$	4,000	$	146,677
Chief Financial Officer	2009		-		-		-		-		-

James J. Cerna, Jr. (2)	2010	$	58,333	$	-	$	-	$	-	$	58,333
Former Chairman, President and	2009		153,125		-		-		2,000		155,125
Chief Executive Officer

William A. Sikora (2) (5)	2010	$	-	$	-	$	-	$	-	$	-
Former President and	2009		63,736		8,846		267,083		2,000	$	341,665
Chief Executive Officer

Malek A. Bohsali (2) (6)	2010	$	-	$	25,000	$	-	$	-	$	25,000
Former Chief Financial Officer	2009		37,250		25,000		-		2,000		64,250

(1)	During the fiscal year ended March 31, 2010 Mr. Sawyer as Director was paid $6,000 for attendance at three Board of Directors meeting, and Mr. Sytsma as chief financial officer and corporate secretary was paid $4,000 for attendance at Board meetings.

(2)	During the fiscal year ended March 31, 2009 Messrs Sawyer, Cerna and Sikora as Company Directors were paid $2,000 for attendance at a Board meeting. Mr. Bohsali was paid $2,000 for attending the Board meeting.

(3)	Stock award granted to Mr. Sawyer of 50,000 shares of common stock for Lucas’ joint venture partner’s commitment to and initial funding of their 70% working interest in the LEI 2009-III capital program. Fair value of shares on date earned was $0.58 per share for total stock award of $29,000.

(4)

Mr. Sytsma appointed chief financial officer and treasurer effective April 14, 2009. In addition monthly cash compensation, Mr. Sytsma’s employment arrangement with Company includes a non-cash compensation component of 2,000 shares of common stock per month. Company closing share price on date Mr. Sytsma appointed chief financial was $0.56 per share. The fair value of shares earned is determined based on closing share price on last trading day of each month.

(5)

Mr. Sikora was appointed President and Chief Executive Officer of the Company on September 2, 2008, pursuant to an employment agreement dated thereof and incorporated by reference to the Form 8-K dated September 2, 2008 that was filed with the Securities and Exchange on September 4, 2008. Mr. Sikora was elected a Director on November 18, 2008. Pursuant to the employment agreement, Mr. Sikora’s initial year base salary was set at $125,000; he was granted non-qualified stock options to purchase 200,000 shares of the Company common stock at $2.60 per share that vested over two years; and he was to receive 19,230 shares of Company common stock. On January 22, 2009, Mr. Sikora’s services with the Company ended and in accordance with the referenced employment agreement the options became fully vested. At the time the options were issued to Mr. Sikora they were valued at $267,083 using the Black-Sholes Option Pricing Model and the entire fair value of the options were recognized by the Company upon the termination of services. Additionally the Company issued 19,230 shares of restricted common stock to Mr. Sikora that were valued at $8,846 at the time of issuance by the Company.

(6)	Mr. Bohsali served as Chief Financial Officer of the Company from April 10, 2007 through April 14, 2009.

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Compensation of Named Executive Officers

William A. Sawyer

Mr. Sawyer co-founded the Company and was originally appointed to a position with the Company on June 13, 2006. Mr. Sawyer has served as a Director of the Company and as its chief operating officer, until his appointment to president and chief executive officer on January 22, 2009. On March 20, 2007, the Company entered into an employment agreement with Mr. Sawyer (filed as exhibit 10.6 to the Company's Annual Report on Form 10-KSB for the year ended March 31, 2007). Mr. Sawyer’s agreement was for a period of three (3) years and provided for payment of $150,000 annually. Additionally, Mr. Sawyer’s employment agreement provided for certain payments in the event termination of employment. Effective October 1, 2009 the Compensation Committee approved an increase to Mr. Sawyer’s base compensation to $162,000 per annum. Mr. Sawyer’s employment agreement terminated on March 20, 2010.

Donald L. Sytsma

Mr. Sytsma was appointed Chief Financial Officer and Treasurer of the Company on April 14, 2009, and he serves as the principal accounting and financial officer for the Company. Mr. Sytsma’s current compensation arrangement with the Company provides for a salary of $11,000 per month for services as required by the Company, plus 2,000 shares of Company common stock per month agreed to as a material inducement to entering into Mr. Sytsma’s employment with the Company.

James J. Cerna, Jr.

Mr. Cerna co-founded the Company and was originally appointed a Director and chief executive officer of the Company on May 19, 2006, and he was appointed as president on June 12, 2006. On September 2, 2008, Mr. Cerna transferred his duties as president and chief executive officer to Mr. Sikora and continued his role as Chairman of the Board of Directors. On May 5, 2009 Mr. Cerna’s resigned as Chairman and as a member of the Board. On March 20, 2007, the Company entered into employment agreement with Mr. Cerna (filed as exhibits 10.5 to the Company's Annual Report on Form 10-KSB for the year ended March 31, 2007). Mr. Cerna's agreement is for a period of 3 years and provides for payment of $175,000 annually in exchange for services to the Company. The agreement also provides for certain payments in the event termination of employment. In connection with Company initiatives to scale back costs in response to low oil prices during our 4th fiscal quarter, Mr. Cerna agreed to suspend payment of his compensation under his employment agreement. Mr. Cerna and the Company are in active discussions as to the settling up of amounts provided for in his referenced employment agreement. Pursuant to an oral agreement, effective August 1, 2009 the Company commenced remitting one-half (½) of the monthly compensation provided for in his employment agreement on a semi-monthly basis, or $7,292 per month, until the remaining amount due under his employment agreement is paid.

William A. Sikora

Mr. Sikora was appointed President and Chief Executive Officer of the Company on September 2, 2008, pursuant to an employment agreement dated thereof and incorporated by reference to the Form 8-K dated September 2, 2008 that was filed with the Securities and Exchange on September 4, 2008. Pursuant to the employment agreement, Mr. Sikora’s initial year base salary was set at $125,000; he was granted non-qualified stock options to purchase 200,000 shares of the Company common stock at $2.60 per share that vested over two years; and he was to receive 19,230 shares of Company common stock. On January 22, 2009, Mr. Sikora’s services with the Company ended and in accordance with the referenced employment agreement the options became fully vested. At the time the options were issued to Mr. Sikora they were valued at $267,083 using the Black-Sholes Option Pricing Model and the entire fair value of the options was recognized by the Company upon the termination of services. Additionally the Company issued 19,230 shares of restricted common stock to Mr. Sikora that were valued at $8,846 at the time of issuance by the Company.

Malek A. Bohsali

Mr. Bohsali served as chief financial officer of the Company from April 10, 2007 through April 14, 2009, and served as corporate secretary of the Company until his resignation effective September 30, 2009. Mr. Bohsali received compensation listed in the above compensation table.

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Other resources utilized in the Company’s operations are typically contractors or sub-contractors of vendors and service providers that are not owned directly or indirectly by the Company or any officer, director or shareholder owning greater than five percent (5%) of our outstanding shares, nor are they members of the referenced individual’s immediate family. Such sub-contracting engagement and per job payments are commonplace in the Company's business. The Company expects to continue to utilize and pay such service providers and third party contractors necessary to operate its day-to-day field operations.

Lucas 2010 Incentive Compensation Plan

The Company shareholders approved the Lucas Energy, Inc. 2010 Long Term Incentive Plan (“Incentive Plan” or “Plan”) at the annual shareholder meeting held on March 30, 2010. The Incentive Plan provides the Company with the ability to offer stock options and restricted stock to employees, consultants and contractors as performance incentives. Shares issuable under the Incentive Plan were registered on Form S-8 registration statement that was filed with the SEC on April 23, 2010. The NYSE Amex approved this listing application for the shares issuable under the Incentive Plan on May 6, 2010. At March 31, 2010 no shares had been issued under the Incentive Plan.

Under the Incentive Plan, 900,000 shares of the Company’s common stock are authorized for initial issuance. The number of shares available under the Plan are reduced by one for each share delivered pursuant to an award under the Plan. Any issued shares that become available due to expiration, forfeiture, surrender, cancellation, termination or settlement in cash of an award under the Incentive Plan may be requested and used as part of a new award under the Plan.

The Plan is administered by the Compensation Committee of the Board of Directors. The Committee interprets the Plan and has broad discretion to select the eligible persons to whom awards will be granted, as well as the type, size and terms and conditions of each award, including the exercise price of stock options, the number of shares subject to awards, the expiration date of awards, and the vesting schedule or other restrictions applicable to awards. The Plan allows the Company to grant the following types of awards: (1) incentive stock options, (2) non-qualified stock options, and (3) restricted shares.

Outstanding Equity Awards at March 31, 2010

At the end of the Company’s fiscal year end, outstanding equity awards for issued and unexercised stock option awards are identified in the following table. There are no outstanding equity awards that are unexercisable at the fiscal year ended March 31, 2010.

Outstanding Equity Awards at 2010 Fiscal Year End

Name

Number of securities underlying unexercised options (#) exercisable

Number of securities underlying unexercised options (#) unexercisable

Option exercise price ($)

Option expiration date

William A. Sikora

200,000

2.60

9/02/2011

The Company does not currently have in place or provide retirement, disability or other benefits to its employees.

DIRECTOR COMPENSATION

The following table sets for compensation information with respect to our directors during our fiscal year ended March 31, 2010.

Director Compensation
Name	Fees earned or paid in cash ($)		Stock awards ($)		Total ($)

Peter K. Grunebaum	$	6,000	$	-	$	6,000
J. Fred Hofheinz		6,000		-		6,000
W. Andrew Krusen		6,000		-		6,000

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Non employee and employee directors are paid $2,000 per meeting attended. Non-employee directors were paid $6,000 in cash for meeting fees during the fiscal year ended March 31, 2010. Non-employee directors have historically been granted shares of common stock for services provided to the Company as a director.

Compensation for serving as a director for an individual that is a named executive officer is reflected in the above table on Executive Compensation.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCK

The following table sets forth information, to the best of our knowledge as of March 31, 2010, with respect to each person known by us to own beneficially more than 5% of our outstanding common stock, and each director and officer, and all directors and officers as a group.

Security Ownership of Certain Beneficial Owners.

Title of Class	Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership	Percent of Class
			(*)
Common	J. Fred Hofheinz Chairman 3555 Timmons Lane, Suite 1550 Houston, Texas 77027	792,020	5.73%
Common	William A. Sawyer Chief Executive Officer and Director 3555 Timmons Lane, Suite 1550 Houston, Texas 77027	333,474	2.41%
Common	W. Andrew Krusen, Jr. Director 3555 Timmons Lane, Suite 1550 Houston, Texas 77027	455,000 (1)	3.29%
Common	Peter Grunebaum Director 3555 Timmons Lane, Suite 1550 Houston, Texas 77027	100,229	0.73%
Common	Donald L. Sytsma Chief Financial Officer and Treasurer 3555 Timmons Lane, Suite 1550 Houston, Texas 77027	29,500	0.21%
Common	LGA, Inc. 377 S. Nevada St. Carson City, Nevada 89703	1,318,700	9.68%
Common	James J. Cerna Jr. Former Chairman, CEO and President Revocable Trust 3555 Timmons Lane, Suite 1550 Houston, Texas 77027	613,098	4.50%
Common	ALL EXECUTIVE OFFICERS AND DIRECTORS AS A GROUP (5 Persons)	1,710,223	12.37%

(*)	Calculated based on total shares outstanding of 13,622,869 plus warrants exercisable into shares of common stock within 60 days.

(1)	Includes indirect beneficial ownership of 200,000 warrants exercisable for one share of common stock at $1.00 per share.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

During the past two fiscal years there have been no transactions between us and any officer, director, or any shareholder owning greater than five percent (5%) of our outstanding shares, nor any member of the above referenced individuals' immediate family, except as set forth below.

Related Party Transactions

It is our policy that any future material transactions between us and members of management or their affiliates shall be on terms no less favorable than those available from unaffiliated third parties.

ITEM 14. PRINCIPAL ACCOUNTANTS FEES AND SERVICES

Our Audit Committee of the board of directors approves in advance the scope and cost of the engagement of an auditor before the auditor renders audit and non-audit services.

Audit Fees

The aggregate fees billed by our independent auditors, GBH CPAs, for professional services rendered for the audit of our annual financial statements included in our Annual Reports on Form 10-K for the years ended March 31, 2010 and 2009, and for the review of quarterly financial statements included in our Quarterly Reports on Form 10-Q for the quarters ending June 30, September 30, and December 31, 2009 and 2008, were:

		2010				2009
GBH CPAs, PC		$	103,885			$	89,525

Audit fees incurred by the Company were pre-approved by the Audit Committee.

Audit Related Fees

For the years ended March 31, 2010 and 2009, there were no fees billed for assurance and related services by GBH CPAs, PC relating to the performance of the audit of our financial statements which are not reported under the caption "Audit Fees" above.

Tax Fees

For the years ended March 31, 2010 and 2009, fees billed by GBH CPAs, PC for tax compliance, tax advice and tax planning were $-0- and $-0-, respectively.

We do not use the auditors for financial information system design and implementation. These services, which include designing or implementing a system that aggregates source data underlying the financial statements or generates information that is significant to our financial statements, are provided internally or by other service providers. We do not engage the auditors to provide compliance outsourcing services.

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The Audit Committee of the board of directors has considered the nature and amount of fees billed by GBH CPAs, PC believes that the provision of services for activities unrelated to the audit is compatible with maintaining GBH CPAs, PC independence.

All Other Fees

None.

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ITEM 15. EXHIBITS

Exhibit No.	Description
3.1	Articles of Incorporation (incorporated by reference to the Company Annual Report of Form 10-KSB for the fiscal year ended November 30, 2005 filed with the SEC on February 14, 2006 as Exhibit 3.1)
3.2	Certificate of Amendment to Articles of Incorporation of Lucas Energy, Inc. (incorporated by reference to Exhibit B to the Information Statement on Schedule 14C filed with the SEC on February 16, 2007).
3.3	Bylaws (incorporated by reference to the Company Annual Report of Form 10-KSB for the fiscal year ended November 30, 2005 filed with the SEC on February 14, 2006 as Exhibit 3.2)
10.1	Contract with SMC (incorporated by reference to the Company Annual Report of Form 10-KSB for the fiscal year ended November 30, 2005 filed with the SEC on February 14, 2006 as Exhibit 10.1)
10.2	Consignment Agreement (incorporated by reference to the Company Annual Report of Form 10-KSB for the fiscal year ended November 30, 2005 filed with the SEC on February 14, 2006 as Exhibit 10.2)
10.3	Stock Purchase Agreement between Lucas Energy, Inc. and The Delphic Oil Co., LLC, dated December 20, 2006 (incorporated by reference to the Form 8-K dated December 20, 2006 filed with the SEC on December 21, 2009 as Exhibit 10.1)
10.4	Oil, Gas and Mineral Lease between Lucas Energy, Inc. and Griffin, filed of record on February 23, 2007 (incorporated by reference to the Form 8-K dated February 24, 2007 filed with the SEC on March 1, 2007 as Exhibit 10.4)
10.5	Employment Agreement between Lucas Energy, Inc. and James J. Cerna, dated March 20, 2007 (incorporated by reference to the Company Annual Report on Form 10-KSB for the fiscal year ended March 31, 2007 filed with the SEC on June 29, 2007, Exhibit 10.5)
10.6	Employment Agreement between Lucas Energy, Inc. and William A. Sawyer, dated March 20, 2007 (incorporated by reference to the Company Annual Report on Form 10-KSB for the fiscal year ended March 31, 2007 filed with the SEC on June 29, 2007, Exhibit 10.6)
10.7	Credit Agreement between Lucas Energy, Inc. and Amegy Bank National Association (Incorporated by reference to the Form 8-K dated October 8, 2008 filed with the SEC October 14, 2008)
10.8	Secured Promissory Note between Lucas Energy, Inc. and Amegy Bank National Association (Incorporated by reference to the Form 8-K dated October 8, 2008 filed with the SEC October 14, 2008)
10.9	Deed of Trust, Security Agreement, Financing Statement and Assignment of Production from Lucas Energy to Kenneth R. Batson, Trustee, for the benefit of Amegy Bank National Association (Incorporated by reference to the Form 8-K dated October 8, 2008 filed with the SEC October 14, 2008)
10.10	Security Agreement by Lucas Energy, Inc. in favor of Amegy Bank National Association (Incorporated by reference to the Form 8-K dated October 8, 2008 filed with the SEC October 14, 2008)
10.11	Unregistered Sale of Equity Securities and Departure of Director and Appointment of Director (Incorporated by reference to the Form 8-K dated October 8, 2009 filed with the SEC October 13, 2009)
10.12	Placement Agent Agreement with WR Hambrecht & Co (Incorporated by reference to the Form 8-K dated March 26, 2009 filed with the SEC March 26, 2010)
10.13	Submission of Matters to a Vote of Security Holders, Election of Directors and Compensatory Arrangements of Certain Officers (Incorporated by reference to the Form 8-K/A dated March 30, 2010 filed with the SEC April 22, 2010).
10.14	Lucas Energy, Inc. 2010 Long Term Incentive Plan (Incorporated by reference to the Form S-8 filed with the SEC on April 23, 2010)
10.15	Purchase and Sale Agreement Between Lucas Energy, Inc. and HilCorp Energy I, L.P. dated April 1, 2010 (1)
10.16	Termination of Credit Agreement with Amegy Bank and Release of all Liens and Security Interests held dated May 5, 2010 (Incorporated by reference to the Form 8-K dated May 5, 2010 filed with the SEC May 6, 2010)
10.17	Unregistered Sale of Equity Securities (Incorporated by reference to the Form 8-K dated May 25, 2010 filed with the SEC May 27, 2010)
14.1	Code of Ethics (Incorporated by reference to the Company Annual Report on Form 10-K/A, Amendment No. 1, for the fiscal year ended March 31, 2009 filed with the SEC on July 29, 2009).
14.2	Whistleblower Protection Policy (Incorporated by reference to the Company Annual Report on Form 10-K/A, Amendment No. 1, for the fiscal year ended March 31, 2009 filed with the SEC on July 29, 2009).
14.3	Charter of the Audit and Ethics Committee (Incorporated by reference to the Company Annual Report on Form 10-K/A, Amendment No. 1, for the fiscal year ended March 31, 2009 filed with the SEC on July 29, 2009).
14.4	Charter of the Nominating Committee (Incorporated by reference to the Company Annual Report on Form 10-K/A, Amendment No. 1, for the fiscal year ended March 31, 2009 filed with the SEC on July 29, 2009).
14.5	Charter of the Compensation Committee (Incorporated by reference to the Company Annual Report on Form 10-K/A, Amendment No. 1, for the fiscal year ended March 31, 2009 filed with the SEC on July 29, 2009).
23.1	Consent of GBH CPAs, PC (1)
23.2	Consent of Forrest A. Garb & Associates, Inc. (1)
31.1	Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (1)
31.2	Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (1)
32.1	Certification of CEO Pursuant to 18 U.S.C. Section 1350 as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (1)
32.2	Certification of CFO Pursuant to 18 U.S.C. Section 1350 as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (1)
99.1	Report of Forrest A. Garb & Associates, Inc. (1)

(1)

Filed herewith.

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SIGNATURES

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

LUCAS ENERGY, INC.

BY:	/S/ WILLIAM A SAWYER
	William A. Sawyer
	President and C.E.O.

Dated: July [ 13 ], 2010

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title	Date

/ s / J. FRED HOFHEINZ J. Fred Hofheinz	Chairman	July 14, 2010

/s/ WILLIAM SAWYER William Sawyer	President, CEO, and Director (Principal Executive Officer)	July 14, 2010

/s/ DONALD L. SYTSMA Donald L. Sytsma	Chief Financial Officer (Principal Financial Officer and Accounting Officer)	July 14, 2010

/s/ W. ANDREW KRUSEN W. Andrew Krusen	Director	July 14, 2010

/s/ PETER GRUNEBAUM Peter Grunebaum	Director	July 14, 2010

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LUCAS ENERGY INC.

INDEX TO THE FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets	F-3
Consolidated Statements of Operations	F-4
Consolidated Statements of Stockholders’ Equity	F-5
Consolidated Statements of Cash Flows	F-6
Notes to Consolidated Financial Statements	F-7

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Lucas Energy, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Lucas Energy, Inc. as of March 31, 2010 and 2009 and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years ended March 31, 2010 and 2009. These consolidated financial statements are the responsibility of Lucas Energy, Inc.’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits 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 audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Lucas Energy, Inc. as of March 31, 2010 and 2009 and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

GBH CPAs, PC

www.gbhcpas.com

Houston, Texas

July 14, 2010

F-2

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LUCAS ENERGY, INC.

