Glen Rose Petroleum CORP - FORM 10-K/A

Attached files

file	filename
EX-23 - Glen Rose Petroleum CORP	v163606_ex23.htm
EX-32 - Glen Rose Petroleum CORP	v163606_ex32.htm
EX-31.2 - Glen Rose Petroleum CORP	v163606_ex31-2.htm
EX-31.1 - Glen Rose Petroleum CORP	v163606_ex31-1.htm

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

Mark One:
	x Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Fiscal Year Ended March 31, 2007 or

	o Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Transition Period from ____________to_____________.

Commission File Number 0-9997

GLEN ROSE PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	87-0372864
(State of Incorporation)	(IRS Employer Identification No.)

Suite 200, 4925 Greenville Avenue, Dallas, Texas 75206
(Address of principal executive offices)

(214) 800-2663
(Registrant’s telephone number, including area code)

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

			Name of each exchange
	Title of each class		on which registered
	Common Stock, $0.001 par value		Nasdaq Capital Market

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

Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act during the past 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

Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B contained in this form, and no disclosure will be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K/A or any amendment to this Form 10-K/A. x

Indicate by checkmark whether the registrant is a shell company as defined in Rule 12b-2 of the Exchange Act.

Yes o No x

State issuer’s revenues for the most recent fiscal year: $1,014,734.

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was sold, or the average bid and asked price of such common equity, as of a specific date within the past 60 days. (See definition of affiliate in Rule 12b-2 of the Exchange Act.) $1,220,288 as of July 11, 2007.

State the number of shares outstanding of each of the issuer’s classes of common equity, as of the latest practicable date. As of July 11, 2007, 6,446,758 shares of common stock were outstanding.

Transitional Small Business Disclosure Format (Check one): Yes o No x

EXPLANATORY NOTE

This Amendment No. 1 on Form 10-K/A amends the Company's Annual Report on Form 10-KSB for the year ended March 31, 2007, filed with the Securities and Exchange Commission ("SEC") on July 16, 2007 (the "Original Annual Report"). This amendment revises the loss from operations on page F-5 of the financial statements and related disclosure in the Management Discussion and Analysis. A loss on the sale of oil and gas assets was moved from below the operating expense line up to be included in operating expenses. The amendment has no impact on the Company’s net income or loss.

Except as described above, no attempt has been made in this Amendment to modify or update other disclosures presented in the Original Annual Report. This Amendment does not reflect events occurring after the filing of the Original Annual Report, or modify or update those disclosures, including the exhibits to the Original Annual Report, affected by subsequent events. Accordingly, this Amendment should be read in conjunction with our filings with the SEC subsequent to the filing of the Original Annual Report, including any amendments to those filings.

In 2007 the Company was named United Heritage Corporation and was incorporated in Utah. In 2008 United Heritage was reincorporated in Delaware from Utah and changed its name to Glen Rose Petroleum Corporation.

The Form 10-KSB has been phased out by the Securities and Exchange Commission since the filing of the original Form 10-KSB in July 2007. Consequently this filing is an amended Form 10-K/A rather than an amended Form 10-KSB.

ITEM 6.

MANAGEMENT’S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION.

Management’s discussion and analysis of results of operations and financial condition is based upon our consolidated financial statements. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America. These principles require management to make certain estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate these estimates based on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions.

OVERVIEW

We are an independent producer of natural gas and crude oil. We produce from properties we lease in Texas. We acquired our Texas property, which includes 130 wellbores (of which approximately 44 wells are capable of producing), in February 1997. Our plan has been to develop these properties by reworking many of the existing wells and drilling additional wells. However, the revenues we earned did not provide us with enough money to implement our development plans.

On March 31, 2006, Lothian loaned United Heritage $2,500,000 (the “Wardlaw Loan”) pursuant to the terms of a promissory note and Secured Credit Agreement. We drew down the Wardlaw Loan as needed for development of the Wardlaw Field. As of March 31, 2007, we had drawn a total of $759,140. Due to Lothian’s bankruptcy, limited funds are available to us.