Consolidated Balance Sheets

	March 31, 2010			March 31, 2009
ASSETS
CURRENT ASSETS
Cash	$	1,822,780		$	136,841
Marketable securities		21,450			293,336
Accounts receivable - oil and gas		198,083			138,283
Accounts receivable - trade		46,081			-
Deferred financing costs, net of amortization of $170,830 and $47,223 respectively		250,921			121,606
Deferred offering costs		119,912			-
Other current assets		43,769			57,764
TOTAL CURRENT ASSETS		2,502,996			747,830

OIL AND GAS PROPERTIES, FULL COST METHOD
Properties subject to amortization		24,699,722			22,794,893
Accumulated depletion, depreciation and amortization		(2,482,443	)		(1,721,580	)
OIL AND GAS PROPERTIES, NET		22,217,289			21,073,313

Property, plant and equipment, net of accumulated depreciation of $15,062 and $3,738, respectively		20,907			26,033
Deferred financing costs		-			250,922
Other assets		57,515			56,828

TOTAL ASSETS	$	24,798,707		$	22,154,926

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable - trade	$	1,391,446		$	808,598
Advances from working interest owner		3,045,292			-
Borrowings on credit facility, current portion		2,150,000			300,000
Accrued expenses		65,541			152,472

TOTAL CURRENT LIABILITIES		6,652,279			1,261,070

NON-CURRENT LIABILITIES
Borrowings on credit facility		-			2,350,000
Asset retirement obligations		327,412			181,599

TOTAL LIABILITIES		6,979,691			3,792,669

STOCKHOLDERS' EQUITY

Preferred stock, 10,000,000 shares authorized of $0.001 par value, no shares issued and outstanding		-			-
Common stock, 100,000,000 shares authorized of $0.001 par value, 12,837,220 and 12,800,320 shares issued and outstanding at March 31, 2010, and 10,383,388 and 10,346,488 shares issued and outstanding at March 31, 2009, respectively		12,837			10,383
Additional paid-in capital		20,639,247			18,864,225
Treasury stock, at cost		(49,159	)		(49,159	)
Accumulated deficit		(2,783,909	)		(463,192	)

TOTAL STOCKHOLDERS' EQUITY		17,819,016			18,362,257

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	24,798,707		$	22,154,926

See notes to consolidated financial statements.

F-3

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LUCAS ENERGY, INC.

Consolidated Statements of Operations

	For the Year Ended March 31, 2010			For the Year Ended March 31, 2009


OIL AND GAS REVENUES	$	1,777,736		$	3,382,060

EXPENSES
Lease operating expenses		1,048,333			1,345,928
Severance and property taxes		129.432			171,688
Depreciation, depletion, amortization and accretion		787,340			899,949
General and administrative		1,690,170			1,594,598

Total Expenses		3,655,275			4,012,163

LOSS FROM OPERATIONS		(1,877,539	)		(630,103	)

OTHER INCOME (EXPENSES)
Unrealized loss on marketable securities		(110,606	)		(2,095,019	)
Realized loss on marketable securities		(30,785	)		(121,273	)
Interest income		-			1,970
Interest expense		(301,787	)		(89,193	)
Total Other Income (Expenses)		(443,178	)		(2,303,515	)

NET INCOME BEFORE INCOME TAXES		(2,320,707	)		(2,933,618	)

INCOME TAX BENEFIT		-			834,127

NET LOSS	$	(2,320,717	)	$	(2,099,491	)

NET LOSS PER SHARE :
BASIC AND DILUTED	$	(0.21	)	$	(0.21	)

WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
BASIC AND DILUTED		10,812,810			10,237,830

See notes to consolidated financial statements.

F-4

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LUCAS ENERGY, INC.

Consolidated Statements of Stockholders' Equity

For the Years Ended March 31, 2010 and 2009

	Preferred Stock				Common Stock				Treasury Stock			Additional Paid- In Capital		Retained Earnings / (Accumulated) Deficit)			Accumulated Other Comprehensive Income			Total
	Shares		Amount		Shares		Amount		Treasury Stock			Additional Paid- In Capital		Retained Earnings / (Accumulated) Deficit)			Accumulated Other Comprehensive Income			Total
Balance, March 31, 2008		-		-		10,246,189	$	10,246	$	-		$	18,518,806	$	407,046		$	1,229,253		$	20,165,351
Reclassification of unrealized gain on available for sale securities		-		-		-		-		-			-		1,229,253			(1,229,253	)		-
Warrants issued for services		-		-		-		-		-			267,082		-			-			267,082
Common shares issued for:
Services at weighted average price of $0.57 per share		-		-		124,480		124		-			71,100		-			-			71,224
Oil and gas properties at weighted average price of $0.57 per share		-		-		12,719		13		-			7,237		-			-			7,250
Purchase of treasury stock at weighted average price of $1.33 per share		-		-				-		(49,159	)		-		-			-			(49,159	)
Net loss		-		-		-		-		-			-		(2,099,491	)		-			(2,099,491	)

Balance, March 31, 2009		-		-		10,383,388		10,383		(49,159	)		18,864,225		(463,192	)		-			18,362,257

Common shares issued for:
Cash at $0.60 per share		-		-		462,501		463		-			277,037		-			-			277,500
Services at weighted average price of $0.72 per share		-		-		179,141		179		-			128,293		-			-			128,472
Oil and gas properties at weighted average price of $0.75 per share		-		-		1,128,504		1,128		-			843,938		-			-			845,066
Conversion of debt at $0.77 per share		-		-		683,686		684		-			525,754		-			-			526,438
Net loss		-		-		-		-		-			-		(2,320,717	)		-			(2,320,717	)
Balance, March 31, 2010		-	$	-		12,837,220	$	12,837	$	(49,159	)	$	20,639,247	$	(2,783,909	)	$	-		$	17,819,016

See notes to consolidated financial statements.

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LUCAS ENERGY, INC.

Consolidated Statements of Cash Flows

	For the Year Ended March 31, 2010			For the Year Ended March 31, 2009


CASH FLOWS FROM OPERATING ACTIVITIES

Net loss	$	(2,320,717	)	$	(2,099,491	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		787,340			899,949
Amortization of deferred financing costs		121,607			49,223
Deferred tax benefit		-			(834,126	)
Unrealized loss on marketable securities		110,606			2,095,019
Realized loss on marketable securities		30,785			121,273
Share-based compensation		128,472			320,928
Marketable securities transferred to consultant for services		38,000			-
Changes in operating assets and liabilities:
(Increase) decrease in receivables		(123,287	)		421,603
(Increase) decrease in other current assets		38,504			(18,915	)
(Increase) decrease in other assets		(25,195	)		(5,062	)
Increase (decrease) in accounts payable and accrued expenses		495,917			(368,472	)

Net Cash Provided by Operating Activities		(717,967	)		581,929

CASH FLOWS FROM INVESTING ACTIVITIES

Proceeds from sale of oil and gas properties		1,595,208			188,500
Investments in marketable securities		-			(121,273	)
Proceeds from sale of marketable securities		92,495			-
Purchase of oil and gas property and equipment		(1,980,479	)		(3,961,443	)
Purchase property, plant and equipment		(6,198	)		(27,153	)

Net Cash Used in Investing Activities		(298,974	)		(3,921,369	)

CASH FLOWS FROM FINANCING ACTIVITIES

Net proceeds from the sale of common stock		277,500			-
Advances from credit facility, net		-			2,383,054
Short term borrowings		740,000
Advances from working interest owners		2,305,292
Cash paid for deferred offering costs		(119,912	)
Cash paid for treasury stock		-			(49,159	)
Principal reduction on credit facility		(500,000	)		-

Net Cash (Used) Provided by Financing Activities		2,702,880			2,333,895

NET INCREASE (DECREASE) IN CASH		1,685,939			(1,005,545	)
CASH AT BEGINNING OF YEAR		136,841			1,142,386

CASH AT END OF YEAR	$	1,822,780		$	136,841

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

CASH PAID FOR:
Interest	$	178,133		$	39,970
Income taxes	$	-		$	-
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Adoption of SFAS 159	$	-		$	1,229,253
Increase in asset retirement obligations	$	145,813		$	18,623
Accounts payable for financing costs	$	-		$	154,805
Common stock issued for oil and gas properties	$	845,066		$	24,628
Common stock issued for conversion of debt	$	526,438		$	-

See notes to consolidated financial statements.

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LUCAS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – ORGANIZATION AND HISTORY

The Company was incorporated on December 16, 2003 in the State of Nevada as Panorama Investments, Corp. (“Panorama”). On June 16, 2006 the Company consummated a share exchange with Lucas Energy Resources, Inc. (“Lucas Resources”), a privately held oil and gas company which held oil and gas lease acreage and producing reserves in the State of Texas. The share exchange was made pursuant to a May 19, 2006 Acquisition and Exchange Agreement the prior shareholders of Lucas Resources assumed control of and responsibilities for the Company’s activities. In conjunction with the share exchange, the name of Panorama was changed to Lucas Energy, Inc. (“Lucas”).

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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.

Lucas' consolidated financial statements are based on a number of significant estimates, including oil and gas reserve quantities which are the basis for the calculation of depreciation, depletion and impairment of oil and gas properties, and timing and costs associated with its retirement obligations.

Cash and Cash Equivalents

Cash and cash equivalents include cash in banks and financial instruments which mature within three months of the date of purchase.

Concentration of Credit Risk

Financial instruments that potentially subject Lucas to concentration of credit risk consist of cash and accounts receivable. Cash balances exceeded FDIC insurance protection levels by approximately $1.6 million at March 31, 2010, and at certain points throughout the year subjecting Lucas to risk related to the uninsured balance. Lucas’ deposits are held at large established bank institutions and it believes that the risk of loss associated with these uninsured balances is remote.

Accounts receivable are recorded at invoiced amount and generally do not bear interest. Any allowance for doubtful accounts is based on management's estimate of the amount of probable losses due to the inability to collect from customers. As of March 31, 2010, no allowance for doubtful accounts has been recorded.

Sales to one customer comprised 87% and 88% of Lucas’ total oil and gas revenues for the fiscal years ending March 31, 2010 and 2009, respectively. Lucas believes that, in the event that its primary customer was unable or unwilling to continue to purchase Lucas’ production, there are a substantial number of alternative buyers for its production at comparable prices.

Marketable Securities

Lucas reports its short-term investments and other marketable securities at fair value in accordance with ASC 825 “Financial Instruments”. At March 31, 2010, Lucas' short-term investments consisted of shares of common stock held in Bonanza Oil & Gas, Inc. (“Bonanza”). ASC 825 allows the Company the option to value its financial assets and liabilities at fair value on an investment by investment basis, and the changes in the fair value of assets and liabilities are reported in Lucas’ results of operations in the period that the change in fair value occurs.

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For the year ended March 31, 2010 Lucas reported a non-cash unrealized loss on its Bonanza shares of common stock of $110,606. For the year ended March 31, 2010 Lucas realized a loss on the sale of a portion of the Bonanza shares held totaling $30,785. Proceeds from sales of Bonanza stock totaled $92,495, and 1,000,000 shares were transferred to an investor relations consultant for services valued at $38,000.

Fair Value of Financial Instruments

As of March 31, 2010, the fair value of cash, accounts receivable and accounts payable approximate carrying values because of the short-term maturity of these instruments.

Oil and Gas Properties, Full Cost Method

Lucas uses the full cost method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells used to find proved reserves, and to drill and equip development wells including directly related overhead costs and related asset retirement costs are capitalized.

Under this method, all costs, including internal costs directly related to acquisition, exploration and development activities are capitalized as oil and gas property costs on a county by country basis. Sales of oil and gas properties or interests therein are credited against capitalized costs in the full cost pool. Properties not subject to amortization consist of exploration and development costs which are evaluated on a property-by-property basis. Amortization of these unproved property costs begins when the properties become proved or their values become impaired. Lucas assesses the realizability of unproved properties, if any, on at least an annual basis or when there has been an indication that impairment in value may have occurred. Impairment of unproved properties is assessed based on management's intention with regard to future exploration and development of individually significant properties and the ability of Lucas to obtain funds to finance such exploration and development. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Costs of oil and gas properties are amortized using the units of production method. Amortization expense calculated per equivalent physical unit of production amounted to $26.28 per barrel of oil equivalent (“BOE”) and $20.56 per BOE for the years ended March 31, 2010 and 2009, respectively.

Ceiling Test

In applying the full cost method, Lucas performs an impairment test (ceiling test) at each reporting date, whereby the carrying value of property and equipment is compared to the “estimated present value,” of its proved reserves discounted at a 10-percent interest rate of future net revenues, based on current economic and operating conditions at the end of the period, plus the cost of properties not being amortized, plus the lower of cost or fair market value of unproved properties included in costs being amortized, less the income tax effects related to book and tax basis differences of the properties. If capitalized costs exceed this limit, the excess is charged as an impairment expense. For the years ending March 31, 2010 and 2009 no impairment of oil and gas properties was recorded.

Property, Plant and Equipment

Property, plant and equipment are stated at cost and consist primarily of furniture and office equipment. Depreciation is computed on a straight-line basis over the estimated useful lives of three to five years.

Income Taxes

Deferred taxes are provided on the liability method whereby deferred tax assets are recognized for deductible temporary differences and operating loss and tax credit carry-forwards and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences are the differences between the reported amounts of assets and liabilities and their tax bases. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and accrued tax liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

Lucas has evaluated and concluded that there are no significant uncertain tax positions requiring recognition in the Company’s financial statements as of March 31, 2010. The Company’s policy is to classify assessments, if any, for tax related interest as interest expense and penalties as interest expenses.

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Earnings per Share of Common Stock

Basic and diluted net income per share calculations are calculated on the basis of the weighted average number of common shares outstanding during the year. Purchases of treasury stock reduce the outstanding shares commencing on the date that the stock is purchased. Common stock equivalents are excluded from the calculation when a loss is incurred as their effect would be anti-dilutive. On March 31, 2010 all options and warrants outstanding were “out of the money”; and are therefore, anti-dilutive and excluded from the calculation of the basic and diluted net income (loss) earnings per share.

Revenue and Cost Recognition

Lucas recognizes oil and natural gas revenue under the sales method of accounting for its interests in producing wells as oil and natural gas is produced and sold from those wells. Oil and natural gas sold by Lucas is not significantly different from Lucas’ share of production. Costs associated with production are expensed in the period incurred.

Recent Accounting Pronouncements

In December 2008, the SEC released Final Rule, “ Modernization of Oil and Gas Reporting” The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require that companies 1) report the independence and qualifications of its reserves preparer, 2) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit, 3) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new disclosure requirements are effective for financial statements for fiscal years ending on or after December 31, 2009. The Company adopted the requirements for the fiscal year ended March 31, 2010. The Company assessed the impact of the adoption of the new pronouncement, and determined that did not have a material impact on the Company’s operating results, financial position or cash flows.

In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162” (“SFAS No. 168”). The FASB Accounting Standards Codification, (“Codification” or “ASC”) became the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of SFAS No. 168, the Codification superseded all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification became non-authoritative.

Following SFAS No. 168, the FASB will no longer issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts; instead, it will issue Accounting Standards Updates (ASU’s). The FASB will not consider ASU’s as authoritative in their own right; rather these updates will serve only to update the Codification, provide background information about the guidance, and provide the bases for conclusions on the change(s) in the Codification. SFAS No. 168 is incorporated in ASC Topic 105, Generally Accepted Accounting Principles. The Company adopted SFAS No. 168 in the third calendar quarter of its 2010 fiscal year, and the Company will provide reference to both the Codification topic reference and the previously authoritative references related to Codification topics and subtopics, as appropriate.

Lucas does not expect that any other recently issued accounting pronouncements will have a significant impact on the financial statements of the Company.

NOTE 3 - FAIR VALUE MEASUREMENTS

The carrying values of cash and cash equivalents, accounts receivable and accounts payable (including income taxes payable and accrued expenses) included in the accompanying consolidated balance sheets approximated fair value at March 31, 2010, and they are not presented in the following table associated with the fair value measurement of Lucas’ investments.

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Financial Assets (Liabilities):		Carrying Amount				Total Fair Value				Quoted Prices In Active Markets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Trading Securities		$	21,450			$	21,450			$	21,450			$	-			$	-

ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the table above, this hierarchy consists of three broad levels. Level 1 inputs on the hierarchy consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs consist of fair values of the investment in commodity futures contracts, which are estimated valuations provided by counterparties using the Black-Scholes model based upon the forward commodity price curves as of the end of the quarter, implied volatilities of commodities, and a risk free rate (using the treasury yield as of the end of the quarter). Level 3 inputs have the lowest priority. Lucas uses appropriate valuation techniques based on the available inputs to measure the fair values of its assets and liabilities. When available, Lucas measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

LEVEL 1 FAIR VALUE MEASUREMENTS

Short-term Investments in Marketable Securities -- The fair values of these investments are based on quoted market prices. Lucas' short-term investments as of March 31, 2010 consisted entirely of trading securities which are subject to market fluctuations.

MARKETABLE SECURITIES

At March 31, 2009, Lucas held 7,332,000 shares (3,666,000 pre-split shares) of Bonanza common stock. On January 20, 2010, Bonanza effected a two for one forward stock split. All shares are reflected on a post-split basis. During the year ended March 31, 2010, Lucas sold 3,032,000 (1,516,000 shares pre-split) of Bonanza common stock, and transferred 1,000,000 shares (500,000 pre-split shares) to an investor relations consultant for services valued at $38,000, with a realized loss of $30,785, net of commissions. During the years ended March 31, 2010 and 2009, pursuant to mark-to-market accounting, Lucas reported a non-cash unrealized loss on Bonanza common shares held totaling $110,606 and $2,095,019, respectively. At March 31, 2010, Lucas held 3,300,000 shares of Bonanza common stock.

On May 2, 2008 Lucas purchased six commodity contracts that were linked to the NYMEX crude oil futures contracts. At the time the contracts were closed out Lucas had a realized loss on the NYMEX contracts totaling $121,273.

NOTE 4 – OIL AND GAS PROPERTIES

All of Lucas’ oil and gas properties are located in the United States. Costs being amortized at March 31, 2010 and 2009 are as follows:

	2010			2009
Proved leasehold costs	$	12,196,467		$	9,973,019
Costs of wells and development		13,243,507			12,692,775
Capitalized asset retirement costs		259,748			129,099
Total cost of oil and gas properties		24,699,722			22,794,893
Accumulated depletion, depreciation, amortization and impairment		(2,482,433	)		(1,721,580	)
Oil and gas properties, net	$	22,217,289		$	21,073,313

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LEI 2009-II Capital Program

LEI 2009-III Capital Program

Acquisition of Oil and Gas Properties Located in Wilson County, Texas

Lucas acquired approximately 2,771 gross oil and gas lease acreage (approx. 2,078 acres net to Lucas interest) located in Wilson County, Texas from El Tex Petroleum, LLC (“El Tex”). The leases have eight shut-in or plugged wellbores that the Company believes are good candidates for restoration and revitalization procedures. The leasehold, wellbore and surface equipment acquisition price totaled approximately $1.0 million comprised of 637,887 shares of Lucas common stock valued at $0.77 per share, or approximately $490,000, Lucas’ assumption of $500,000 in debt plus accrued interest; and the remittance of $68,000 in cash.

One director of Lucas holds an approximate 25.2% interest in El Tex while a second Lucas director holds an indirect beneficial ownership interest of approximately 18.8% in El Tex. Pursuant to NYSE Amex exchange rules, Company shareholders were required to approve the issuance of shares of common stock to El Tex due to the directors holding in the aggregate more than five percent (5%) indirect interest in the assets being acquired by Lucas from El Tex. Additionally, the note holder of the debt assumed by Lucas is a director of Lucas. In connection with the Lucas acquisition the note holder agreed to convert the debt plus accrued interest due him into shares of Lucas common stock. Pursuant to NYSE Amex exchange rules Company shareholders were required to approve the issuance of the shares of common stock to the director.

At the Lucas shareholder meeting held on March 30, 2010, the Lucas shareholders approved the issuance of the shares of common stock to El Tex and the issuance of shares of common stock to the Company director for the conversion of debt plus accrued interest assumed by Lucas. NYSE Amex approved the listing application for the shares to be issued and on May 25, 2010 Lucas issued 637,887 shares of common stock to El Tex and 683,686 shares of common stock to the Lucas director that held the debt assumed by Lucas. The shares of common stock were issued at $0.77 per share which was the fair value of the shares at the time the acquisition was agreed and effected in September 2009.

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Three wells acquired by Lucas from El Tex are part of the LEI 2009-III capital program, while one well is part of the LEI 2009-II six well program.

In addition, on February 23, 2010, Lucas paid $250,000 to El Tex for lease acquisition in additional properties.

NOTE 5 - REVOLVING LINE OF CREDIT AND LETTER OF CREDIT FACILITY

On October 8, 2008, Lucas entered into a three-year Revolving Line of Credit and Letter of Credit Facility with Amegy Bank (the “Credit Facility”). The Credit Facility originally provided Lucas with up to a $100 million oil and gas reserve-based revolving line of credit with maturity on October 8, 2011 (the “Revolving Line of Credit”). The availability of credit and repayments under the Credit Facility are subject to periodic borrowing base redeterminations. The Credit Facility provides for scheduled semiannual borrowing base redeterminations on June 1 and December 1, or at any other time that Amegy or Lucas may request an unscheduled redetermination; but neither is obligated to accommodate an unscheduled redetermination more than once between the scheduled semiannual redeterminations. At closing of the Credit Facility in October 2008, Lucas had a lending commitment and borrowing capacity of $3.0 million. Lucas’ accounts receivable were collateral to the Revolving Line of Credit with Amegy Bank.

The interest rate on borrowed funds under the Credit Facility is based on the greater of Amegy Bank’s prime lending rate or Federal Funds rate plus 0.50% per annum, but not less than 5.0% per annum. The Credit Facility contains a variable commitment fee component for unused borrowing capacity not to exceed a 0.05% annual rate. Borrowings outstanding on the Credit Facility are due October 8, 2011. Since entering into the Credit Facility with Amegy Bank, Lucas’ interest rate has been 5.0% per annum paid monthly. Lucas incurred transaction costs totaling $421,751 on the Amegy Credit Facility and the deferred financing costs are being amortized over the three year term of the Credit Facility using the effective interest rate method. For the year ended March 31, 2010, Lucas recorded as interest expense the amortization of deferred financing costs totaling $123,654 and the unamortized balance of the Amegy Credit Facility transaction costs total $250,921 at March 31, 2010.

The Credit Facility contained covenants that Lucas is required to meet including: a) maintain a current ratio of not less than 1.00 to 1.00; b) prohibit the ratio of Indebtedness to adjusted earnings before interest, taxes, depreciation and amortization (“EBITDA”) from being more than 3.75 to 1.00 (as defined in the credit agreement) for the preceding four quarterly periods; and c) limit general and administrative (“G&A”) expenses (determined in accordance with generally accepted accounting principles) during a fiscal quarter to no more than twenty-five percent (25.0%) of revenue less recurring lease operating expenses and taxes for the quarter.

At March 31, 2010, Lucas did not meet the above described loan covenants. The outstanding balance under the Credit Facility at March 31, 2010 was $2,150,000; and no borrowing capacity was available to Lucas under the Facility.

For the year ended March 31, 2010 Lucas incurred $122,970 of interest; $55,163 of bank and bank advisor’s fees; and $123,654 for amortization of deferred financing costs on the Credit Facility for total interest and associated costs of the Credit Facility of $301,787.

On May 5, 2010, Lucas paid off the outstanding balance under the Amegy Credit Facility, and terminated the Facility. In connection with the repayment and termination of the Credit Facility, Amegy Bank released all liens and security interests securing the Lucas’ obligations under the Credit Facility; and the remaining unamortized deferred financing costs on the Credit Facility totaling $250,921 were recorded as a interest expense during the period ending June 30, 2010.

NOTE 6 – ASSET RETIREMENT OBLIGATIONS

Lucas records the fair value of a liability for asset retirement obligations (“ARO”) in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The present value of the estimated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset and is depreciated over the useful life of the asset. Lucas accrues an abandonment liability associated with its oil and gas wells when those assets are placed in service. The ARO is recorded at its estimated fair value and accretion is recognized over time as the discounted liability is accreted to its expected settlement value. Fair value is determined by using the expected future cash outflows discounted at Lucas's credit-adjusted risk-free interest rate. No market risk premium has been included in Lucas's calculation of the ARO balance. Lucas recorded $327,412 and $181,599 of asset retirement obligations as of March 31, 2010 and 2009, respectively.

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The following is a description of the changes to the Company's asset retirement obligations for the years ended March 31, 2010 and 2009.

	2010			2009
Asset retirement obligations at beginning of year	$	181,599		$	141,512
Additions for development drilling		139,739			21,129
Accretion expense		15,164			21,464
Reduction for sale of oil and gas property		(9,090	)		(2,506	)

Asset retirement obligations at end of year	$	327,412		$	181,599

NOTE 7 – INCOME TAXES

The total provision for income taxes consisted of the following for the years ended:

	March 31, 2010			March 31, 2009
Current taxes:
Federal	$	-		$	-
State		-			-
		-			-
Deferred taxes:
Federal		(787,172	)		(834,127	)
State		-			-
		(787,172	)		(834,127	)

Total	$	(787,172	)	$	(834,127	)

Reconciliation between actual tax expense (benefit) and income taxes computed by applying the U.S. federal income tax rate and state income tax rate to income from continuing operations before income taxes are as follows:

	March 31, 2010			March 31, 2009
Computed at expected tax rates (34%)	$	(789,044	)	$	(997,430	)
Meals and entertainment		1,872			2,445
Change in valuation allowance		787,172			160,858
Total	$	-		$	(834,127	)

Tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred liabilities are presented below:

	March 31, 2010			March 31, 2009
Deferred tax assets:
Net operating tax loss carryforwards	$	4,222,046		$	3,024,380
Stock-based compensation		109,116			109,116
Deferred financing cost		2,396			2,396
Unrealized loss on available for-sale securities		97,896			60,290
Oil and gas properties		-			-
Accretion of asset retirement obligation liability		23,005			17,850
Depletion		532,112			324,694
Gain on sale of oil and gas properties		-			33,096
Total deferred tax assets		4,986,571			3,571,822

Deferred tax liabilities:
Depreciation		(630,222	)		(410,886	)
Depletion		-			-
Intangible drilling costs		(3,066,667	)		(3,000,078	)
Loss on sale of oil and gas properties		(341,653	)		-
Total deferred tax liabilities		(4,038,541	)		(3,410,964	)

Subtotal		948,030			160,858
Less: Valuation allowance		(948,030	)		(160,858	)

Total	$	-		$	-

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At March 31, 2010, Lucas had estimated net operating loss carryforwards for federal and state income tax purposes of $12,417,783 which will begin to expire, if unused, beginning in 2026.

The above estimates are based upon management’s decisions concerning certain elections which could change the relationship between net income and taxable income. Management decisions are made annually and could cause the estimates to vary significantly.

NOTE 8 – STOCKHOLDERS’ EQUITY

Shares issued for cash

In the second and third fiscal quarters of 2010, Lucas issued through private equity placement, 350,000 units at a purchase price of $0.60 per unit (“Unit”) for net proceeds to the Company of $210,000. Each Unit was comprised of one share of common stock and an attached three-year warrant for one share of common stock at $1.00 per share. The relative fair value of the common stock and attached warrant for one share of common stock were as follows:

Description	Shares		Relative Fair Value Amount
Common stock		350,000	$	144,900
Common stock purchase warrants		350,000		65,100

Total Proceeds			$	210,000

The relative fair value of the common stock and warrants in the above table were derived through the Black Scholes option pricing model, and variables used in the model were: (i) a 0.42% risk-free interest rate, (ii) an expected life of one year, (iii) a volatility of 120.82%, and (iv) zero expected dividends.

During the year ending March 31, 2010, two company directors purchased a total of 112,501 shares of common stock at $0.60 per share for net proceeds to the Company of $67,500. The directors did not receive any warrants in connection with the purchase of shares.

Shares issued for services

During the year ended March 31, 2010 the Company issued 179,141 shares valued at $128,472 of common stock to consultants and contractors for capital raising, investor awareness and other similar services.

During the annual shareholder meeting held on March 30, 2010, Company shareholders approved the Lucas Energy, Inc. Long Term Incentive Plan (“Incentive Plan”) providing for the Company to issue up to 900,000 shares of common stock to officers, directors, employees, contractors and consultants for services provided to the Company. The Company registered shares to be issued under the Incentive Plan in a Form S-8 filed with the SEC on April 23, 2010. The Compensation Committee of the Board of Directors approved the grant of shares of common stock to be issued under the Incentive Plan upon the NYSE Amex approval of the associated listing application totaling 109,141 shares with fair value of $71,672 or $0.66 per share.

On July 20, 2009, the Company issued 25,000 shares of common stock to its corporate secretary and former chief financial officer as part of his compensation package. The shares were issued at fair value totaling $25,000 or $1.00 per common share, and approved by Company shareholders in the annual shareholder meeting held on March 30, 2010.

During the year ended March 31, 2009 the Company issued 124,480 shares of common stock for services with a fair value of $71,224 or $0.57 per common share.

F-14

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Shares issued for oil and gas properties

On October 20, 2009, the Company issued 85,443 shares of common stock to acquire new oil and gas lease acreage. The shares were issued at the grant date fair value of $69,649, or $0.82 per common share.

On November 30, 2009, the Company issued 220,000 shares of common stock to acquire an additional 22.5% working interest in three existing oil and gas wells located in Gonzales County, Texas (i.e., Rozella Kifer No. 1, Louis Zavadil No. 1 and Ali-O No. 1). The shares were issued at the grant date fair value of $165,000, or $0.75 per common share.

On March 30, 2010, Company shareholders in the annual meeting approved the issuance of 637,887 shares of common stock with a fair value of $490,000 or $0.77 per common share, to El Tex Petroleum, LLC for the acquisition of oil and gas lease acreage located in Wilson County, Texas. Also in the March 30, 2010 annual shareholder meeting, Company shareholders approved the issuance of 683,686 shares of common stock with a fair value of $526,438, or $0.77 per common share, to the Company’s chairman in exchange for the assignment of approximately $526,438 of debt and accrued interest due him by El Tex Petroleum, LLC.

During the year ended March 31, 2009 the Company issued 12,719 shares of common stock for oil and gas properties with a fair value of $7,250 or $0.57 per share.

Warrant Exercise

On April 29, 2010 a warrant holder exercised his warrants with an exercise price of $1.00 per share and the Company issued 25,000 shares of common stock for total proceeds of $25,000.

Treasury Stock

On September 8, 2008 and October 29, 2009, Lucas repurchased 10,000 shares and 26,900 shares, respectively of its common stock in the open market trading at a total cost of $49,159. The shares are held by Lucas’ transfer agent as Treasury stock, and the shares are treated as issued but not outstanding at March 31, 2010 and 2009.

Preferred Stock

Lucas has authorized 10,000,000 shares of $0.001 par value preferred stock. No shares were outstanding as of March 31, 20010 and 2009.

NOTE 9 – OPTIONS AND WARRANTS

On September 2, 2008, Lucas granted 200,000 non-qualified options to purchase Lucas’ common stock to an officer of Lucas. These options were to vest as follows: 50,000 on March 1, 2009; 50,000 on September 1, 2009; 50,000 on March 1, 2010; and 50,000 on September 1, 2010 at an exercise price of $2.60 per share. The options expire in September 2010. The stock options were valued at $267,083 using the Black-Scholes Options Pricing Model with the following assumptions: i) expected share price volatility of 95.93%; ii) risk free interest rate of 2.26%; iii) contractual term weighted of two years; and iv) no dividend yield. Due to the termination of employment of the officer in January 2009, all options became fully vested and Lucas recognized the total value of $267,083 during the year ended March 31, 2009 as a non-cash charge for stock-based compensation expense.

In September 2007, Lucas completed a private placement in which it sold 2,763,049 Units. Each Unit was comprised of one share of restricted common stock and a warrant to purchase one share of common stock at $8.00 per share for a period of three years. Also in connection with the private placement, Lucas issued 247,500 warrants to the placement agents, and each warrant entitles the placement agents the right to purchase one share of common stock at $8.00 per share for a period of three years. All warrants issued were outstanding at March 31, 2010 and 2009 had $-0- intrinsic value.

F-15

Table of Contents

Summary information regarding options and warrants are as follows:

	Options		Weighted Average Exercise Price		Warrants		Weighted Average Exercise Price
Outstanding at March 31, 2009		200,000	$	2.60		3,010,549	$	8.00
Options and warrants issued		-		-		350,000		1.00
Outstanding at March 31, 2010		200,000	$	2.60		3,360,549	$	7.27

Options and warrants outstanding and exercisable as of March 31, 2010:

Exercise Price		Remaining Life	Options Outstanding		Options Exercisable		Warrants Outstanding		Warrants Exercisable

$	8.00	.60 Years		-		-		3,010,549		3,010,549
$	2.60	.64 Years		200,000		200,000		-		-
$	1.00	2.64 Years		-		-		350,000		350,000
Total				200,000		200,000		3,360,549		3,360,549

All options are vested, and all options and warrants are exercisable. All options and warrants had no intrinsic value at March 31, 2010.

NOTE 10 – COMMITMENTS AND CONTINGENCIES

Lucas leases approximately 3,793 square feet of office space in Houston, Texas that serves as its corporate office. The lease is for 22 months, with lease payments of approximately $6,572 per month with an expiry of April 30, 2012. Total rent expense was $65,596 for the year ended March 31, 2010 and $46,062 for the year ended March 31, 2009.

NOTE 11 – SUBSEQUENT EVENTS

Hilcorp Energy I, L.P. Purchase and Sale Agreement dated April 1, 2010

The proceeds from HilCorp were recorded as a reduction to Lucas’ full cost pool with no recognition of gain or loss on the transaction. Due to Lucas’ net operating tax loss carry-forwards no taxable income or income tax liability on the “deep rights” sale occurred. A third closing of the remainder of the Company’s Eagle Ford Shale rights is expected to occur by the end of July 2010.

F-16

Table of Contents

At-The-Market Shelf Public Offering

On March 26, 2010, Lucas entered into a Placement Agent Agreement with WR Hambrecht + Co. (“WRH”), under which Lucas may issue and sell up to 4,000,000 shares of common stock from time to time in an at-the-market (“ATM”) public equity offering program. Under the ATM offering Lucas sold a total of 778,170 newly issued shares of common stock during the period April 12, 2010 through May 6, 2010 with gross and net proceeds of $1,493,561 and $1,381,544, respectively.

F-17

Table of Contents

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

(UNAUDITED)

The following supplemental unaudited information regarding Lucas Energy’s oil and gas activities is presented pursuant to the disclosure requirements of SFAS No. 69. The standardized measure of discounted future net cash flows is computed by applying constant prices of oil and gas to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on period-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on period-end statutory tax rates) to be incurred on pre-tax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. All operations of Lucas are located in the United States.

(1)	Capitalized Costs Relating to Oil and Gas Producing Activities:

	At March 31, 2010			At March 31, 2009

Proved leasehold costs	$	12,196,467		$	9,973,019
Costs of wells and development		13,243,507			12,692,775
Capitalize asset retirement costs		259,748			129,099
Total cost of oil and gas properties	$	24,699,722		$	22,794,893
Unproved oil and gas properties		-			-
Accumulated depreciation and depletion		(2,482,433	)		(1,721,580	)
Net Capitalized Costs	$	22,217,289		$	21,073,313

(2)	Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities:

	For the Year Ended March 31, 2010		For the Year Ended March 31, 2009
Acquisition of Properties
Proved	$	2,150,000	$	578,297
Unproved		-		-
Exploration Costs		-		-
Development Costs		1,222,361		3,426,397
Total	$	3,372,881	$	4,004,694

(3)	Results of Operations for Producing Activities:

	For the Year Ended March 31, 2010			For the Year Ended March 31, 2009

Sales	$	1,777,736		$	3,382,060
Production costs		(1,177,765	)		(1,517,616	)
Depreciation and depletion		(760,853	)		(896,574	)
Income tax benefit		-			834,127
Results of operations for producing activities, (excluding corporate overhead and interest costs)	$	(160,882	)	$	1,801,997

F-18

Table of Contents

(4)	Reserve Quantity Information

Our proved reserves at March 31, 2010 are set forth below:

	Oil		Gas
	(Bbls)		(MMcf)
Proved Developed Producing		73,010		11,760
Proved Developed Non Producing		63,540		19,410
Proved Undeveloped		1,833,680		-
Total Proved, at March 31, 2010		1,970,230		31,170

Our proved reserves at March 31, 2009 are set forth below:

	Oil		Gas
	(Bbls)		(MMcf)
Proved Developed Producing		218,200		67,510
Proved Developed Non Producing		11,900		-
Proved Undeveloped		2,008,760		-
Total Proved, at March 31, 2009		2,238,860		67,510

A summary of changes in reserve quantities for the years ended March 31, 2010 and 2009 are set forth below:

	Oil (BBL)			Gas (MCF)

Proved reserves at March 31, 2008		1,797,230			96,010

Revisions of previous estimates		(1,027,906	)		(20,995	)
Purchases of minerals in place		352,750			-
Extensions and discoveries		1,161,990			-
Production		(41,309	)		(7,505	)
Sales of minerals in place		(3,895	)		-

Proved reserves at March 31, 2009		2,238,860			67,510

Revisions of previous estimates		(389,520	)		(30,490	)
Purchases of minerals in place		694,610			-
Extensions and discoveries		47,510			-
Production		(25,600	)		(5,850	)
Sales of minerals in place		(595,630	)		-

Proved reserves at March 31, 2010		1,970,230			31,170

During the years ended March 31, 2010 and 2009, Lucas had reserve studies and estimates prepared on its various properties. The difficulties and uncertainties involved in estimating proved oil and gas reserves makes comparisons between companies difficult. Estimation of reserve quantities is subject to wide fluctuations because it is dependent on judgmental interpretation of geological and geophysical data.

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

	March 31, 2010			March 31, 2009
Future cash inflows	$	133,979,890		$	108,060,340
Future production costs		(20,249,210	)		(28,445,570	)
Future development costs		(31,999,050	)		(25,193,750	)
Future tax expense		(11,211,606	)		(5,095,748	)
Future net cash flows		70,520,024			49,325,272
Discounted for estimated timing of cash flows, at 10%		(31,313,531	)		(25,338,137	)
Standardized measure	$	39,206,493		$	23,987,135

The following schedule summarizes changes in the standardized measure of discounted future net cash flow relating to proved oil and gas reserves:

	Years ended March 31,
	2010			2009
Standardized measure, beginning of year	$	23,987,135		$	63,419,343
Extensions, discoveries and improved recovery		1,065,740			13,739,320
Revisions of previous estimates		(11,127,350	)		(21,762,785	)
Purchases of minerals in place		24,767,887			4,045,010
Sales of minerals in place		(18,398,099	)		(53,909	)
Net change in prices and production costs		18,942,910			(60,738,814	)
Accretion of discount		2,398,713			9,013,353
Oil and gas sales, net of production costs		(599,971	)		(1,864,441	)
Changes in estimated future development costs		4,733,700			5,234,031
Previously estimated development cost incurred		865,320			2,347,510
Net change in income taxes		(4,500,813	)		22,904,742
Change in timing of estimated future production		(2,928,679	)		(12,296,225	)
Standardized measure, end of year	$	39,206,493		$	23,987,135

The above schedules relating to proved oil and gas reserves, standardized measure of discounted future net cash flows and changes in the standardized measure of discounted future net cash flows have their foundation in engineering estimates of future net revenues that are derived from proved reserves and prepared using the prevailing economic conditions. These reserve estimates are made from evaluations conducted by independent geologists, of such properties and will be periodically reviewed based upon updated geological and production data. Estimates of proved reserves are inherently imprecise.

Subsequent development and production of Lucas's reserves will necessitate revising the present estimates. In addition, information provided in the above schedules does not provide definitive information as the results of any particular year but, rather, helps explain and demonstrate the impact of major factors affecting Lucas's oil and gas producing activities. Therefore, Lucas suggests that all of the aforementioned factors concerning assumptions and concepts should be taken into consideration when reviewing and analyzing this information.

F-20

EX-10.15 2 ex10_15.htm EXHIBIT 10.15 ex10_15.htm

Exhibit 10.15

PURCHASE AND SALE AGREEMENT

BETWEEN

LUCAS ENERGY, INC.

AS SELLER

AND

HILCORP ENERGY I, L.P.