On April 20, 2005, our wholly-owned subsidiary, Petroleum, assigned 7,840 specific net acres of its 10,360 acre oil and gas leasehold situated in the Val Verde Basin to Dominion Oklahoma Texas Exploration & Production, Inc., which is a petroleum exploration and production company owned by Dominion Resources, Inc. (“Dominion”). Petroleum and Dominion also agreed to an area of mutual interest (“AMI”) that surrounds the 7,840 specific net acres. This AMI encompasses approximately 12,800 acres. The assignment to Dominion is for development of wells in depths below 2000 feet. Petroleum reserved all right to develop wells above 2000 feet. The term of the assignment is two years, but will continue so long as oil, gas or associated hydrocarbons are produced in paying quantities. The assignment provides that the first well is to be commenced within two years from the date of the assignment, and that subsequent wells must be drilled every 180 days. Petroleum received as consideration for the assignment cash, an overriding royalty interest, a carried working interest in the first, second or third wells, and the right to participate as a working interest partner, on a “well by well” basis, in the development of the entire acreage. In 2006, Dominion drilled a well on the AMI, but has not notified us whether the well was successful. In June 2007 we notified Dominion that it had not performed in accordance with the terms of the assignment because it had not drilled a second well within 180 days from the completion of the first well. We have requested that Dominion reassign to us the land subject to the assignment, due to lack of production in paying quantities or Continuous Drilling Operations, as defined by the assignment. Dominion has not yet responded to our request.

On August 2, 2005 we elected to participate with Dominion in an additional 1,555 acre oil and gas lease acquisition. We paid $14,556 for our proportionate share of the cost of the lease.

In December 2005 we again elected to participate with Dominion in an additional 640 acre oil and gas lease acquisition in Edwards County, Texas. We paid $12,000 for our proportionate share of the cost.

To date, other than the cash payment we received for the assignment, we have earned no revenues from it.

During the 2007 fiscal year, the sale price of oil produced by our properties in Texas increased by $1.53 a barrel, to $38.33 a barrel, from $36.80 a barrel during the 2006 fiscal year. Production costs during the 2007 fiscal year increased from $30.11 a barrel during the 2006 fiscal year to $144.79 a barrel for our Texas properties.

Prior to the Asset Sale, we realized proceeds from the sale of oil and gas derived from our properties in New Mexico. During the 2007 fiscal year, the sale price of oil produced by our properties in New Mexico increased by $0.01 a barrel, to $44.73 a barrel, from $44.72 a barrel during the 2006 fiscal year. Production costs during the 2007 fiscal year increased from $8.53 a barrel during the 2006 fiscal year to $42.96 a barrel for our New Mexico properties. During the 2007 fiscal year, the sales price of gas produced by our properties in New Mexico decreased by $0.33 per Mcf, from $3.34 per Mcf during the 2006 fiscal year to $3.01 per Mcf during the 2007 fiscal year. Due to the Asset Sale, we will not earn these revenues or accrue these expenses in the future.

While the Asset Sale will result in a significant decrease to our expenses, it will also result in a significant decrease to our revenues. Our Texas property does not produce significant quantities of oil therefore, if we do not receive operating capital from other sources, such as loans or proceeds from an offering of our securities, we may not be able to continue our operations. We do not have any commitments for financing. Due to the bankruptcy of Lothian, we do not know how much longer we can continue operating.

Except as otherwise discussed in this Annual Report, we know of no trends, events or uncertainties that have, or are reasonably likely to have, a material impact on our short-term or long-term liquidity or on our net sales or revenues from continuing operations. We do not currently have any commitments for capital expenditures for the 2008 fiscal year.

During the 2008 fiscal year, our plan is to continue redevelopment of our properties if we are successful in finding other funding sources or, alternatively, we will seek investors or buyers.

Going Concern Status

Our financial statements have been prepared on a going concern basis which contemplates the realization of assets and the liquidation of liabilities in the ordinary course of business. We have incurred substantial losses from operations and we have a working capital deficit which raises doubt about our ability to continue as a going concern. We sustained a net loss of $11,435,134 for the fiscal year ended March 31, 2007 and, as of the same period, we had a working capital deficit of $1,218,803. We must obtain financing in order to develop our properties and alleviate the doubt about our ability to continue as a going concern.