AS BUYER

April 1, 2010

TABLE OF CONTENTS

		Page

ARTICLE I Assets		1

Section 1.01	Agreement to Sell and Purchase	1
Section 1.02	Assets	1
Section 1.03	Certain Additional Defined Terms.	3

ARTICLE II Purchase Price		3

Section 2.01	Purchase Price.	3
Section 2.02	Deposit.	3
Section 2.03	Allocated Values	4

ARTICLE III Effective Time		4

Section 3.01	Ownership of Assets	4

ARTICLE IV Title and Environmental Matters		5

Section 4.01	Examination Period	5
Section 4.02	Title Defects	5
Section 4.03	Notice of Title Defects.	5
Section 4.04	Remedies for Title Defects.	6
Section 4.05	Special Warranty of Title	7
Section 4.06	Preferential Rights To Purchase	8
Section 4.07	Consents to Assignment	9
Section 4.08	Environmental Review.	9
Section 4.09	Environmental Definitions.	10
Section 4.10	Notice of Environmental Defects	11
Section 4.11	Remedies for Environmental Defects.	11

ARTICLE V Representations and Warranties of Seller		11

Section 5.01	Existence	11
Section 5.02	Legal Power	11
Section 5.03	Execution	12
Section 5.04	Brokers	12
Section 5.05	Bankruptcy	12
Section 5.06	Taxes	12
Section 5.07	Environmental Matters.	12
Section 5.08	Violations and Defaults.	12
Section 5.09	Litigation.	13
Section 5.10	Leases.	13
Section 5.11	Material Contracts.	13
Section 5.12	Hydrocarbon Sales Agreements.	13

Section 5.13	Preferential Rights and Consents.	13
Section 5.14	Access.	13
Section 5.15	Area of Mutual Interest and Other Agreements.	13
Section 5.16	Expenses.	14

ARTICLE VI Representations and Warranties of Buyer		14

Section 6.01	Existence	14
Section 6.02	Legal Power	14
Section 6.03	Execution	14
Section 6.04	Brokers	14
Section 6.05	Bankruptcy	14
Section 6.06	Litigation	14

ARTICLE VII Covenants		15

Section 7.01	Operation of the Leases Prior to the Closing.	15
Section 7.02	Operation of the Assets After the Closing	15
Section 7.03	Seller's Knowledge.	15
Section 7.04	Excluded Wellbores.	15

ARTICLE VIII Conditions to Obligations of Seller		16

Section 8.01	Representations	16
Section 8.02	Performance	16
Section 8.03	Pending Matters	16

ARTICLE IX Conditions to Obligations of Buyer		16

Section 9.01	Representations	16
Section 9.02	Performance	16
Section 9.03	Pending Matters	16

ARTICLE X The Closing		17

Section 10.01	Time and Place of the Closing	17
Section 10.02	Adjustments to Purchase Price at the Closing.	17
Section 10.03	Pre-Closing Allocations/Statement.	17
Section 10.04	Post-Closing Adjustments to Purchase Price.	17
Section 10.05	Transfer Taxes and Costs	18
Section 10.06	Ad Valorem and Similar Taxes	18
Section 10.07	Actions of Seller at the Closing.	18
Section 10.08	Actions of Buyer at the Closing.	19
Section 10.09	Further Cooperation.	19

ARTICLE XI Termination		20

Section 11.01	Right of Termination	20
Section 11.02	Effect of Termination	20
Section 11.03	Attorneys’ Fees, Etc.	20

ARTICLE XII Obligations and Indemnification		21

Section 12.01	Seller’s Retained Obligations	21
Section 12.02	Buyer’s Assumed Obligations	21
Section 12.03	Buyer’s Indemnification	21
Section 12.04	Seller’s Indemnification	21
Section 12.05	Indemnification Procedures.	22

ARTICLE XIII Limitations on Representations and Warranties; and Casualty Losses		24

Section 13.01	Disclaimers of Representations and Warranties	24
Section 13.02	Survival	24

ARTICLE XIV Arbitration		24

Section 14.01	Arbitrator.	24
Section 14.02	Rules and Procedures.	24

ARTICLE XV Miscellaneous		25

Section 15.01	Recording Expenses	25
Section 15.02	Entire Agreement	25
Section 15.03	Waiver	25
Section 15.04	Publicity	26
Section 15.05	Construction	26
Section 15.06	No Third Party Beneficiaries	26
Section 15.07	Assignment	26
Section 15.08	GOVERNING LAW; VENUE; JURY WAIVER.	26
Section 15.09	Notices	27
Section 15.10	Severability	27
Section 15.11	Survival.	27
Section 15.12	Time of the Essence	28
Section 15.13	Counterpart Execution	28
Section 15.14	Attorney Fees.	28
Section 15.15	Interpretation.	28
Section 15.16	Tax-Deferred Exchange.	29

iii

EXHIBITS

Exhibit A

– Leases

Exhibit A-1

– Excluded Wellbores

Exhibit B

– Contracts

Exhibit C

– Partial Assignment of Oil and Gas Leases

Exhibit D

– Participation Agreement

SCHEDULES

Schedule 5.07

Environmental

Schedule 5.09

Litigation

Schedule 5.13

Preferential Rights and Consents

Schedule 5.15

Area of Mutual Interest and Other Agreements

PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (this “Agreement”) is made and entered into this 1st day of April, 2010, by and between LUCAS ENERGY, INC., a Nevada corporation (“Seller”), and HILCORP ENERGY I, L.P., a Texas limited partnership (“Buyer”). Buyer and Seller are collectively referred to herein as the “Parties”, and are sometimes referred to individually as a “Party.”

W I T N E S S E T H:

WHEREAS, Seller is willing to sell to Buyer, and Buyer is willing to purchase from Seller, the Assets (as hereinafter defined), all upon the terms and conditions hereinafter set forth;

NOW, THEREFORE, in consideration of the mutual benefits derived and to be derived from this Agreement by each Party, Seller and Buyer hereby agree as follows:

ARTICLE I

Assets

Section 1.01 Agreement to Sell and Purchase. Subject to and in accordance with the terms and conditions of this Agreement, Buyer agrees to purchase the Assets from Seller, and Seller agrees to sell the Assets to Buyer as of the Effective Time.

Section 1.02 Assets. The term “Assets” shall mean the following:

(a) an undivided 85% of Seller’s interest in the oil, gas and/or mineral leases described or referred to in Exhibit A attached hereto (the “Leases”), insofar as the Leases cover depths below the base of the Austin Chalk Formation (defined below) (the “Subject Lease Interests”);

(b) an undivided 85% of Seller’s interest in all amendments, supplements, renewals, extensions or ratifications of the Leases, insofar as the same affect the Subject Lease Interests;

(c) an undivided 85% of Seller’s interest in all oil, gas and other hydrocarbons (“Hydrocarbons”) which may be produced from (i) any formation or depth below the base of the Austin Chalk Formation in and under the lands covered by the Leases, and (ii) the Austin Chalk Formation in and under the lands covered by the Leases to the extent that such Hydrocarbons are produced from (A) vertical wellbores, the perforations in which are located in the Eagle Ford Shale Formation (defined below) or in any other formation or depth below the base of the Austin Chalk Formation, or (B) that portion of any wellbores for horizontal wells after such wellbores first encounter the Eagle Ford Shale Formation, in each case whether or not such Hydrocarbon production results from fracing procedures conducted in the wellbores and whether or not any such wellbore is in a new well drilled or in an existing well subsequently assigned by Seller to Buyer, and in the case of item (B) above whether or not such Hydrocarbon production results from encountering the Austin Chalk Formation “D” Zone (defined below) in the drilling of horizontal wells after encountering the Eagle Ford Shale Formation (together with the Subject Lease Interests, collectively, the ”Subject Interests,” or singularly, a “Subject Interest”).

(d) an undivided 85% of Seller’s interest in (i) all rights of Seller to use and occupy the surface of and the subsurface depths under the lands covered by the Leases, insofar only as such rights pertain to the Subject Interests; (ii) all rights of Seller in any pooled, communitized or unitized acreage by virtue of any Subject Interest being a part thereof, including all Hydrocarbons produced after the Effective Time attributable to the Subject Interests or any such pool or unit allocated to any such Subject Interest;

(e) an undivided 85% of Seller’s interest in all easements, rights-of-way, surface leases, surface use agreements, surface fee or other surface or subsurface interests, rights and estates of Seller related to or used or useful in connection with the Subject Interests (the “Easements”), including, without limitation, the Easements described or referred to in Exhibit A attached hereto;

(f) an undivided 85% of Seller’s interest in all permits, licenses, franchises, registrations, certificates, exemptions, consents, approvals and other similar rights and privileges of Seller related to or used or useful in connection with the ownership or operation of the Subject Interests or the Easements (the “Permits”), to the extent Seller has the authority to assign the Permits;

(g) an undivided 85% of Seller’s interest in all contracts, agreements and other written agreements described in Exhibit B attached hereto, and all other contracts and agreements of Seller, including, without limitation, all production sales contracts, farmout agreements, operating agreements, service agreements, equipment leases, division orders, unit agreements, gas gathering and transportation agreements, water disposal agreements and other similar agreements, but only to the extent the same relate to the Subject Interests, the Easements, the Permits or the G&G Data (defined below) (collectively, the “Contracts”), and to the extent Seller has the authority to assign the Contracts;

(h) an undivided 85% of Seller’s interest in all books, records, files, muniments of title, reports and similar documents and materials that relate to the foregoing interests and that are in the possession or control of, or maintained by, Seller, including, without limitation, all contract files, title files, title records, title opinions, abstracts, property ownership reports, well logs, well tests, maps, engineering data and reports, health, environmental and safety information and records, regulatory records, accounting and financial records (the “Records”); and

(i) an undivided 85% of Seller’s interest in all geological, geophysical and seismic data of Seller (including, without limitation, raw data and interpretive data whether in written or electronic form), insofar only as it pertains to the Subject Interests, other than such data which cannot be transferred without the consent of or payment to any third party (the “G&G Data”).

Notwithstanding the foregoing, the Assets shall not include, and there is excepted, reserved and excluded from the sale contemplated by this Agreement, the wellbores listed on Exhibit A-1 attached hereto (the “Excluded Wellbores”) as long as such wellbores are not deepened or sidetracked, together with all Hydrocarbons which may be produced from any depth or formation in the Excluded Wellbores other than the Eagle Ford Shale Formation.

Section 1.03 Certain Additional Defined Terms.

(a) Austin Chalk Formation. For purposes of this Agreement, the term “Austin Chalk Formation” means the stratigraphic equivalent of the interval between 9286’ and 9773’ on the 5” Dual Induction Compensated Formation Density log in the Czar Resources Willa Whyburn Austin #1 Well, Gonzales County, Texas, API # 42177307170000.

(b) Eagle Ford Shale Formation. For purposes of this Agreement, the term “Eagle Ford Shale Formation” means the stratigraphic equivalent of the interval between 9773’ and 9896’ on the 5” Dual Induction Compensated Formation Density log in the Czar Resources Willa Whyburn Austin #1 Well, Gonzales County, Texas, API # 42177307170000.

(c) Horizontal Wells. For purposes of this Assignment, the term “horizontal well” means any well in which the wellbore deviates at least 75° from vertical.

(d) Austin Chalk Formation “D” Zone. For purposes of this Agreement, the term “Austin Chalk Formation “D” Zone” means the stratigraphic equivalent of the interval between 9686’ and 9773’ on the 5” Dual Induction Compensated Formation Density log in the Czar Resources Willa Whyburn Austin #1 Well, Gonzales County, Texas, API #42177307170000.

ARTICLE II

Purchase Price

Section 2.01 Purchase Price. The total consideration for the purchase, sale and conveyance of the Assets from Seller to Buyer is Buyer’s payment to Seller of the sum of $12,750,000.00 (the “Purchase Price”), as adjusted in accordance with the terms of this Agreement. The adjusted Purchase Price shall be paid to Seller (or its designee) at the Closing (defined below) by means of a completed federal funds transfer to an account designated in writing by Seller.

Section 2.02 Deposit.

(a) Not later than 5:00 p.m. Central Time on the next Business Day (defined below) following the execution of this Agreement by Buyer and Seller, Buyer shall deliver to Seller a performance guarantee deposit in the amount of $500,000.00 (together with all accrued interest thereon, the “Deposit”). The Deposit shall be paid by Buyer to Seller by means of a completed federal funds transfer to an account designated in writing by Seller. The Deposit shall be held by Seller in an interest bearing account subject to the terms of this Agreement.

(b) If all conditions precedent to the obligations of Buyer set forth in Article IX have been met and the transactions contemplated by this Agreement are not consummated on or before the Closing Date solely because of the failure of Buyer to perform any of its material obligations hereunder or the material breach of any representation herein by Buyer, then in such event and notwithstanding anything contained in this Agreement to the contrary, Seller shall have the right to terminate this Agreement and receive the Deposit as liquidated damages, in lieu of all other damages, which remedy shall be the sole and exclusive remedy available to Seller for Buyer’s failure to perform any of its material obligations hereunder or Buyer’s material breach of any representation herein. Buyer and Seller acknowledge and agree that (i) Seller’s actual damages upon such a termination would be difficult to ascertain with any certainty, (ii) that the Deposit is a reasonable estimate of such actual damages, and (iii) such liquidated damages do not constitute a penalty.

(c) If all conditions precedent to the obligations of Seller set forth in Article VIII have been met and the transactions contemplated by this Agreement are not consummated on or before the Closing Date solely because of the failure of Seller to perform any of its material obligations hereunder or the material breach of any representation herein by Seller, then in such event, Buyer shall have the option, in its sole discretion, (i) to consummate the transactions contemplated by this Agreement through enforcement of this Agreement by an action for specific performance, (ii) to enforce such other remedies as Buyer may have at law or in equity, or (iii) to terminate this Agreement, in which event Seller shall return the Deposit to Buyer within three (3) Business Days.

(d) If this Agreement is terminated by the mutual written agreement of Buyer and Seller, or if the Closing does not occur on or before the Closing Date (as the same may be extended by mutual agreement between Buyer and Seller), for any reason other than as set forth in Section 2.02(b) or 2.02(c), then Seller shall return the Deposit to Buyer within three (3) Business Days. Buyer and Seller shall thereupon have no further rights or obligations under this Agreement. As used herein, the term “Business Day” shall mean any day on which national banks are open for business in Houston, Texas.

(e) If the transactions contemplated by this Agreement are consummated, the Deposit shall be retained by Seller and shall be considered as prepayment of a portion of the Purchase Price, and the amount payable by Buyer at the Closing shall be reduced by the amount of the Deposit.

Section 2.03 Allocated Values. Seller has indicated to Buyer that the Subject Interests total 12,750 net mineral leasehold acres. The Purchase Price is allocated among the Subject Interests by Buyer based upon an allocated value of $1,000 per net mineral leasehold acre (the “Allocated Values”). Seller and Buyer agree that the Allocated Values shall be used to compute any adjustments to the Purchase Price pursuant to the provisions of Article IV of this Agreement.

ARTICLE III

Effective Time

Section 3.01 Ownership of Assets. If the transactions contemplated hereby are consummated in accordance with the terms and provisions hereof, the ownership of the Assets shall be transferred from Seller to Buyer on the Closing Date, but effective for all purposes as of 7:00 a.m. local time on March 1, 2010 (the “Effective Time”).

ARTICLE IV

Title and Environmental Matters

Section 4.01 Examination Period. Following the execution date of this Agreement until 5:00 p.m., local time in Houston, Texas on April 22, 2010 (the “Examination Period”), Seller shall make available for inspection and copying and shall permit Buyer and/or its representatives to examine and copy, at all reasonable times (including, by mutual agreement between Buyer and Seller, on weekends, holidays and before and after normal business hours if requested by Buyer) in Seller’s offices, the Leases, the Easements, the Contracts, the Permits, the Records, the G&G Data and all abstracts of title, title opinions, title files, ownership maps, lease files, Contracts files, assignments, division orders, operating and accounting records, agreements and other materials pertaining to the Assets.

Section 4.02 Title Defects. The term “Title Defect,” as used in this Agreement, shall mean, subject to Section 4.03, any material encumbrance, encroachment, irregularity, deficiency, defect in or reasonable objection to Seller’s ownership of the Subject Interests (expressly excluding Permitted Encumbrances, as hereinafter defined) that causes Seller, or Buyer from and after the Effective Time, not to have Good and Defensible Title (as hereinafter defined) to the Subject Interests. For purposes of this Agreement, the term “Good and Defensible Title” means subject to and except for the Permitted Encumbrances:

(a) that the net mineral leasehold acres attributable to the Subject Interests total not less than 12,750 net mineral leasehold acres (i.e., 85% x 15,000 net mineral leasehold acres);

(b) that Seller’s average net revenue interest in all Hydrocarbons produced, saved and sold from the Subject Interests (“Net Revenue Interest”) is not less than 73.5%, proportionately reduced (Seller’s average Net Revenue Interest shall be calculated on an acreage basis using the number of net mineral leasehold acres and the Net Revenue Interests attributable thereto);

(c) that Seller’s interest in and to the Subject Interests is deducible from the real property records of Gonzales County, Texas; and

(d) that the Subject Interests are free and clear of all liens, obligations, encumbrances and defects in title.

Section 4.03 Notice of Title Defects.

(a) If Buyer discovers any Title Defect affecting any Asset, Buyer shall notify Seller prior to 5:00 p.m., local time in Houston, Texas, on April 22, 2010 (the “Defects Deadline”) of such alleged Title Defect. To be effective, such notice (a “Defects Notice”) must (i) be in writing, (ii) be received by Seller prior to the Defects Deadline, (iii) describe the Title Defect, (iv) to the extent applicable, identify the specific Asset or Assets affected by such Title Defect, and (v) include a good faith estimate of the Defect Value (defined below) of such Title Defect as determined by Buyer. Any matters that may otherwise constitute a Title Defect, but of which Seller has not been specifically notified by Buyer in accordance with the foregoing, shall be deemed to have been waived by Buyer, except to the extent any unasserted Title Defect would constitute (A) a breach of the Seller’s special warranty of title contained in the Assignment, (B) a breach of any of Seller’s representations or warranties contained in this Agreement, or (C) a Retained Obligation (defined below). Except as otherwise provided herein, upon the receipt of any Defects Notice from Buyer, Seller shall have the option, but not the obligation, to attempt to cure such Title Defect to Buyer’s reasonable satisfaction at any time prior to Closing.

(b) The value attributable to each Title Defect (the “Defect Value”) that is asserted by Buyer in a Defects Notice shall be determined based upon the criteria set forth below:

(i) if a Title Defect is a lien upon any Asset, the Defect Value is the amount necessary to be paid to remove the lien from the affected Asset;

(ii) if a Title Defect is that the net mineral leasehold acres attributable to the Subject Interests total less than 12,750 net mineral leasehold acres, then the Defect Value thereof shall be an amount equal to the product of $1,000 multiplied by the difference between 12,750 net mineral leasehold acres and the number of net mineral leasehold acres actually attributable to the Subject Interests;

(iii) if a Title Defect represents an obligation, encumbrance, burden or charge upon the affected Asset for which the economic detriment to Buyer is unliquidated, the amount of the Defect Value shall be determined by taking into account the Allocated Value of the affected Asset, the portion of the Asset affected by the Title Defect, the legal effect of the Title Defect, the potential economic effect of the Title Defect over the life of the affected Asset, and the Defect Values placed upon the Title Defect by Buyer and Seller;

(iv) if a Title Defect is not then currently in effect or does not adversely affect an Asset throughout the entire productive life of such Asset, such fact shall be taken into account in determining the Defect Value;

(v) the Defect Value of a Title Defect shall be determined without duplication of any costs or losses included in another Defect Value hereunder;

(vi) notwithstanding anything herein to the contrary, the Defect Value of a Title Defect may not exceed the Allocated Value of the affected Asset;

(vii) Buyer’s right to assert Title Defects hereunder shall not be diminished or otherwise adversely affected by any materiality qualification contained in any of Seller’s representations and warranties in Article V hereof; and

(viii) such other factors as are reasonably necessary to make a proper evaluation.

Section 4.04 Remedies for Title Defects.

(a) Subject to Seller’s right to dispute the existence of a Title Defect and/or the Defect Value asserted with respect thereto and subject to the rights of Buyer pursuant to Section 4.04(b) and Section 11.01, in the event that any Title Defect timely asserted by Buyer in accordance with Section 4.03(a) is not waived in writing by Buyer or cured on or before Closing, Seller shall reduce the Purchase Price by the Defect Value for such Title Defect as determined pursuant to Section 4.03(b) or Article XIV;

(b) In the event that the Title Defect results from Seller’s average Net Revenue Interest attributable to the Subject Interests being less than 73.5%, proportionately reduced, and Buyer and Seller cannot agree on an appropriate reduction to the Purchase Price as a result thereof, then Buyer shall have the right to cause all or any portion of the Leases in which Seller’s Net Revenue Interest is less than 73.5% (proportionately reduced) to be excluded from this Agreement with an appropriate reduction in the Purchase Price based upon the Allocated Value of the net mineral leasehold acres attributable to such excluded Leases;

(c) If any Title Defect is in the nature of an unobtained consent to assignment or other restriction on assignability, the provisions of Section 4.07 shall apply; and

(d) If on or before Closing the Parties have not agreed upon the validity of any asserted Title Defect or have not agreed on the Defect Value attributable thereto, either Party shall have the right to elect to have the validity of such Title Defect and/or such Defect Value determined by an Independent Expert pursuant to Article XIV. If the validity of any asserted Title Defect, or the Defect Value attributable thereto, is not determined before Closing, then the Purchase Price paid at Closing shall be reduced by virtue of such disputed Title Defect or Defect Value by an amount that is midway between the amounts asserted by Buyer and Seller, and upon the final resolution of such dispute Buyer or Seller, as the case may be, shall pay to the other party the difference between the Defect Value withheld for such Title Defect and the Defect Value of such Title Defect as finally determined.