Critical Accounting Policies and Estimates

Our financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. The reported financial results and disclosures were determined using the significant accounting policies, practices and estimates described below.

Oil and Gas Properties

Proved Reserves - Proved reserves are defined by the Securities and Exchange Commission as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Although our engineers are knowledgeable of and follow the guidelines for reserves established by the Securities and Exchange Commission, the estimation of reserves requires engineers to make a significant number of assumptions based on professional judgment. Reserve estimates have been updated at least annually and consider recent production levels and other technical information about each well. Because we had no proved reserves on March 31, 2007, we did not commission a reserve report. Estimated reserves are often subject to future revision, which could be substantial, based on the availability of additional information including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in the depletion rates utilized by the Company. The Company cannot predict what reserve revisions may be required in future periods.

Depletion rates are determined based on reserve quantity estimates and the capitalized costs of producing properties. As the estimated reserves are adjusted, the depletion expense for a property will change, assuming no change in production volumes or the costs capitalized. Estimated reserves are used as the basis for calculating the expected future cash flows from a property, which are used to determine whether that property may be impaired. Reserves are also used to estimate the supplemental disclosure of the standardized measure of discounted future net cash flows relating to oil and gas producing activities and reserve quantities disclosure in Footnote 20 to the consolidated financial statements. Changes in the estimated reserves are considered changes in estimates for accounting purposes and are reflected on a prospective basis.

We employ the full cost method of accounting for our oil and gas production assets, which are located in the southwestern United States. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in cost centers on a country-by-country basis. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production basis using proved oil and gas reserves as determined by independent petroleum engineers.

Net capitalized costs are limited to the lower of unamortized cost net of related deferred tax or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on un-escalated year-end prices and costs; (ii) the cost of properties not being amortized; (iii) the lower of cost or market value of unproved properties included in the costs being amortized; less (iv) income tax effects related to differences between the book and tax basis of the oil and gas properties.

The ceiling test is affected by a decrease in net cash flow from reserves due to higher operating or finding costs or reduction in market prices for natural gas and crude oil. These changes can reduce the amount of economically producible reserves. If the cost center ceiling falls below the capitalized cost for the cost center, we would be required to report an impairment of the cost center’s oil and gas assets at the reporting date.

Impairment of Properties - We will continue to monitor our long-lived assets recorded in oil and gas properties in the consolidated balance sheet to ensure they are fairly presented. We must evaluate our properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable oil and gas reserves that will be produced from a field, the timing of future production, future production costs, and future inflation. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or gas, unfavorable adjustment to reserves, or other changes to contracts, environmental regulations or tax laws. All of these factors must be considered when testing a property's carrying value for impairment. We cannot predict whether impairment charges may be required in the future.

Revenue Recognition - Oil and gas production revenues are recognized at the point of sale. Production not sold at the end of the fiscal year is included as inventory.

Income Taxes - Included in our net deferred tax assets are approximately $15.3 million of future tax benefits from prior unused tax losses. Realization of these tax assets depends on sufficient future taxable income before the benefits expire. We are unsure if we will have sufficient future taxable income to utilize the loss carry-forward benefits before they expire. Therefore, we have provided an allowance for the full amount of the net deferred tax asset.

Accounting Estimates - Management uses estimates and assumptions in preparing financial statements in accordance with accounting principles generally accepted in the United States of America. Those estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported revenues and expenses. In particular, there is significant judgment required to estimate oil and gas reserves, impairment of unproved properties and asset retirement obligations. Actual results could vary significantly from the results that are obtained by using management’s estimates.

Off-Balance Sheet Arrangements - We have no off-balance sheet arrangements, special purpose entities or financing partnerships.

RESULTS OF OPERATIONS

The following selected financial data for the two years ended March 31, 2007 and March 31, 2006 is derived from our consolidated financial statements. The data is qualified in its entirety and should be read in conjunction with the consolidated financial statements and related notes contained elsewhere herein.

	Year Ended			Year Ended
	March 31, 2007			March 31, 2006

Income Data :
Revenues	$	1,014,734		$	601,685
Income Profit (Loss)	$	(11,435,134	)		(17,371,395	)
Income Profit (Loss)
Per Share	$	(1.77	)	$	(2.98	)
Weighted Average
Number of Shares		6,446,758			5,830,188


Balance Sheet Data :
Working Capital (deficit)	$	(1,218,803	)	$	(1,765,656	)
Total Assets	$	9,983,559		$	15,461,605
Current Liabilities	$	3,427,471		$	1,998,447
Long-Term Debt	$	2,941,983		$	1,413,003
Shareholders’ Equity	$	803,977		$	11,783,643

Combined Results

Our 2007 fiscal year revenues were $1,014,734, an increase of $413,049 or approximately 69%, as compared to revenues of $601,685 for the 2006 fiscal year. The sales revenue increase for the 2007 fiscal year was due primarily to increased volume of oil sold.

Total operating expenses of $11,993,185 reflects a decrease of $13,864,818, or approximately 54%, for the 2007 fiscal year as compared to operating expenses of $25,858,003 for the 2006 fiscal year. The significant operating expenses reported for the 2006 fiscal year resulted from the inclusion of $23,199,110 in impairment of our oil and gas properties, which was not taken in 2007. The impairment was taken in conjunction with the re-evaluation of our reserves. General and administrative expenses decreased slightly by $22,464, or approximately 2%, from $1,339,920 in the 2006 fiscal year to $1,317,456 in the 2007 fiscal year. We also incurred a put option expense of $2,727,186 during the fiscal year ended March 31, 2007. We had no similar expense during the fiscal year ended March 31, 2006. Interest expense was $456,683 in the 2007 fiscal year, as compared to $221,445 in the 2006 fiscal year. The increase during the 2007 fiscal year was due primarily to the increase in the amount of money loaned to us by Lothian for development of our properties. 2007 fiscal year operating expenses include a $6,125,233 loss on the sale of oil and gas assets.

Our net loss for the 2007 fiscal year was $11,435,134, a decrease of $5,936,261 or approximately 34%, as compared to a net loss of $17,371,395 for the 2006 fiscal year. We reported a significant decrease in net loss because we had no impairment charge in the 2007 fiscal year, as compared to the impairment charge of $23,199,110 we included in the 2006 fiscal year.

Food Products Activity

Our subsidiary, National Heritage Sales Corporation, had $0 product sales during the 2007 fiscal year, as compared to sales for the 2006 fiscal year of $8,694. National is no longer selling meat and poultry products and has sold its assets. We do not intend to re-enter this market and we will no longer have results related to this activity to report.

Oil and Gas Activity

Oil and gas sales during the 2007 fiscal year were $1,014,734, an increase of $421,743 or approximately 71%, as compared to sales of $592,991 during the 2006 fiscal year. The volume of production sold during the 2007 fiscal year was greater than the volume of production sold during the 2006 fiscal year, however, significantly higher production costs offset the increased volumes and slightly higher product prices. The increased costs from the 2006 fiscal year were primarily the result of higher field labor, salt water disposal and high service company costs related to increased activity on the Texas and New Mexico properties. Production is expected to remain limited on our Texas property, the only property we currently own, due to a lack of operating and investment capital that, prior to its bankruptcy, had been provided to us by Lothian. Receivables due to the Asset Sale comprised 99% of our total receivable balance at March 31, 2007. Receivables from a single oil and gas customer comprised 55% of our trade receivable balance at March 31, 2006. No allowance for doubtful accounts has been included in our financial statements since recorded amounts are determined to be fully collectible, based on management’s review of customer accounts, historical experience and other pertinent factors. During the fiscal year ended March 31, 2007, we recorded oil and gas sales to only two customers. Buyers of crude oil are plentiful and can be easily replaced.