Section 4.05 Special Warranty of Title. The documents to be executed and delivered by Seller to Buyer transferring title to the Assets as required hereby, including the Partial Assignment of Oil and Gas Leases attached hereto as Exhibit C (the “Assignment”), shall provide for a special warranty of title, subject to the Permitted Encumbrances and the terms of this Agreement. The term “Permitted Encumbrances” shall mean any of the following matters to the extent the same are valid and subsisting and affect the Assets:

(a) the Leases and Contracts set forth in Exhibit A and Exhibit B, to the extent complete executed copies of the same (with all exhibits, schedules and attachments) are included in the Records or provided to Buyer on or prior to April 15, 2010 and the same do not operate to reduce the average Net Revenue Interest of Seller in the Subject Interests below 73.5%, proportionately reduced or materially interfere with, diminish or detract from the operation, development or ownership of the affected Asset;

(b) any unfiled materialman’s, mechanics’, repairman’s, employees’, contractors’, operators’ liens or other similar liens or charges for liquidated amounts arising in the ordinary course of business where payment of such amounts is not delinquent, and (i) that Seller has agreed to retain or pay pursuant to the terms hereof, or (ii) for which Seller is responsible for paying or releasing at the Closing;

(c) any current period liens for taxes and assessments affecting the Assets that are not yet due or delinquent, to the extent Seller has agreed to pay the same pursuant to the terms hereof or which are to be prorated pursuant to the terms hereof;

(d) to the extent that same do not and will not at any time materially interfere with the ownership, operation, development or value of the Assets, any (i) easements, rights-of-way, servitudes, permits, surface leases and other rights in respect of surface operations, pipelines, grazing, hunting, lodging, canals, ditches, reservoirs or the like, and (ii) easements for streets, alleys, highways, pipelines, telephone lines, power lines, railways and other similar rights-of-way on, over or in respect of property owned or leased by Seller or over which Seller owns rights-of-way, easements, permits or licenses;

(e) all lessors’ royalties, overriding royalties and other burdens on or deductions from the proceeds of production created or in existence as of the Effective Time, provided that such matters do not operate to reduce the average Net Revenue Interest of Seller in the Subject Interests below 73.5%, proportionately reduced;

(f) preferential rights to purchase or similar agreements with respect to which (i) written waivers or consents are obtained from the appropriate parties for the transactions contemplated hereby, or (ii) required written notices have been given for the transactions contemplated hereby to the holders of such rights and the appropriate period for asserting such rights has expired without an exercise of such rights;

(g) required third party consents to assignments or similar agreements with respect to which written waivers or consents are obtained from the appropriate parties for the transactions contemplated hereby;

(h) all rights to consent by, required notices to, filings with, or other actions by Governmental Authorities (defined below) in connection with the sale or conveyance of oil and gas leases or interests therein that are customarily obtained subsequent to such sale or conveyance;

(i) rights reserved to or vested in any Governmental Authority to control or regulate any of the Assets and the applicable laws, rules, and regulations of such Governmental Authorities;

(j) Title Defects which Buyer has waived or is deemed to have waived pursuant to the terms of this Agreement; and

(k) liens and encumbrances which are to be released at Closing pursuant to Section 10.07 hereof.

Section 4.06 Preferential Rights To Purchase. Seller shall use all reasonable efforts to comply with all preferential right to purchase provisions encumbering any Asset prior to the Closing. Prior to the Closing, Seller shall notify Buyer of the existence of any preferential purchase rights and if any preferential purchase rights are exercised or if the requisite period has elapsed without said rights having been exercised. If a third party who has been offered an interest in any Asset pursuant to a preferential right to purchase elects prior to the Closing to purchase such Asset pursuant to the aforesaid offer, the interest so affected will be eliminated from the Assets and the Purchase Price shall be reduced by the Allocated Value of such Asset. Otherwise, the interest offered as aforesaid shall be conveyed to Buyer at the Closing subject to any preferential right to purchase of any third party for which notice has been given but the time period for response by the holder of such preferential right extends beyond the Closing and Buyer shall assume all duties, obligations and liabilities arising from such preferential right to purchase. Without limiting the foregoing, if any such third party timely and properly elects to purchase an interest in any Asset subject to a preferential right to purchase after the Closing Date, Buyer shall be obligated to convey said interest to such third party and shall be entitled to the consideration for the sale of such interest.

Section 4.07 Consents to Assignment. Seller shall use all reasonable efforts to obtain all necessary consents from third parties to assign the Assets to Buyer prior to Closing (other than governmental approvals that are customarily obtained after Closing). To the extent such consents are not obtained prior to Closing, then such failure shall constitute a Title Defect as to that portion of the Assets affected thereby. Notwithstanding anything contained herein to the contrary Buyer, at its sole option, shall have the right to exclude any Asset which is subject to a consent to assignment that has not been obtained prior to Closing. If Buyer elects to exclude such Asset then the Purchase Price shall be reduced at Closing by an amount equal to the Allocated Value of the Asset excluded. If Buyer elects to acquire such Asset at Closing even though a consent to assignment has not been obtained, Buyer assumes all obligations in connection with such failure to obtain such consent, and such obligations shall be Assumed Obligations (as defined below) hereunder.

Section 4.08 Environmental Review.

(a) Buyer shall have the right to conduct or cause its environmental consultant (“Buyer’s Environmental Consultant”) to conduct an environmental review of the Assets prior to the expiration of the Defects Deadline (“Buyer’s Environmental Review”). The cost and expense of Buyer’s Environmental Review, if any, shall be borne solely by Buyer. Buyer shall (and shall cause Buyer’s Environmental Consultants to): (i) consult with Seller before conducting any work comprising Buyer’s Environmental Review, (ii) perform all such work in a safe and workmanlike manner and so as to not unreasonably interfere with Seller’s operations, and (iii) comply with all applicable laws, rules, and regulations. Seller will assist Buyer in obtaining any third party consents that are required in order to perform any work comprising Buyer’s Environmental Review. Seller shall have the right to have a representative or representatives accompany Buyer and Buyer’s Environmental Consultant at all times during Buyer’s Environmental Review, and Buyer shall give Seller notice not less than 24 hours before any visits by Buyer or Buyer’s Environmental Consultant to the Assets. With respect to any samples taken in connection with Buyer’s Environmental Review, Buyer shall take split samples, providing one of each such sample, properly labeled and identified, to Seller. BUYER HEREBY AGREES TO RELEASE, DEFEND, INDEMNIFY AND HOLD HARMLESS SELLER, ITS AFFILIATES, AND THEIR RESPECTIVE PARTNERS, SHAREHOLDERS, OWNERS, OFFICERS, DIRECTORS, EMPLOYEES, AGENTS AND REPRESENTATIVES, FROM AND AGAINST ALL CLAIMS, LOSSES, DAMAGES, COSTS, EXPENSES, CAUSES OF ACTION AND JUDGMENTS OF ANY KIND OR CHARACTER (INCLUDING THOSE RESULTING FROM SELLER’S JOINT, COMPARATIVE OR CONCURRENT NEGLIGENCE OR STRICT LIABILITY BUT EXPRESSLY NOT INCLUDING THOSE RESULTING FROM SELLER’S SOLE NEGLIGENCE, GROSS NEGLIGENCE OR WILLFUL MISCONDUCT) ARISING OUT OF OR RELATING TO BUYER’S ENVIRONMENTAL REVIEW.

(b) Unless otherwise required by applicable law, Buyer shall (and shall cause Buyer’s Environmental Consultant to) treat confidentially any matters revealed by Buyer’s Environmental Review and any reports or data generated from such review (the “Environmental Information”), and unless required by law Buyer shall not (and shall cause Buyer’s Environmental Consultant to not) disclose any Environmental Information to any Governmental Authority or other third party without the prior written consent of Seller. Unless otherwise required by law, Buyer may use the Environmental Information only in connection with the transactions contemplated by this Agreement. If Buyer, Buyer’s Environmental Consultant, or any third party to whom Buyer has provided any Environmental Information become legally compelled to disclose any of the Environmental Information, Buyer shall provide Seller with prompt notice sufficiently prior to any such disclosure so as to allow Seller to file any protective order, or seek any other remedy, as it deems appropriate under the circumstances.

Section 4.09 Environmental Definitions.

(a) Environmental Defect. For purposes of this Agreement, the term “Environmental Defect” means an Asset has been cited by Governmental Authority for a violation of an Environment Law (defined below), or Buyer has discovered a condition on or affecting an Asset which violates an Environment Law, Lease, Contract or other agreement, unless such violation has been cured to Buyer’s reasonable satisfaction or has been waived by Buyer.

(b) Governmental Authority. For purposes of this Agreement, the term “Governmental Authority” shall mean, as to any given Asset, the United States and the state, county, parish, city and political subdivisions in which such Asset is located and that exercises jurisdiction over such Asset, and any commission, agency, department, board or other instrumentality thereof that exercises jurisdiction over such Asset.

(c) Environmental Laws. For purposes of this Agreement, the term “Environmental Laws” shall mean all laws, statutes, ordinances, court decisions, rules and regulations of any Governmental Authority pertaining to health or the environment as may be interpreted by applicable court decisions or administrative orders, including, without limitation, the Clean Air Act, as amended, the Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), the Federal Water Pollution Control Act, as amended, the Occupational Safety and Health Act, as amended, the Resource Conservation and Recovery Act of 1976, as amended, the Safe Drinking Water Act, as amended, the Toxic Substances Control Act, as amended, the Superfund Amendment and Reauthorization Act of 1986, as amended, the Hazardous Materials Transportation Act, as amended, the Rivers and Harbors Act of 1899, as amended, the Hazardous and Solid Waste Amendments Act of 1984, as amended, the Occupational Safety and Health Act, as amended, and any other federal, state and local law whose purpose is to conserve or protect human health, the environment, wildlife or natural resources.

(d) Environmental Defect Value. For purposes of this Agreement, the term “Environmental Defect Value” shall mean, with respect to any Environmental Defect, the amount of the estimated costs and expenses to correct or remediate such Environmental Defect in a manner consistent with Environmental Laws and applicable Leases, Contracts and agreements.

Section 4.10 Notice of Environmental Defects. If Buyer discovers any Environmental Defect affecting the Assets, Buyer shall notify Seller prior to the Defects Deadline of such alleged Environmental Defect. To be effective, such notice must (i) be in writing, (ii) be received by Seller prior to the Defects Deadline, (iii) describe the Environmental Defect in reasonable detail, (iv) to the extent known, identify the specific Assets affected by such Environmental Defect, (v) identify the procedures recommended to correct the Environmental Defect, and (vi) include Buyer’s reasonable estimate of the Environmental Defect Value of the Environmental Defect. Upon the receipt of such effective notice from Buyer, Seller shall have the option, but not the obligation, to attempt to cure any such Environmental Defect at any time prior to the Closing.

Section 4.11 Remedies for Environmental Defects. If any Environmental Defect described in a notice delivered in accordance with Section 4.10 is not cured to Buyer’s reasonable satisfaction on or before the Closing and Buyer and Seller cannot agree on an appropriate reduction to the Purchase Price as a result thereof, then Buyer shall have the right to cause the Assets affected by such Environmental Defect to be excluded from this Agreement with an appropriate reduction in the Purchase Price based upon the Allocated Value of such excluded Assets.

ARTICLE V

Representations and Warranties of Seller

Seller represents and warrants to Buyer that:

Section 5.01 Existence. Seller is a corporation duly organized, validly existing and in good standing under the laws of the State of Nevada and is qualified to conduct business and in good standing in the State of Texas. Seller has full legal power, right and authority to carry on its business as such is now being conducted and as contemplated to be conducted.

Section 5.02 Legal Power. Seller has the legal power and right to enter into and perform this Agreement and the transactions contemplated hereby. The execution and delivery of this Agreement and the consummation of the transactions contemplated by this Agreement will not violate, nor be in conflict with (a) any provision of Seller’s organizational documents; (b) any material agreement or instrument to which Seller is a party or by which Seller or the Assets are bound; or (c) any judgment, order, ruling or decree applicable to Seller or the Assets, or any law, rule or regulation applicable to Seller or the Assets.

Section 5.03 Execution. The execution, delivery and performance of this Agreement and the transactions contemplated hereby are duly and validly authorized by all requisite action on the part of Seller. This Agreement constitutes, and the documents to be executed and delivered by Seller at the Closing will constitute, the legal, valid and binding obligations of Seller enforceable in accordance with their terms, except as enforceability may be limited by bankruptcy, insolvency, reorganization, debtor relief or similar laws affecting the rights of creditors generally and general equitable principles.

Section 5.04 Brokers. No broker or finder is entitled to any brokerage or finder’s fee, or to any commission, based in any way on agreements, arrangements or understandings made by or on behalf of Seller or any affiliate of Seller for which Buyer has or will have any liabilities or obligations (contingent or otherwise).

Section 5.05 Bankruptcy. There are no bankruptcy, reorganization or liquidation proceedings pending against Seller or being contemplated by Seller, or to the knowledge of Seller, threatened against Seller.

Section 5.06 Taxes. Seller has paid and discharged all ad valorem, property, production, severance, excise and other taxes and assessments based on or measured by the ownership of the Leases and other Assets, the production of Hydrocarbons therefrom or the receipt of proceeds therefrom as are due and payable. No taxing authority or agency, domestic or foreign, has asserted or is now asserting or, to the knowledge of Seller, threatening to assert against the Assets or Seller any deficiency or claim for additional taxes or interest thereon or penalties in connection therewith.

Section 5.07 Environmental Matters. Except as set forth in Schedule 5.07 attached hereto, to the best of Seller’s knowledge (i) no environmental or physical condition of any Lease or other Asset violates any Environmental Laws, Lease, Contract or other agreement in any material respect; (ii) no condition or event has occurred with respect to any Lease or other Asset that, with notice or the passage of time, or both, would constitute a violation requiring action by Seller or, after Closing, Buyer to remedy, stabilize, neutralize, clean up or otherwise alter the environmental or physical condition of any such Lease or other Asset; and (iii) Seller has not disposed of any produced water, hazardous substances or solid waste materials generated on the Leases or used on the Leases at sites off the Leases, except in compliance with Environmental Laws. Except as set forth in Schedule 5.07, there are no civil, criminal or administrative actions, lawsuits, demands, litigation, claims or hearings pending, or to Seller’s knowledge threatened, relating to an alleged breach of Environmental Laws on or with respect to any Lease or other Asset, and Seller has not received any notice from any Governmental Authority or any other person that the operation of any Lease or other Asset is in violation of any Environmental Laws or agreement or that Seller or any predecessor in title of Seller is responsible (or potentially responsible) for remedying, stabilizing, neutralizing or cleaning up any pollutants, contaminants, or hazardous or toxic waste, substances or materials at, on, or beneath any Lease or other Asset.

Section 5.08 Violations and Defaults. Seller is not in violation of, or in default in any material respect under, and no event has occurred that (with notice or the lapse of time or both) could constitute a violation of or default under (i) any applicable law, rule, regulation, ordinance, order, writ, decree or judgment of any Governmental Authority related to the Leases or other Assets, or (ii) any Lease, Easement, Permit or Contract.

Section 5.09 Litigation. Except as set forth in Schedule 5.09: (i) no litigation, arbitration, investigation or other proceeding of any Governmental Authority or other party is pending or, to the knowledge of Seller, threatened against Seller affecting the Leases or other Assets, nor are there any facts or circumstances existing which could reasonably be expected to give rise to any such litigation, arbitration, investigation or proceeding; and (ii) Seller is not subject to any outstanding injunction, judgment, order, decree, settlement agreement, conciliation agreement, letter of commitment, deficiency letter or ruling affecting the Leases or other Assets (other than routine oil and gas field regulatory orders applicable generally to the oil and gas industry).

Section 5.10 Leases. Seller is not in default with respect to any of its material obligations under any of the Leases. Seller has not received, either verbally or in writing, any notice of default or breach under any of the Leases which default or breach has not been cured or remedied to the satisfaction of the applicable lessor. All royalties and other payments due under the Leases have been timely and properly paid, except for those which Seller has a legal right to suspend.

Section 5.11 Material Contracts. Except for the Contracts listed in Exhibit B, there are no Contracts affecting the Leases or other Assets with respect to which a breach by any party thereto could reasonably be expected to have or result in a material adverse effect on any of the Leases or other Assets. Each Contract listed in Exhibit B is in full force and effect and constitutes a legal, valid and binding obligation of Seller and, to the knowledge of Seller, each other party thereto. Seller has not received from any other party to a Contract listed in Exhibit B any notice, whether written or oral, of termination or intention to terminate such Contract and, to the knowledge of Seller, no event has occurred which (with notice or lapse of time, or both) would constitute a default under any such Contract or give Seller or any other party to any such Contract the right to terminate or modify such Contract.

Section 5.12 Hydrocarbon Sales Agreements. There are no Hydrocarbon sales agreements pertaining to the Assets that provide for a fixed price and that cannot be cancelled at any time upon ninety (90) days (or less) prior notice.

Section 5.13 Preferential Rights and Consents. To the knowledge of Seller, except as set forth in Schedule 5.13, there are no preferential rights to purchase or consents to assignment that are applicable to the Assets and the transactions contemplated hereby.

Section 5.14 Access. Seller has a legal right of access to all of the Leases, and following the Closing Buyer will have a legal right of access to all of the Leases.

Section 5.15 Area of Mutual Interest and Other Agreements. Except as set forth in Schedule 5.15, none of the Assets are subject to (i) any area of mutual interest agreement, or (ii) any farmout agreement, farmin agreement or similar agreement under which any party thereto is entitled to receive assignments not yet made, or could earn additional assignments after the Effective Time.

Section 5.16 Expenses. Seller has paid all lease operating expenses, capital expenses, joint interest billings and other costs and expenses attributable to the ownership and operation of the Leases and other Assets in a timely manner before becoming delinquent.

ARTICLE VI

Representations and Warranties of Buyer

Buyer represents and warrants to Seller that:

Section 6.01 Existence. Buyer is a limited partnership duly organized, validly existing and in good standing under the laws of the State of Texas. Buyer has full legal power, right and authority to carry on its business in the State of Texas as such is now being conducted and as contemplated to be conducted.

Section 6.02 Legal Power. Buyer has the legal power and right to enter into and perform this Agreement and the transactions contemplated hereby. The execution and delivery of this Agreement and the consummation of the transactions contemplated by this Agreement will not violate, nor be in conflict with (a) any provision of Buyer’s organizational documents, (b) any material agreement or instrument to which Buyer is a party or by which Buyer is bound; or (c) any judgment, order, ruling or decree applicable to Buyer as a party in interest or any law, rule or regulation applicable to Buyer.

Section 6.03 Execution. The execution, delivery and performance of this Agreement and the transactions contemplated hereby are duly and validly authorized by all requisite company action on the part of Buyer. This Agreement constitutes, and the documents to be executed and delivered by Buyer at the Closing will constitute, the legal, valid and binding obligations of Buyer enforceable in accordance with their terms, except as enforceable that may be limited by bankruptcy, insolvency, reorganization, debtor relief or similar laws affecting the rights of creditors generally.

Section 6.04 Brokers. No broker or finder is entitled to any brokerage or finder’s fee, or to any commission, based in any way on agreements, arrangements or understandings made by or on behalf of Buyer or any affiliate of Buyer for which Seller has or will have any liabilities or obligations (contingent or otherwise).

Section 6.05 Bankruptcy. There are no bankruptcy, reorganization or liquidation proceedings pending against Buyer, being contemplated by Buyer or, to the knowledge of Buyer, threatened against Buyer.

Section 6.06 Litigation. There is no suit, action, claim, investigation or inquiry by any person or entity or by any administrative agency or Governmental Authority and no legal, administrative or arbitration proceeding pending or, to Buyer’s knowledge, threatened against Buyer or any affiliate of Buyer that has materially affected or will materially affect Buyer’s ability to consummate the transactions contemplated herein.

ARTICLE VII

Covenants

Section 7.01 Operation of the Leases Prior to the Closing.