Production and operating expenses were $1,320,401 during the 2007 fiscal year as compared to $259,290 in production and operating expenses during the 2006 fiscal year, an increase of $1,061,111 or approximately 401%. This significant increase in production and operating expenses was the result of higher salt water disposal charges and charges for field labor. Depreciation and depletion expense for the 2007 fiscal year was $490,507 as compared to depreciation and depletion expense of $1,027,155 for the 2006 fiscal year, a decrease of $536,648 or approximately 52%. The decreased depreciation and depletion expense resulted primarily from the reduction of proved properties due to the impairment of assets in the 2006 fiscal year.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Our sales revenues have not been adequate to support our operations and we do not expect that this will change in the near future. In the past, we relied primarily on loans from Lothian to finance our operations. Lothian declared bankruptcy on June 13, 2007 and we do not believe that it is capable of providing additional funding to us. We currently have no other sources of capital. We are operating on a day-to-day basis and we will continue operating in this manner for as long as Lothian provides us with the funds to do so.

Our current assets increased by $1,975,877 or approximately 849%, from $232,791 at March 31, 2006 to $2,208,668 at March 31, 2007. The increase in our current assets was due primarily to cash and receivables related to the Asset Sale. Current liabilities increased from $1,998,447 at March 31, 2006, to $3,427,471 at March 31, 2007, an increase of $1,429,024 or approximately 72%. The increase in current liabilities was due to increased accounts payable and accrued interest on the related party notes payable. Working capital was a deficit of $1,218,803 at March 31, 2007 as compared to the March 31, 2006 deficit of $1,765,656, a decrease of $546,853 or approximately 31%. The decreased deficit was due primarily to the Asset Sale.

Due to the loss incurred on the sale of our New Mexico properties and the expense related to the put provision included in certain stock option agreements, equity capital decreased by $10,979,666, or approximately 93%, during the 2007 fiscal year. Shareholders’ equity was $11,783,643 at March 31, 2006, as compared to $803,977 at March 31, 2007.

Total assets were $9,983,559 at March 31, 2007, a decrease of $5,478,046 as compared to $15,461,605 for the 2006 fiscal year. The decrease in total assets resulted primarily from the sale of our New Mexico property.

Cash Flow

Our operations used $575,885 of cash in the 2007 fiscal year as compared to $67,729 used in the 2006 fiscal year. The cash flow deficits are due to the operating losses incurred.

Cash of $642,211 was provided by investing activities during the 2007 fiscal year and cash of $1,908,815 was used in investing activities for the 2006 fiscal year. Net cash provided from investing activities for the 2007 fiscal year consisted of the proceeds from the sale of our New Mexico properties, which totaled $6,613,947. Cash of $5,971,736 was used for capital expenditures for our oil and gas properties and for the purchase of equipment. During the 2006 fiscal year, cash flows used in investing activities related primarily to capital expenditures for our oil and gas properties.

In the 2007 fiscal year, cash of $6,338,904 was provided by borrowings from Lothian. Payments totaling $4,809,924 were made to Lothian from the proceeds we received when we sold New Mexico’s assets. During the 2006 fiscal year, cash in the amount of $5,249,753 from financing activities came from the exercise of warrants, the sale of our common stock to Lothian and loans from Lothian. Of this amount, $3,203,994 was used for the repayment of a loan from Almac Financial Corporation.

At March 31, 2007 we had cash of $1,671,672.

FACTORS AFFECTING OUR BUSINESS, OPERATING RESULTS AND FINANCIAL CONDITION

Risks Related to Our Business

Lothian filed a petition for protection under Chapter 11 of the U.S. Bankruptcy Code. It is not likely that Lothian will have the resources to continue funding our operations. We may be forced to discontinue our operations.

In October 2005 Lothian began to provide funding to us for our operations. On June 13, 2007 Lothian filed a petition for protection under Chapter 11 of the U.S. Bankruptcy Code. It is not likely that Lothian will be able to continue loaning money to us for our operations and we have no other sources of capital. If we cannot find other financing for our operations, we may be required to severely curtail or discontinue them.

Currently, Lothian does not have the financial capacity to develop our properties.