(a) From the date of this Agreement until Closing (the “Interim Period”), Seller shall (i) operate and administer the Leases in a good and workmanlike manner consistent with its past practices, and in material compliance with all applicable Leases, Contracts, laws, rules, regulations and Permits, (ii) carry on its business with respect to the Assets in substantially the same manner as before execution of this Agreement, (iii) give prompt written notice to Buyer of any notice of asserted default or violation received or given by Seller under any Leases, Contracts, laws, rules, regulations or Permits affecting any Asset, (iv) give Buyer the opportunity to discuss matters related to the Assets with such officers, accountants, consultants and counsel of Seller as Buyer deems reasonably necessary or appropriate for the purpose of familiarizing itself with the Assets, and (v) cause its employees to furnish Buyer with such data, records and other information with respect to the Assets as Buyer may from time to time reasonably request. Notwithstanding the foregoing, during the Interim Period, without the prior written consent of Buyer, which consent will not be unreasonably withheld or delayed, Seller will not (i) cause the Assets to be developed, maintained or operated in a manner substantially inconsistent with prior operations; (ii) abandon any part of the Assets; (iii) propose, agree to or commence any drilling or other operations on the Assets; (iv) convey, encumber, relinquish or dispose of any part of the Assets or any operating or other rights related thereto; (v) enter into any agreement amending, modifying, relinquishing or terminating all or any part of the Assets; or (vi) enter into any agreements affecting the Assets or the ownership, development or operation thereof.

(b) During the Interim Period, Seller will promptly pay, when due, all expenses, taxes, revenues, royalties, overriding royalties and other obligations attributable to the Assets and will not, without the prior written consent of Buyer waive any rights accruing after the Effective Time with respect to any of the Assets.

Section 7.02 Operation of the Assets After the Closing. On the Closing Date Seller will tender operation of the Assets to Buyer’s general partner, Hilcorp Energy Company.

Section 7.03 Seller's Knowledge. If after the date of this Agreement, Seller obtains knowledge of any fact which results in any representation or warranty of Buyer contained herein being inaccurate in any respect, Seller will promptly provide Buyer with written notice thereof.

Section 7.04 Excluded Wellbores. Seller shall not deepen or sidetrack any of the Excluded Wellbores or attempt to produce or complete any of the Excluded Wellbores in the Eagle Ford Shale Formation. If Seller takes any action in violation of this Section 7.04(a), Buyer shall be entitled to 85% of Seller’s interest in any Hydrocarbons produced from such Excluded Wellbores and to enforce any other rights or remedies available to Buyer at law or in equity, and (b) Seller shall execute any such assignments or other documents or take any such other action as Buyer may request in order to evidence Buyer’s rights to such Hydrocarbons. Seller shall also immediately notify Buyer if any other working interest owner in any Excluded Wellbore proposes a deepening, sidetrack or Eagle Ford shale recompletion operation for such Excluded Wellbore.

ARTICLE VIII

Conditions to Obligations of Seller

The obligations of Seller to consummate the transaction provided for in this Agreement are subject, at the option of Seller, to the fulfillment on or prior to the Closing Date of each of the following conditions:

Section 8.01 Representations. The representations and warranties of Buyer in this Agreement shall be true and correct in all material respects as of the Closing Date as though made on and as of such date, except that those representations and warranties which address matters only as of a particular date shall remain true and correct as of such date.

Section 8.02 Performance. Buyer shall have performed all material obligations, covenants and agreements contained in this Agreement to be performed or complied with by it at or prior to the Closing.

Section 8.03 Pending Matters. No suit, action or other proceeding shall be pending or threatened that seeks to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated by this Agreement.

ARTICLE IX

Conditions to Obligations of Buyer

The obligations of Buyer to consummate the transaction provided for in this Agreement are subject, at the option of Buyer, to the fulfillment on or prior to the Closing Date of each of the following conditions:

Section 9.01 Representations. The representations and warranties of Seller in this Agreement shall be true and correct in all material respects as of the Closing Date as though made on and as of such date, except that those representations and warranties which address matters only as of a particular date shall remain true and correct as of such date.

Section 9.02 Performance. Seller shall have performed all material obligations, covenants and agreements contained in this Agreement to be performed or complied with by it at or prior to the Closing.

Section 9.03 Pending Matters. No suit, action or other proceeding shall be pending or threatened that seeks to restrain, enjoin, or otherwise prohibit the consummation of the transactions contemplated by this Agreement.

ARTICLE X

The Closing

Section 10.01 Time and Place of the Closing. If the conditions referred to in Articles VIII and IX of this Agreement have been satisfied, the transactions contemplated by this Agreement (the “Closing”) shall take place at the offices of Buyer, whose address is 1201 Louisiana, Suite 1400, Houston, Texas 77002, at 9:00 a.m. on April 29, 2010, or at such other time as the Parties might hereafter mutually agree in writing (the “Closing Date”).

Section 10.02 Adjustments to Purchase Price at the Closing.

(a) At the Closing, the Purchase Price shall be increased by any amount provided for in this Agreement or agreed upon by Buyer and Seller.

(b) At the Closing, the Purchase Price shall be decreased by the following amounts:

(i) the Allocated Value of any Subject Interests sold prior to the Closing to the holder of a preferential right pursuant to Section 4.06;

(ii) all downward Purchase Price adjustments for Title Defects and Environmental Defects determined in accordance with Article IV;

(iii) the amount of the Deposit; and

(iv) any other amount provided for in this Agreement or agreed upon by Buyer and Seller.

(c) The adjustments described in Sections 10.02(a) and (b) are hereinafter referred to as the “Purchase Price Adjustments.”

Section 10.03 Pre-Closing Allocations/Statement. Not later than three (3) Business Days prior to the Closing Date, Buyer shall prepare and deliver to Seller a statement of the estimated Purchase Price Adjustments taking into account the foregoing principles (the “Closing Statement”). Buyer shall make available to Seller in Buyer’s office all documents supporting the estimated Purchase Price Adjustments. The Purchase Price paid by Buyer to Seller at Closing shall be the Purchase Price, as adjusted by the estimated Purchase Price Adjustments set forth in the Closing Statement; provided that if Seller notifies Buyer on or before the Closing Date that it disputes Buyer’s estimate of the Purchase Price Adjustments and the Parties cannot agree otherwise, then the Purchase Price paid at Closing shall be the amount that is midway between Seller’s and Buyer’s estimated amounts.

Section 10.04 Post-Closing Adjustments to Purchase Price. To the extent the Parties determine following the Closing that the Purchase Price Adjustments set forth in the Closing Statement were incorrect, the Party owing monies shall make the appropriate payment or reimbursement to the other Party within five (5) Business Days. The Closing Statement shall become final and binding upon the parties on the sixtieth (60th) day following the Closing (the “Final Settlement Date”), unless a Party gives written notice of its disagreement (a “Notice of Disagreement”) to the other Party prior to such date. Any Notice of Disagreement shall specify in detail the dollar amount, nature and basis of any disagreement so asserted. If a Notice of Disagreement is received by a Party in a timely manner and the Parties are unable to otherwise resolve the dispute evidenced by the Notice of Disagreement, then either Party may elect to have the dispute evidenced by the Notice of Disagreement resolved by arbitration in accordance with Article XIV.

Section 10.05 Transfer Taxes and Costs. All sales, use or other taxes (other than taxes on gross income, net income or gross receipts) and duties, levies or other governmental charges incurred by or imposed with respect to the property transfers undertaken pursuant to this Agreement shall be the responsibility of, and shall be collected, remitted and paid by, Buyer. Buyer agrees to reimburse Seller for all reasonable third party costs incurred by Seller and associated with assigning the Permits and Contracts to Buyer.

Section 10.06 Ad Valorem and Similar Taxes. All ad valorem, property, severance and similar taxes and assessments based upon or measured by the value of the Assets shall be divided or prorated between Seller and Buyer as of the Effective Time. Seller shall retain responsibility for such taxes attributable to the period of time prior to the Effective Time and Buyer shall assume responsibility for the period of time from and after the Effective Time.

Section 10.07 Actions of Seller at the Closing. At the Closing, Seller shall execute (where applicable) and deliver to Buyer the following, all of which shall be in form and content reasonably satisfactory to Buyer:

(a) the Assignment;

(b) a Participation Agreement between Seller and Buyer substantially in the form attached hereto as Exhibit D (the “Participation Agreement”);

(c) an Operating Agreement between Hilcorp Energy Company, as Operator, and Buyer and Seller, as Non-Operators, covering the Leases and substantially in the form attached to the Participation Agreement (the “Operating Agreement”);

(d) possession of the Assets;

(e) a Closing Certificate executed by a principal executive officer of Seller certifying that all of Seller’s representations and warranties are true and correct in all material respects as of the Closing Date, and that Seller has performed in all material respects all of the covenants required of Seller in this Agreement as of the Closing Date;

(f) a “non-foreign person” affidavit establishing that the transaction contemplated by this Agreement does not subject Buyer to the withholding requirement of the Foreign Investment Real Property Tax Act of 1980;

(g) a Request for Taxpayer Identification and Certification on Form W-9 certifying Seller’s federal employer identification number;

(h) any necessary change of operator forms on those Assets operated by Seller or its affiliates;

(i) recorded or recordable releases of all mortgage liens, security interests, financing statements and other similar liens and encumbrances granted by Seller to its lenders or other parties which encumber the Assets; and

(j) any other documents provided for herein or necessary or desirable to effectuate the transactions contemplated hereby.

Section 10.08 Actions of Buyer at the Closing. At the Closing, Buyer shall take possession of the Assets and execute (where applicable) and deliver to Seller the following, all of which shall be in form and content reasonably satisfactory to Seller:

(a) the Purchase Price (as adjusted pursuant to the provisions of this Agreement and net of the Deposit) by wire transfer to an account designated in writing by Seller;

(b) the Participation Agreement;

(d) a Closing Certificate, executed by a principal executive officer of the general partner of Buyer, certifying that all of Buyer’s representations and warranties are true and correct in all material respects as of the Closing Date, and that Buyer has performed in all material respects all of the covenants required of it in this Agreement as of the Closing Date; and

(e) the Assignment and any other documents provided for herein or necessary or desirable to effectuate the transactions contemplated hereby.

Section 10.09 Further Cooperation.

(a) Seller shall make the Records available to be picked up by Buyer at the offices of Seller during normal business hours on the Closing Date and on any date thereafter.

(b) After the Closing Date, each Party, at the request of the other and without additional consideration, shall execute and deliver, or shall cause to be executed and delivered, from time to time such further instruments of conveyance and transfer and shall take such other action as the other Party may reasonably request to convey and deliver the Assets to Buyer and to accomplish the orderly transfer of the Assets to Buyer in the manner contemplated by this Agreement.

(c) To the extent that any G&G Data relating to the Subject Interests cannot be transferred to Buyer at Closing without the consent of or payment to a third party, Seller shall, subject to any confidentiality requirements related to such data, allow Buyer to review such data in Seller’s offices during normal business hours following the Closing.

ARTICLE XI

Termination

Section 11.01 Right of Termination. This Agreement may be terminated at any time at or prior to the Closing:

(a) by mutual written consent of the Parties;

(b) by Seller on the Closing Date if the conditions set forth in Article VIII have not been satisfied in all material respects by Buyer or waived by Seller in writing by the Closing Date;

(c) by Buyer on the Closing Date if the conditions set forth in Article IX have not been satisfied in all material respects by Seller or waived by Buyer in writing by the Closing Date;

(d) by either Party if the Closing shall not have occurred on or before May 15, 2010;

(e) by either Party if any Governmental Authority shall have issued an order, judgment or decree or taken any other action challenging, delaying, restraining, enjoining, prohibiting or invalidating the consummation of any of the transactions contemplated herein;

(f) by Buyer or Seller if (i) the aggregate amount of the Purchase Price Adjustments asserted by Buyer pursuant to this Agreement with respect to all Title Defects, plus (ii) the aggregate Allocated Value of all Assets excluded from the transactions contemplated by this Agreement pursuant to Section 4.06 and Section 4.11, exceeds $6,375,000.00; or

(g) as otherwise provided herein;

provided, however, that no Party shall have the right to terminate this Agreement pursuant to clause (b), (c), or (d) above if such Party is at such time in material breach of any provision of this Agreement.

Section 11.02 Effect of Termination. In the event that the Closing does not occur as a result of any Party exercising its right to terminate pursuant to Section 11.01, then except as set forth in Section 2.02, this Agreement shall be null and void and no Party shall have any further rights or obligations under this Agreement.

Section 11.03 Attorneys’ Fees, Etc. If either Party to this Agreement resorts to legal proceedings to enforce this Agreement, the prevailing Party in such proceedings shall be entitled to recover all costs incurred by such Party, including reasonable attorneys’ fees, in addition to any other relief to which such Party may be entitled. Notwithstanding anything to the contrary in this Agreement, in no event shall either Party be entitled to receive any punitive, indirect or consequential damages unless same are a part of a third party claim for which a Party is seeking indemnification hereunder, REGARDLESS OF WHETHER CAUSED OR CONTRIBUTED TO BY THE SOLE, JOINT, COMPARATIVE OR CONCURRENT NEGLIGENCE OR STRICT LIABILITY OF THE OTHER PARTY.

ARTICLE XII

Obligations and Indemnification

Section 12.01 Seller’s Retained Obligations. Provided that the Closing occurs, Seller hereby retains all costs, expenses, liabilities and obligations of any kind or character related, applicable or attributable to (a) the ownership or operation of the Leases, insofar as they cover depths from the surface to the base of the Austin Chalk Formation, whether attributable to periods before, on or after the Effective Time; (b) the ownership or operation of the Assets for all periods of time prior to the Effective Time; and (c) the ownership or operation of Seller’s retained 15% interest in the Leases, insofar as they cover depths below the base of the Austin Chalk Formation, whether attributable to periods before, on or after the Effective Time (collectively, the “Retained Obligations”).

Section 12.02 Buyer’s Assumed Obligations. Provided that the Closing occurs, except to the extent Seller has an indemnity obligation under Section 12.04 and except for the Retained Obligations, Buyer hereby assumes a proportionate share of all duties, obligations and liabilities of every kind and character related, applicable or attributable to the ownership or operation of Buyer’s interest in the Assets from and after the Effective Time (collectively, the “Assumed Obligations”).

Section 12.03 Buyer’s Indemnification. PROVIDED THAT THE CLOSING OCCURS, EXCEPT TO THE EXTENT SELLER HAS AN INDEMNITY OBLIGATION UNDER SECTION 12.04, BUYER SHALL RELEASE, DEFEND, INDEMNIFY AND HOLD HARMLESS SELLER, ITS AFFILIATES, AND ITS AND THEIR RESPECTIVE OWNERS, OFFICERS, DIRECTORS, EMPLOYEES, AGENTS, PARTNERS, REPRESENTATIVES, MEMBERS, SHAREHOLDERS, AFFILIATES, SUBSIDIARIES, SUCCESSORS AND ASSIGNS (COLLECTIVELY, THE “SELLER INDEMNITEES”) FROM AND AGAINST ANY AND ALL CLAIMS, DAMAGES, LIABILITIES, LOSSES, CAUSES OF ACTION, COSTS AND EXPENSES (INCLUDING, WITHOUT LIMITATION, INVOLVING THEORIES OF NEGLIGENCE OR STRICT LIABILITY AND INCLUDING COURT COSTS AND ATTORNEYS’ FEES) (“LOSSES”) AS A RESULT OF, ARISING OUT OF, OR RELATED TO THE ASSUMED OBLIGATIONS OR ANY INACCURACY OR BREACH OF ANY REPRESENTATION, WARRANTY OR COVENANT OF BUYER CONTAINED IN THIS AGREEMENT THAT SURVIVES THE CLOSING, REGARDLESS OF WHETHER CAUSED OR CONTRIBUTED TO BY THE SOLE, JOINT, COMPARATIVE OR CONCURRENT NEGLIGENCE OR STRICT LIABILITY OF ANY OF THE SELLER INDEMNITEES EXCLUDING ANY SELLER INDEMNITEE’S GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.

Section 12.04 Seller’s Indemnification. PROVIDED THAT THE CLOSING OCCURS, SELLER SHALL RELEASE, DEFEND, INDEMNIFY AND HOLD HARMLESS BUYER, ITS AFFILIATES, AND ITS AND THEIR RESPECTIVE OFFICERS, DIRECTORS, EMPLOYEES, AGENTS, PARTNERS, REPRESENTATIVES, MEMBERS, SHAREHOLDERS, AFFILIATES AND SUBSIDIARIES (COLLECTIVELY, THE “BUYER INDEMNITEES”) FROM AND AGAINST ANY AND ALL LOSSES AS A RESULT OF, ARISING OUT OF, OR RELATED TO (A) THE RETAINED OBLIGATIONS, OR (B) ANY INACCURACY OR BREACH OF ANY REPRESENTATION, WARRANTY OR COVENANT OF SELLER CONTAINED IN THIS AGREEMENT THAT SURVIVES THE CLOSING, OR (C) CLAIMS OF SELLER OR ITS SUCCESSORS OR ASSIGNS IN CONNECTION WITH BUYER FRACING INTO THE AUSTIN CHALK FORMATION WHILE FRACING IN A WELLBORE LOCATED IN THE EAGLE FORD SHALE FORMATION OR IN ANY OTHER FORMATION OR DEPTH BELOW THE BASE OF THE AUSTIN CHALK FORMATION OR WHILE FRACING IN THAT PORTION OF ANY WELLBORES FOR HORIZONTAL WELLS AFTER SUCH WELLBORES FIRST ENCOUNTER THE EAGLE FORD SHALE FORMATION, OR (D) CLAIMS OF SELLER OR ITS SUCCESSORS OR ASSIGNS IN CONNECTION WITH BUYER ENCOUNTERING THE AUSTIN CHALK FORMATION “D” ZONE IN THAT PORTION OF ANY WELLBORES FOR HORIZONTAL WELLS AFTER SUCH WELLBORES FIRST ENCOUNTER THE EAGLE FORD SHALE FORMATION, OR (E) CLAIMS OF SELLER OR ITS SUCCESSORS OR ASSIGNS IN CONNECTION WITH BUYER PRODUCING HYDROCARBONS FROM THE AUSTIN CHALK FORMATION FROM A WELLBORE DRILLED BY BUYER IN THE EAGLE FORD SHALE FORMATION OR IN ANY OTHER FORMATION OR DEPTH BELOW THE BASE OF THE AUSTIN CHALK FORMATION OR FROM THAT PORTION OF ANY WELLBORES FOR HORIZONTAL WELLS AFTER SUCH WELLBORES FIRST ENCOUNTER THE EAGLE FORD SHALE FORMATION, INSOFAR AS SUCH WELLBORES DO NOT SUBSEQUENTLY ENCOUNTER ANY DEPTH ABOVE THE AUSTIN CHALK FORMATION “D” ZONE, IN THE CASE OF ITEMS (C), (D) AND (E) ABOVE, TO THE EXTENT SUCH WELLBORES ARE IN AND UNDER LANDS COVERED BY THE LEASES AND WHETHER OR NOT THE WELLBORES ARE IN NEW WELLS DRILLED BY BUYER OR EXISTING WELLS SUBSEQUENTLY ASSIGNED BY SELLER TO BUYER, AND, IN EACH CASE, REGARDLESS OF WHETHER CAUSED OR CONTRIBUTED TO BY THE SOLE, JOINT, COMPARATIVE OR CONCURRENT NEGLIGENCE OR STRICT LIABILITY OF ANY OF THE BUYER INDEMNITEES EXCLUDING ANY BUYER INDEMNITEE’S GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.

Section 12.05 Indemnification Procedures. All claims for indemnification under this Agreement shall be asserted and resolved as follows:

(a) For purposes of this Section 12.05, the term “Indemnifying Party” when used in connection with particular Losses shall mean the party or parties having an obligation to indemnify another party or parties with respect to such Losses pursuant to this Agreement, and the term “Indemnified Party” when used in connection with particular Losses shall mean the party or parties having the right to be indemnified with respect to such Losses by another party or parties pursuant to this Agreement.

(b) To make claim for indemnification under this Agreement, an Indemnified Party shall notify the Indemnifying Party of its claim under this Section 12.05, including the specific details of and specific basis under this Agreement for its claim (the “Claim Notice”). In the event that the claim for indemnification is based upon a claim by a third party against the Indemnified Party (a “Claim”), the Indemnified Party shall provide its Claim Notice promptly after the Indemnified Party has actual knowledge of the Claim and shall enclose a copy of all papers (if any) served with respect to the Claim; provided that the failure of an Indemnified Party to give notice of a Claim as provided in this Section 12.05 shall not relieve the Indemnifying Party of its obligations under this Agreement except to the extent such failure results in insufficient time being available to permit the Indemnifying Party to effectively defend against the Claim or otherwise materially prejudices the Indemnifying Party’s ability to defend against the Claim.

(c) In the case of a claim for indemnification based upon a Claim, the Indemnifying Party shall have thirty (30) days from its receipt of the Claim Notice to notify the Indemnified Party whether it admits or denies its responsibility to defend the Indemnified Party against such Claim at the sole cost and expense of the Indemnifying Party. The Indemnified Party is authorized, prior to and during such thirty (30) day period, to file any motion, answer or other pleading that it shall deem necessary or appropriate to protect its interests or those of the Indemnifying Party and that is not prejudicial to the Indemnifying Party.

(d) If the Indemnifying Party admits its responsibility to defend the Indemnified Party against such Claim, it shall have the right and obligation to diligently defend the Claim, at its sole cost and expense. The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof. If requested by the Indemnifying Party, the Indemnified Party agrees to cooperate in contesting any Claim which the Indemnifying Party elects to contest. The Indemnified Party may participate in, but not control, any defense or settlement of any Claim controlled by the Indemnifying Party pursuant to this Section 12.05. An Indemnifying Party shall not, without the written consent of the Indemnified Party, (i) settle any Claim or consent to the entry of any judgment with respect thereto which does not include an unconditional written release of the Indemnified Party from all liability in respect of such Claim or (ii) settle any claim or consent to the entry of any judgment with respect thereto in any manner that may materially and adversely affect the Indemnified Party (other than as a result of money damages covered by the indemnity).

(e) If the Indemnifying Party does not admit its responsibility to defend the Indemnified Party against such Claim or admits its responsibility but fails to diligently prosecute or settle the Claim, then the Indemnified Party shall have the right to defend against the Claim at the sole cost and expense of the Indemnifying Party, with counsel of the Indemnified Party’s choosing, subject to the right of the Indemnifying Party to admit its liability and assume the defense of the Claim at any time prior to settlement or final determination thereof. If the Indemnifying Party has not yet admitted its responsibility for a Claim, the Indemnified Party shall send written notice to the Indemnifying Party of any proposed settlement and the Indemnifying Party shall have the option for ten (10) days following receipt of such notice to (i) admit in writing its responsibility for the Claim and (ii) if responsibility is so admitted, reject, in its reasonable judgment, the proposed settlement.

(f) In the case of a claim for indemnification not based upon a Claim, the Indemnifying Party shall have thirty (30) days from its receipt of the Claim Notice to (i) cure the Losses complained of, (ii) admit its responsibility for such Losses or (iii) dispute the claim for such Losses. If the Indemnifying Party does not notify the Indemnified Party within such 30 day period that it has cured the Losses or that it disputes the claim for such Losses, the amount of such Losses shall conclusively be deemed a liability of the Indemnifying Party hereunder.

ARTICLE XIII

Limitations on Representations and Warranties; and Casualty Losses

Section 13.01 Disclaimers of Representations and Warranties. The express representations and warranties of Seller contained in this Agreement and the Assignment are exclusive and are in lieu of all other representations and warranties, express, implied or statutory.

Section 13.02 Survival. Except as otherwise provided in Section 15.11, the representations, warranties, covenants and obligations of the Parties under this Agreement shall survive the Closing.

ARTICLE XIV

Arbitration

Section 14.01 Arbitrator.

(a) Either Party may submit disputes regarding Title Defects, Defect Values or calculation of the Final Statement or revisions thereto (each a “Dispute”), to an independent arbitrator appointed in accordance with this Section 14.01 (each, an “Independent Arbitrator”), who shall serve as sole arbitrator. The Independent Arbitrator shall be appointed by mutual agreement of the Parties from among candidates with experience and expertise in the area that is the subject of such Dispute, and failing such agreement, such Independent Arbitrator for such Dispute shall be selected as would a single arbitrator in accordance with the Rules (as hereinafter defined).

(b) Disputes to be resolved by an Independent Arbitrator shall be resolved in accordance with mutually agreed procedures and rules and failing such agreement, in accordance with the rules and procedures for arbitration provided in Section 14.02. The Independent Arbitrator shall be instructed by the Parties to resolve such Dispute as soon as reasonably practicable in light of the circumstances. The decision and award of the Independent Arbitrator shall be binding upon the Parties as an award under the Federal Arbitration Act and final and nonappealable to the maximum extent permitted by law, and judgment thereon may be entered in a court of competent jurisdiction and enforced by any Party as a final judgment of such court.

Section 14.02 Rules and Procedures.

(a) Such arbitration shall be conducted pursuant to the Federal Arbitration Act, except as expressly provided otherwise in this Agreement. The validity, construction, and interpretation of this Section 14.02, and all procedural aspects of the arbitration conducted pursuant hereto shall be decided by the Independent Arbitrator. The arbitration shall be administered by the American Arbitration Association (the “AAA”), and shall be conducted pursuant to the Commercial Arbitration Rules of the AAA (the “Rules”), except as expressly provided otherwise in this Agreement. The arbitration proceedings shall be subject to any optional rules contained in the Rules for emergency measures and, in the case of Disputes with respect to amounts in excess of $1 million, optional rules for large and complex cases.

(b) Venue. All arbitration proceedings hereunder shall be conducted in Houston, Texas or such other mutually agreeable location.

(c) Substantive Law. In deciding the substance of the Dispute, the Independent Arbitrator shall refer to the substantive laws of the State of Texas for guidance (excluding choice-of-law principles that might call for the application of the laws of another jurisdiction). Matters relating to arbitration shall be governed by the Federal Arbitration Act.

(d) Fees and Awards. The fees and expenses of the Independent Arbitrator shall be borne equally by the Parties, but the decision of the Independent Arbitrator may include such award of the Independent Arbitrator’s fees and expenses and of other costs and attorneys’ fees as the Independent Arbitrator determines appropriate (provided that such award of costs and fees may not exceed the amount of such costs and fees incurred by the winning Party in the arbitration).

(e) Binding Nature. The decision and award of the Independent Arbitrator shall be binding upon the Parties and final and nonappealable to the maximum extent permitted by law, and judgment thereon may be entered in a court of competent jurisdiction and enforced by any Party as a final judgment of such court.

ARTICLE XV

Miscellaneous

Section 15.01 Recording Expenses. Buyer shall pay all recording fees arising from the recordation of the Assignment and the other documents delivered at Closing, except that Seller shall pay all recording fees arising from the recordation of the lien release documents delivered by Seller at Closing. Each Party shall be solely responsible for all expenses, including due diligence expenses, incurred by it in connection with this transaction, and neither Party shall be entitled to any reimbursement for such expenses from the other Party.

Section 15.02 Entire Agreement. This Agreement, the documents to be executed hereunder, and the exhibits attached hereto constitute the entire agreement between the Parties pertaining to the subject matter hereof and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of the Parties pertaining to the subject matter hereof. No supplement, amendment, alteration, modification or waiver of this Agreement shall be binding unless executed in writing by the Parties and specifically referencing this Agreement.

Section 15.03 Waiver. Unless it is a waiver which is deemed to have been made automatically at the expiration of a time limit under this Agreement, any waiver must be in writing executed by the waiving party and no waiver of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provisions hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided.

Section 15.04 Publicity. Seller and Buyer shall consult with each other with regard to all publicity and other disclosures concerning this Agreement or the documents to be executed hereunder (including any term or condition hereof), the transactions contemplated hereby, the status of such transactions and the negotiations related thereto, and, except as required by applicable law or the applicable rules or regulations of any Governmental Authority or stock exchange, neither Seller nor Buyer shall issue any publicity or press release without the prior written consent of the other Party, such consent not to be unreasonably withheld.

Section 15.05 Construction. The captions in this Agreement are for convenience only and shall not be considered a part of or affect the construction or interpretation of any provision of this Agreement. The Parties acknowledge that they have participated jointly in the negotiation and drafting of this Agreement and as such the Parties agree that if an ambiguity or question of intent or interpretation arises hereunder, this Agreement shall not be construed more strictly against one Party than another on the grounds of authorship.

Section 15.06 No Third Party Beneficiaries. Except as provided in Sections 12.03 and 12.04, nothing in this Agreement shall provide any benefit to any third party or entitle any third party to any claim, cause of action, remedy or right of any kind, it being the intent of the Parties that this Agreement shall otherwise not be construed as a third party beneficiary contract.

Section 15.07 Assignment. Neither Party may assign or delegate any of its rights or obligations hereunder without the prior written consent of the other Party and any assignment made without such consent shall be void. Except as otherwise provided herein, this Agreement shall be binding upon and inure to the benefit of the Parties hereto and their respective permitted successors, assigns and legal representatives.

Section 15.08 GOVERNING LAW; VENUE; JURY WAIVER. THIS AGREEMENT, THE OTHER DOCUMENTS DELIVERED PURSUANT HERETO AND THE LEGAL RELATIONS BETWEEN THE PARTIES SHALL BE GOVERNED AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS, EXCLUDING ANY CONFLICTS OF LAW, RULE OR PRINCIPLE THAT MIGHT REFER CONSTRUCTION OF THIS AGREEMENT AND SUCH OTHER DOCUMENTS TO THE LAWS OF ANOTHER JURISDICTION. ALL OF THE PARTIES HERETO CONSENT TO THE EXERCISE OF JURISDICTION IN PERSONAM BY THE COURTS OF THE STATE OF TEXAS FOR ANY ACTION ARISING OUT OF THIS AGREEMENT OR THE OTHER DOCUMENTS EXECUTED PURSUANT TO OR IN CONNECTION WITH THIS AGREEMENT. ALL ACTIONS OR PROCEEDINGS WITH RESPECT TO, ARISING DIRECTLY OR INDIRECTLY IN CONNECTION WITH, OUT OF, RELATED TO OR FROM THIS AGREEMENT OR THE OTHER DOCUMENTS EXECUTED PURSUANT TO OR IN CONNECTION WITH THIS AGREEMENT SHALL BE EXCLUSIVELY LITIGATED IN COURTS HAVING SITES IN HOUSTON, HARRIS COUNTY, TEXAS. EACH PARTY HERETO WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY A JURY IN RESPECT OF ANY ACTION, SUIT OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT.

Section 15.09 Notices. Any notice, communication, request, instruction or other document required or permitted hereunder shall be given in writing and delivered in person or sent by U.S. Mail postage prepaid, return receipt requested, overnight courier, facsimile or electronic mail to the addresses of Seller and Buyer set forth below. Any such notice shall be effective only upon receipt.

	Addressed to:	With copy to:
Seller:	Lucas Energy, Inc. 6800 West Loop South, Suite 415 Bellaire, Texas 77401 Attention: William A. Sawyer Fax No.: 713-337-1510 Email: wsawyer@lucasenergy.com	Lucas Energy, Inc. 6800 West Loop South, Suite 415 Bellaire, Texas 77401 Attention: Don Sytsma Fax No.: 713-337-1510 Email: dsytsma@lucasenergy.com

	Addressed to:	With copy to:
Buyer:	Hilcorp Energy I, L.P. c/o Hilcorp Energy Company 1201 Louisiana, Suite 1400 Houston, Texas 77002 Attention: Curtis Smith Fax No.: 713-209-2420 Email: csmith@hilcorp.com	Hilcorp Energy I, L.P. c/o Hilcorp Energy Company 1201 Louisiana, Suite 1400 Houston, Texas 77002 Attention: William P. Swenson Fax No.: 713-289-2650 Email: bswenson@hilcorp com

Either Party may, by written notice so delivered to the other Party, change its address for notice purposes hereunder.

Section 15.10 Severability. If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any rule of law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect and the Parties shall negotiate in good faith to modify this Agreement so as to effect their original intent as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

Section 15.11 Survival. The representations and warranties of Seller set forth in Sections 5.06 through 5.16 hereof shall survive the Closing for a period of one (1) year. All other representations, warranties, covenants and agreements contained in this Agreement shall survive the Closing indefinitely.

Section 15.12 Time of the Essence. Time shall be of the essence with respect to all time periods and notice periods set forth in this Agreement.

Section 15.13 Counterpart Execution. This Agreement may be executed in any number of counterparts, and each counterpart hereof shall be effective as to each Party that executes the same whether or not all of such parties execute the same counterpart. If counterparts of this Agreement are executed, the signature pages from various counterparts may be combined into one composite instrument for all purposes. All counterparts together shall constitute only one Agreement, but each counterpart shall be considered an original.

Section 15.14 Attorney Fees. If any Party institutes an action or proceeding against any other Party relating to the provisions of this Agreement, including arbitration, the Party to such action or proceeding which does not prevail will reimburse the prevailing Party therein for the reasonable expenses of attorneys' fees and disbursements incurred by the prevailing Party.

Section 15.15 Interpretation. This Agreement shall be deemed and considered for all purposes to have been jointly prepared by the Parties, and shall not be construed against any one Party (nor shall any inference or presumption be made) on the basis of who drafted this Agreement or any particular provision hereof, who supplied the form of Agreement, or any other event of the negotiation, drafting or execution of this Agreement. Each Party agrees that this Agreement has been purposefully drawn and correctly reflects its understanding of the transaction that it contemplates. In construing this Agreement, the following principles will apply:

(a) A defined term has its defined meaning throughout this Agreement and in each Exhibit and Schedule to this Agreement, regardless of whether it appears before or after the place where it is defined.

(b) If there is any conflict or inconsistency between the provisions of the main body of this Agreement and the provisions of any Appendix, Exhibit or Schedule hereto, the provisions of this Agreement shall take precedence. If there is any conflict between the provisions of any of the Assignment or other transaction documents attached to this Agreement as an Exhibit and the provisions of any Assignment and other transaction documents actually executed by the parties, the provisions of transaction documents actually executed shall take precedence.

(c) The Exhibits and Schedules referred to herein are hereby incorporated and made a part of this Agreement for all purposes by such reference.

(d) The omission of certain provisions of this Agreement from the Assignment does not constitute a conflict or inconsistency between this Agreement and the Assignment, and will not effect a merger of the omitted provisions. To the fullest extent permitted by law, all provisions of this Agreement are hereby deemed incorporated into the Assignment by reference.

(e) The word “includes” and its derivatives means “includes, but not limited to” and corresponding derivative meanings.

(f) The Article, Section, Exhibit and Schedule references in this Agreement refer to the Articles, Sections, Exhibits and Schedules of this Agreement. The headings and titles in this Agreement are for convenience only and shall have no significance in interpreting or otherwise affect the meaning of this Agreement.

(g) The plural shall be deemed to include the singular, and vice versa.

(h) As used in this Agreement, the phrases “to Seller’s knowledge,” “to the knowledge of Seller,” and similar phrases shall mean to the actual or constructive knowledge of any officer or employee of Seller actively involved in the management or operation of any of the Assets, in each case, after due inquiry.

Section 15.16 Tax-Deferred Exchange.

(a) Notwithstanding any other provision of this Agreement, in the event either Party so elects, the other Party shall accommodate such Party in effecting a tax-deferred exchange under Internal Revenue Code section 1031, as amended. Either Party shall have the right to elect this tax-deferred exchange at any time prior to the Closing Date. If either Party elects to effect a tax-deferred exchange, the other Party shall execute such escrow instructions, documents, agreements or instruments to effect an exchange, as the electing Party may reasonably request, it being understood that the other Party shall not be required to incur additional costs, expenses, fees or liabilities, not reimbursed or indemnified by the electing Party, as a result of or connection with an exchange.

(b) Either Party may assign its rights and delegate its duties under this Agreement in whole or in part to a third party in order to effect such an exchange; provided that the electing Party shall remain responsible to the other Party for the full and prompt performance of any delegated duties. The electing Party shall indemnify and hold the other Party and its affiliates harmless from and against all claims, expenses (including reasonable attorneys’ fees), loss and liability resulting from the other Party’s participation in any exchange undertaken pursuant to this Section 15.16.

[SIGNATURE PAGE TO FOLLOW]

IN WITNESS WHEREOF, Seller and Buyer have executed and delivered this Agreement as of the date first set forth above.

	SELLER:

	LUCAS ENERGY, INC.

		/ s / William A. Sawyer
	By:
		William A. Sawyer
		President and Chief Executive Officer

	BUYER:

	HILCORP ENERGY I, L.P.
	By:	Hilcorp Energy Company,
		its general partner

		/ s / Curtis D. Smith
	By:
		Curtis D. Smith
		Vice President - Land

EX-99.1 9 ex99_1.htm EXHIBIT 99.1 ex99_1.htm

EXHIBIT 99.1

ESTIMATED RESERVES AND FUTURE NET REVENUE

AS OF

APRIL 1, 2010

ATTRIBUTABLE TO INTERESTS

OWNED BY

LUCAS ENERGY INC.

IN CERTAIN PROPERTIES

LOCATED IN

TEXAS

(SEC CASE)

	FORREST A. GARB & ASSOCIATES, INC.
	INTERNATIONAL PETROLEUM CONSULTANTS

FORREST A. GARB & ASSOCIATES, INC.

INTERNATIONAL PETROLEUM CONSULTANTS

5310 HARVEST HILL ROAD, SUITE 275, LB 152

DALLAS, TEXAS 75230 - 5805

(972)788-1110 Telefax (972)991-3160 (E MAIL) forgarb@forgarb.com

July 1, 2010

Mr. William A. Sawyer

Lucas Energy Inc.

6800 West Loop South, Suite 415

Bellaire, TX 77401

Re: SEC Case

Dear Mr. Sawyer:

At your request, Forrest A. Garb & Associates, Inc. (FGA) has estimated the reserves and future net revenue, as of April 1, 2010, attributable to interests owned by Lucas Energy, Inc. (Lucas) in certain oil and gas properties located in Atascosa, Gonzales, Karnes, and Wilson counties, Texas. It is our understanding that the proved reserves in this report constitute all of the proved reserves owned by Lucas. This report has been prepared for Lucas’ use in filing with the U.S. Securities and Exchange Commission (SEC).

The following table summarizes the estimated net reserves and revenue:

	Estimated Net Reserves1				Estimated Future Net Revenue
Reserve Category	Oil and Condensate (MBbl)2		Gas (MMcf)3		Undiscounted (M$)4		Discounted at 10% Per Year5 (M$)4
Proved
Producing		73.01		11.76		2,007.98		1,614.72
Non-producing		63.54		19.41		3,034.00		2,549.30
Undeveloped		1,833.68		0.00		76,689.64		43,354.36
Total Proved6		1,970.23		31.17		81,731.63		47,518.38

Probable
Undeveloped		680.77		0.00		25,367.35		4,464.91
Total Probable6		680.77		0.00		25,367.35		4,464.91

1	The definitions for all reserves incorporated in this study have been set forth in this report.

2	M$ = thousands of dollars.

3	MBbl = thousands of barrels.

4	MMcf = millions of cubic feet.

5	The discounted future net revenue is not represented to be the fair market value of these reserves.

6	The reserves and revenues in the summary table were estimated using the PHDWin economics program. Due to the rounding procedures used in this program, there may be slight differences in the calculated and summed values.

FORREST A. GARB & ASSOCIATES, INC.

This report has been prepared using the SEC’s new definitions and guidelines, and with the exception of the exclusion of future income taxes, conforms to the FASB Accounting Standards Codification Topic 932, Extractive Industries – Oil and Gas. The new guidelines specify: 1) the use of a 12-month first-of-the-month average benchmark price, 2) the use of reliable technologies to establish reserves estimates, 3) requires proved undeveloped locations be drilled within five years, 4) the change from certainty to reasonable certainty for proved undeveloped reserves, 5) a 10 percent discount factor, and 6) constant prices and costs.

The attached report presents projections of production and revenue for the interests studied. Also provided is a discussion of geology, engineering, and economic considerations incorporated in the forecasts.

GEOLOGY

Lucas’ holdings in Atascosa, Gonzales, Karnes, and Wilson counties are found in a broad area of current industry activity concentrating on three vertically adjacent targets: Austin Chalk, Eagle Ford, and Buda Limestone, in order of increasing depth. Activity in this area has been uninterrupted since the late 1970’s. The recent development of the Eagle Ford as a high-potential producing zone has heightened industry interest and success. Lucas’ acreage position is well positioned in the oil window of the Eagle Ford play.

Lucas’ original activity started in Gonzales County by acquiring existing shut-in and stripper wells and improving production in those wells. Most of the wells had produced from the Austin Chalk. Lucas’ original approach was to open more of the Austin Chalk to the wellbore by drilling deeper into the formation and re-stimulating these wells. The Austin Chalk is a dense limestone, varying in thickness along its trend from approximately 200 feet to more than 800 feet. It produces by virtue of localized, highly-fractured intervals within the formation; and seismic data can be used to help identify these fractured zones. Rapid development of the Austin Chalk began with the growth of the Giddings field, which eventually expanded to include a long, narrow trend which extends from the Texas-Mexico border up through northeast Texas into Louisiana. Original drilling was done with vertical holes, but the current horizontal drilling techniques have greatly expanded development. Lucas employs both vertical and horizontal drilling in its ongoing Austin Chalk development.

The Eagle Ford is the newcomer in Lucas’ portfolio of opportunities. Drilling activity by other operators over the past two years, and the improvement in horizontal drilling, well stimulation, and completion technologies, have brought the Eagle Ford play to prominence as one of the foremost plays in the United States today. A few of the more active companies in this play include Pioneer Natural Resources, Apache Corporation, ConocoPhillips, PetroHawk Energy, and EOG Resources, Inc. Figure 1 is a map of a portion of the more active parts of the Eagle Ford trend taken from an April 2010 presentation by Pioneer. This figure illustrates the widely recognized segregation of this trend into three areas. The updip shallower portion is primarily oil production, the deeper, more downdip, regions are mostly dry gas, and the middle parts of the trend produce a mix of gas and condensate (wet gas). Most of Lucas’ leases are in the oil and wet gas windows.

FORREST A. GARB & ASSOCIATES, INC.

Figure 1: Eagle Ford Active Trend

On Lucas leases, the Eagle Ford is a shaly limestone with a high content of organic matter that directly underlies the Austin Chalk and is believed to be the primary source of oil and gas produced from the Austin and the Buda, as well as the Eagle Ford. Reservoir thickness varies from approximately 80 feet in the shallower portions of the trend to more than 300 feet in the deeper areas. One of the more notable Eagle Ford producers is the #1 Domingo Torres well, originally completed in the Eagle Ford in 1977. This vertical well is positioned among Lucas’ Gonzales County leases and has produced a total of more than 140,000 barrels of oil. Figure 2 shows the current state of Eagle Ford activity, both completed and permitted wells, as of April 16, 2010, as reflected in records from the Texas Railroad Commission.

Lucas recently logged the Eagle Ford, as well as the Austin and Buda, in multiple wells with a Reservoir Monitoring Tool. This sophisticated device provides an excellent portrayal of the porosity, hydrocarbon content, and brittleness of the Eagle Ford, and is helpful in recognizing better productive capacity. Lucas has successfully tested multiple vertical wells in the Eagle Ford, and includes horizontal development drilling in the Eagle Ford in their future operations.

FORREST A. GARB & ASSOCIATES, INC.

Figure 2: Eagle Ford Wells

The Buda limestone directly underlies the Eagle Ford. Its thickness varies from approximately 100 feet to more than 150 feet in this area. Like the Austin Chalk, the Buda produces from natural fractures and is prospective across this whole area. Typically the Buda is the least prolific of these three zones, but there are a number of Buda wells with cumulative production of more than 100,000 barrels of oil. Lucas has re-completed wells which previously produced from the Buda, and deepened and successfully completed other wells in the Buda with success. Future development plans include more of this type of activity in both vertical and horizontal wells.

ENGINEERING

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible from a given date forward. The basis for estimating the proved producing reserves was the extrapolation of historical production having an established decline trend. Analogy to adjacent Austin Chalk, Buda and Eagle Ford wells was used for forecasting properties where insufficient production data were present for decline extrapolation. Additional data which proved the oil window of the Eagle Ford in Lucas’ lease holdings are recent Eagle Ford successful completions by area operators, the production history of the Domingo Torres well, and Lucas well tests in the Norris and Ervin wells. Volumetrics and/or analogy were used for forecasting properties where insufficient data were present for production decline extrapolation.

FORREST A. GARB & ASSOCIATES, INC.

Production histories were provided by Lucas and checked using published production data and state reporting records. The reserves for other reserve categories were estimated by the volumetric method considering well logs, core analyses, geologic maps, etc., and/or by analogy to adjacent comparable wells. FGA has accepted Lucas’ intent to drill the proved and probable undeveloped locations. The SEC requires a development plan be in place for these assets. This reserve report defines a budget for that development plan, but FGA makes no representation about the company’s ability to fund this development.

The analysis and findings presented in this report, with the exceptions of parameters specified by others, represent FGA’s informed judgments based on accepted standards of professional engineering practice, but are subject to the generally recognized and unforeseen risks associated with the interpretation of geological, geophysical, and engineering data. Future changes in federal, state, or local regulations may adversely impact the ability to recover the future oil and gas volumes expected. Changes in economic and market conditions from the assumptions and parameters used in this study may cause the total quantity of future oil or gas recovered, actual production rates, prices received, operating expenses and capital costs to vary from the results presented in this report.

The available geologic and engineering data were furnished by Lucas for FGA's review. Gas volumes are expressed in millions of cubic feet (MMcf) at standard temperature and pressure. Gas sales imbalances have not been taken into account in the reserve estimates. The oil reserves shown in this study include crude oil and/or condensate. Oil volumes are expressed in thousands of barrels (MBbl), with one barrel equivalent to 42 United States gallons.

ECONOMICS

The benchmark oil and gas prices used in this study are the prior 12-month average of the first trading-day of the month spot prices posted for the West Texas Intermediate (WTI) oil and Henry Hub natural gas, per the SEC’s guidelines. Oil prices are based on a benchmark price of $69.54 per barrel and have been adjusted by lease for gravity, transportation fees, and regional price differentials. Gas prices per thousand cubic feet (MCF) are based on a benchmark price of $3.96 per million British thermal units (MMBtu) and have been adjusted by lease for Btu content, transportation fees, and regional price differentials. The adjustment is based on the differential between historic oil and gas sales and the corresponding benchmark price. The oil and gas prices were held constant for the economic life of the properties as specified by the SEC.

Lease operating cost data were provided by Lucas for FGA’s review. The average lease operating costs and overhead costs for the prior 12 months for each property were utilized for this study. Capital expenditures are included as required for workovers, the future development of new wells, and for production equipment. All costs have been held constant in this evaluation. Existing or potential liabilities stemming from environmental conditions caused by current or past operating practices have not been considered in this report. No costs are included in the projections of future net revenue or in our economic analyses to restore, repair, or improve the environmental conditions of the properties studied to meet existing or future local, state, or federal regulations.

The estimated future net revenues shown are those that should be realized from the sale of estimated oil and gas reserves after deduction of severance taxes, ad valorem taxes, and direct operating costs. No deductions have been made for federal income taxes or other indirect costs, such as interest expense and loan repayments. Surface and well equipment salvage values have not been considered in the revenue projections. The estimated reserves included in the cash flow projections have not been adjusted for risk. The reserves included in this study are estimates only and should not be construed as exact quantities. They may or may not be actually recovered; and, if recovered, the actual revenues and associated costs could be more or less than the estimated amounts. Future conditions may affect recovery of estimated reserves and revenue, and all categories of reserves may be subject to revision as more performance data become available.

FORREST A. GARB & ASSOCIATES, INC.

Grand total summary projections by category and category summaries (including one-line summaries for the individual properties) are presented in Attachment A. The individual properties have been ranked in descending order of discounted future net revenue value. This ranking is presented as Attachment B. Attachment C is a master list of all properties.

Individual projections and graphs of historical and forecast production are provided in Attachment D for proved developed producing, proved non-producing, proved undeveloped, and probable undeveloped properties. Attachment E presents the definitions of oil and gas reserves in accordance with the U.S. Securities and Exchange Commission (SEC), as of January 1, 2010. General comments regarding this report and the estimation of future reserves and revenue are presented in Attachment F. Attachment G contains the consulting firm profile.

Lucas provided ownership interest in the properties, and FGA accepted the extent and character of ownership (working interest and net revenue interest) as represented. Our staff conducted no independent well tests, property inspections, or audits of completion and operating expenses as part of this study.

FGA is an independent firm of geologists and petroleum engineers. Neither the firm nor its employees own any interest in the properties studied, nor have we been employed on a contingency basis.

We appreciate the opportunity to submit this evaluation. Should you have any questions, please do not hesitate to call.

This report was prepared under the supervision of W.D. Harris III, Registered Professional Engineer No. 75222, State of Texas.

Yours truly,

/s/ Forrest A. Garb & Associates, Inc.

Forrest A. Garb & Associates, Inc.

Texas Registered Engineering Firm F-629

/s/ W. D. Harris III

W. D. Harris III

Chief Executive Officer

Forrest A. Garb & Associates, Inc.

FORREST A. GARB & ASSOCIATES, INC.

ATTACHMENTS

CATEGORY AND ONE-LINE SUMMARIES

RANKING OF PROVED PROPERTIES IN DESCENDING ORDER OF DISCOUNTED FUTURE NET REVENUE VALUE

MASTER INDEX OF PROPERTIES

INDIVIDUAL PROJECTIONS AND GRAPHS OF HISTORICAL AND FORECAST PRODUCTION

DEFINITIONS FOR OIL AND GAS RESERVES (1)

GENERAL COMMENTS (1)

CONSULTING FIRM PROFILE (1)

(1)

Filed herewith.

FORREST A. GARB & ASSOCIATES, INC.

ATTACHMENT E

DEFINITIONS FOR OIL AND GAS RESERVES

FORREST A. GARB & ASSOCIATES, INC.

DEFINITIONS FOR OIL AND GAS RESERVES*

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

ATTACHMENT E - 1

FORREST A. GARB & ASSOCIATES, INC.

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

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

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or G&G costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

ATTACHMENT E - 2

FORREST A. GARB & ASSOCIATES, INC.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities. (i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

( 1 )

Lifting the oil and gas to the surface; and

( 2 )

Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

ATTACHMENT E - 3

FORREST A. GARB & ASSOCIATES, INC.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

ATTACHMENT E - 4

FORREST A. GARB & ASSOCIATES, INC.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs. (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience 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—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

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FORREST A. GARB & ASSOCIATES, INC.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during 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, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. 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.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

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FORREST A. GARB & ASSOCIATES, INC.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir ( i.e. , absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources ( i.e. , potentially recoverable resources from undiscovered accumulations).

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category 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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can 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 the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

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FORREST A. GARB & ASSOCIATES, INC.

ATTACHMENT F

GENERAL COMMENTS

FORREST A. GARB & ASSOCIATES, INC.

GENERAL COMMENTS

(1)

The reserve estimates presented in this report have been calculated using deterministic procedures. The reserves shown in this report are those estimated to be recoverable under the new guidelines of the Securities and Exchange Commission (SEC). The definitions for oil and gas reserves in accordance with SEC Regulation S-X are set forth in this report.

(2)

The estimated future net revenue shown in the cash flow projections is that revenue which should be realized from the sale of the estimated net reserves. Surface and well equipment salvage values have not been considered in the revenue projections. Future net revenue as stated in this report is before the deduction of federal income tax.

(3)

The discounted future net revenue is not represented to be the fair market value of these reserves. The estimated reserves included in the cash flow projections have not been adjusted for risk.

(4)

The reserves included in this study are estimates only and should not be construed as exact quantities. Future conditions may affect recovery of estimated reserves and revenue, and all categories of reserves may be subject to revision as more performance data become available.

(5)

Extent and character of ownership, oil and gas prices, production data, direct operating costs, required capital expenditures, and other data furnished have been accepted as represented. No independent well tests, property inspections, or audits of operating expenses were conducted by our staff in conjunction with this study.

(6)

If investments or business decisions are to be made in reliance on these estimates by anyone other than our client, such a person, with the approval of our client, is invited to visit our offices at his own expense so that he can evaluate the assumptions made and the completeness and extent of the data available on which our estimates are based.

(7)

Forrest A. Garb and Associates has used all methods and procedures it considers necessary to evaluate the reserves and future revenues included in the report.

(8)

Gas contract differences, including take or pay claims, are not considered in this report.

(9)

Gas sales imbalances have not been taken into account in the reserve estimates.

(10)

Unless otherwise stated in the text, existing or potential liabilities stemming from environmental conditions caused by current or past operating practices have not been considered in this report. No costs are included in the projections of future net revenue or in our economic analyses to restore, repair, or improve the environmental conditions of the properties studied to meet existing or future local, state, or federal regulations.

(11)

Any distribution of this report or any part thereof must include these general comments and the cover letter in their entirety.

(12)

This report was prepared under the supervision of W.D. Harris III, Registered Professional Engineer No. 75222, State of Texas.

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FORREST A. GARB & ASSOCIATES, INC.

ATTACHMENT G

CONSULTING FIRM PROFILE

FORREST A. GARB & ASSOCIATES, INC.

INTERNATIONAL PETROLEUM CONSULTANTS

5310 HARVEST HILL ROAD, SUITE 275, LB 152

DALLAS, TEXAS 75230 – 5805

(972) 788-1110 Fax (972) 991-3160

E-Mail: forgarb@forgarb.com

Web Site: www.forgarb.com

We are pleased to present this profile of Forrest A. Garb & Associates, Inc. (FGA). FGAis an international petroleum engineering and geologic consulting firm staffed by experienced engineers and geologists. Collectively our staff has more than a century of world-wide experience. FGA has no outside ownership. And the firm has no direct or contingent participation in oil or gas ventures. There are no conflicts of interest or concerns about maintaining the confidentiality of our client’s data. The company is dedicated to providing the highest level of integrity, technology, and service.

FGA expertise includes:

• Exploration and Prospect Evaluations

• Reserve Estimation and Evaluation Studies

• Fair Market Value Analyses

• Economic and Market Analyses

• Forensic Engineering and Expert Witness Testimony

• Reservoir Engineering

• Regional and Detailed Geological Studies

• Numeric Simulation Studies

• Special Computer Applications

• Pressure Transient Test Design, Supervision, and Evaluation

• Reservoir Characterization

• Geostatistical Studies

• Oil & Gas Production Environmental Studies

• Minerals Evaluations

• Petrophysical Analyses

OUR SENIOR STAFF

Mr. Forrest A. Garb, Founder, Chairman of the Board and Chief Engineer Emeritus, with more than 50 years of practical petroleum industry experience, was a staff member and then a principal of a major consulting firm for over 30 years, serving as president and chief operating officer of this firm for the last 14 of those years. During his tenure, he supervised or prepared over 12,500 assignments varying from simple evaluations to complex reservoir simulations. Using this experience as a base, he assembled the best work system offered to the oil and gas industry. The use of state of the art computers and office equipment, together with an experienced staff, ensures economic service to the client.

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FORREST A. GARB & ASSOCIATES, INC.

Mr. William D. Harris III, P.E. joined FGA in August 1998, and is now the Chief Executive Officer. Previously, he was a Vice President with DeGolyer and MacNaughton where he prepared and supervised engineering studies and reserve and appraisal reports for fields in many countries. Mr. Harris holds a B.S. in Petroleum Engineering from Texas A&M University and a M.B.A. from Southern Methodist University. He is a member of the Society of Petroleum Engineers and is a registered professional engineer in the state of Texas.

Mr. John Cooper, Senior Geologist, joined Forrest A. Garb & Associates, Inc. in 2007. Mr. Cooper received his Bachelor's degree in Geology from the University of Louisiana -Lafayette (formerly the University of Southwestern Louisiana) and holds an MBA from Tulane University. He was employed at Great Southern Oil and Gas, Innex Energy, and Hunt Petroleum in various geological and technical positions, and is experienced in log analysis, geological interpretations, and reserves evaluations using the latest technologies. Mr. Cooper is a member of the American Association of Petroleum Geologists, the Society of Economic Geophysicists,and the Dallas Geological & Geophysical Society.

Mr. Gerald K. Ebanks, Senior Geologist, received his M.A. degree in geology from the University of Texas at Austin and has more than 35 years of experience in petroleum geology. He was employed with Mobil Oil Corporation, and subsequently with Ray Holifield and Associates, and PXI, Incorporated, in various geological positions. Mr. Ebanks is a member of the American Association of Petroleum Geologists, Dallas Geological Society, Houston Geological Society, and is a certified petroleum geologist.

Mr. Enrique Gonzalez-Gerth, P.E., Senior Vice President of Engineering and Director, brings more than 30 years of international and domestic experience to the firm. He has performed a wide range of reservoir engineering analyses including oil and gas property evaluations, reservoir performance predictions, and secondary recovery studies. Mr. Gonzalez-Gerth is fluent in Spanish, permitting precise communication with Spanish-speaking clients. He is a registered professional engineer in the state of Texas and is a member of the Society of Petroleum Engineers and the Society of Hispanic Professional Engineers.

Ms. Stacy M. Light, Senior Reservoir Engineer, joined Forrest A. Garb & Associates, Inc. in May 2010 as a reservoir engineer. Ms. Light previously worked for ARCO Oil and Gas as a reservoir/operations engineer and crude oil risk management director. She performed detailed production, reservoir and economic analyses for both onshore and offshore properties, and supervised engineers in the same capacity. She also performed risk management duties, trading crude oil futures and options on the New York Mercantile Exchange. Areas worked include onshore and offshore Gulf Coast and the mid-continent area. Ms. Light received a B.S. in Petroleum Engineering from Texas A&M University and is a member of the Society of Petroleum Engineers (SPE).

Mr. Claude M. (Mike) Rightmire, Senior Vice President Petroleum Engineering joined Forrest A. Garb & Associates, Inc. in December 2007, as a reservoir engineer. Mr. Rightmire previously worked for ARCO Alaska and ARCO Exploration & Production Technologies as a reservoir and operations engineer and most recently for Pinnacle Technologies as a senior engineer and project manager. His work experience includes over 25 years of operations andreservoir engineering assignments, reservoir engineering research and applications development work, and fracture stimulation engineering. Mr. Rightmire holds a B.S. in Petroleum Engineering from Texas A&M University, a B.S. in Biological Science from the University of Alaska Anchorage, and is a member of the Society of Petroleum Engineers (SPE).

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FORREST A. GARB & ASSOCIATES, INC.

Ms. Sandra W. Wall, Senior Vice President Petroleum Engineering joined Forrest A. Garb & Associates, Inc. in August 2006, as a reservoir engineer. Ms. Wall previously worked for Texas Eastern Corp., Exploration and Production Division. She performed detailed reservoir and economic analyses for both onshore and offshore properties, and ran 3D computer simulation studies for massive hydraulic fracturing, water floods, and CO2 floods. Areas worked include onshore and offshore Gulf Coast, Rocky Mountains, Offshore California, Indonesia, and North Sea. Ms. Wall holds a B.S. in Petroleum Engineering from Texas A&M University, a M.B.A. from Houston Baptist University, and is a member of the Society of Petroleum Engineers (SPE).

THE COMPANY

Forrest A. Garb & Associates, Inc. (FGA) is a consulting firm comprised of professional petroleum engineers, geologists, and technical support personnel with diversified backgrounds in all phases of the petroleum and energy industries. The group prides itself in offering the highest level of ethics, state of the art technology, and prompt dedicated service to our clients.

FGA professionals have extensive experience in the world's important hydrocarbon producing areas, including North and South America, the Middle East, Australia, New Zealand, Indonesia, Turkey, North Africa, Russia, China, Thailand, Myanmar, West Africa, India, the North Sea, Alaska, and Mexico.

The firm offers a complete range of geological and engineering services - from screening exploration prospects and designing development drilling projects to estimating reserves, forecasting future production, and presenting economic analyses. Major financial institutions accept the validity of our studies, particularly in the areas of reserve estimation and appraisal. The fair market value analysis technique developed by FGA is being applied by some of industry’s largest players. Major integrated and independent oil and gas companies have used our estimates of future production rates and available hydrocarbon resources to design facilities, and to establish contract terms.

FGA is a leader in the development and application of computers to the daily requirements of petroleum engineering. Mainframe programs, hand-held computer programs, and personal computer systems designed by Mr. Garb have been installed in many major integrated oil company offices around the world. Associations with facilities design, seismic interpretation, petrology, and environmental firms, renowned in their own right, enable the FGA organization to offer a complete service to its clients under one master contract.

Because the company has no hydrocarbon production and because it has no outside ownership to dictate opinions, the determinations of the firm are independent. Its studies are without bias and are based on the best interpretation of all available data after processing with "state of the art" methods and equipment.

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FORREST A. GARB & ASSOCIATES, INC.

FGA restricts its activities exclusively to consultation; it does not accept contingent fees nor does it own operating interests in any oil, gas, or mineral properties. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies.

The entire FGA staff is dedicated to providing each client with a personalized and cost efficient approach to serve their individual needs.

ATTACHMENT G - 4

	/s/ William D. Harris III
	William D. Harris III
	Chief Executive Officer

	/s/ Forrest A. Garb & Associates, Inc.
	Forrest A. Garb & Associates, Inc.
	Texas Registered Engineering Firm F-629
	Dallas, Texas