Lothian planned to develop our oil and gas properties, however, it does not currently have the funds to pay the costs associated with such development, including engineering studies, equipment purchases or leasing and personnel costs, all of which are significant. In order to undertake this development, it is likely that Lothian will need additional sources of capital. Lothian has recently filed for protection under Chapter 11 of the U.S. Bankruptcy Code. There is no guarantee that sources of capital will be available to Lothian on acceptable terms, or at all. If Lothian cannot develop our oil properties as it planned and we cannot find other sources of financing for our operations, we may be required to severely curtail or discontinue our operations.

We do not earn enough money to support our operations. We may be unable to continue our business.

We do not earn enough money from our oil and gas sales to pay for our operating expenses. Due to our substantial losses and our working capital deficit, we may be unable to continue as a going concern. We currently do not know how long we can continue our operations. If we do not obtain financing, we will be required to severely curtail, or to completely cease, our operations. We do not currently have any commitments for financing. We are operating on a day-to-day basis and we will continue operating in this manner for as long as Lothian provides us with the funds to do so.

Weaver and Tidwell, L.L.P., our independent auditor, has included in its report on our financial statements a paragraph stating that that we may be unable to continue as a going concern.

We have experienced net losses and negative cash flows from operations. We sustained a net loss of $11,435,134 and a working capital deficit of $1,218,803 for the fiscal year ended March 31, 2007. We have an accumulated deficit of $42,999,146. As discussed in Note 3 to the financial statements, we sold all of our proved reserves in 2007 and we currently do not have significant revenue producing assets. In addition, we have limited capital resources and Lothian, our majority shareholder who was financing our development, filed for bankruptcy subsequent to March 31, 2007. All of these factors raise substantial doubt about our ability to continue as a going concern. The financial statements included in this report do not include any adjustments that might result from the outcome of these uncertainties. As noted in an explanatory paragraph in the report of Weaver and Tidwell, L.L.P., our independent certified public accountants, on our consolidated financial statements for the year ended March 31, 2007, these conditions have raised substantial doubt about our ability to continue as a going concern.

We must estimate our proved oil and gas reserves and the estimated future net cash flows from the reserves. These estimates may prove to be inaccurate.

This Form 10-K/A contains estimates of our proved oil and gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the Securities and Exchange Commission relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. Additionally, our interpretations of the rules governing the estimation of proved reserves could differ from the interpretation of staff members of regulatory authorities resulting in estimates that could be challenged by these authorities.

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

Our business plan anticipates that we will be able to develop our oil and gas properties. The cost to develop our oil properties is significant, and, to date, we have been unable to do so due to our lack of funds. Unless we can develop our oil properties, our revenues and results of operations will be adversely affected.

We believe that the properties of our subsidiary, Petroleum, have significant reserves of oil, however, we have not had the funds to fully exploit these resources. The costs associated with the development of oil and gas properties, including engineering studies, equipment purchase or leasing and personnel costs, are significant. In order to become profitable we must enhance our oil production, which means that we must drill and/or recomplete more wells. In order to accomplish this, we must find additional sources of capital.

In the past, we and our subsidiaries received financing from Lothian. However, it is unlikely that Lothian will be able to continue funding our operations. We cannot guarantee that future financing will be available to us from any other source on acceptable terms or at all. If we do not earn revenues sufficient to operate our business and we fail to obtain other financing, either through an offering of our securities or by obtaining additional loans, we may be unable to continue our operations.

Even if we fully develop our oil properties, we may not be profitable. Our inability to operate profitably will adversely affect our business.

We have assumed that once we fully develop our oil properties we will be profitable. However, even if we were able to fully develop our properties, there is no guarantee that we would achieve profitability. Our reserves may prove to be lower than expected, production levels may be lower than expected, the costs to exploit the oil may be higher than expected, new regulations may adversely impact our ability to exploit these resources and the market price for crude oil may be lower than current prices.

We also face competition from other oil companies in all aspects of our business, including obtaining oil leases, marketing oil, and obtaining goods, services and labor to exploit our resources. Many of our competitors have substantially larger financial and other resources than we have, and we may not be able to successfully compete against them. Competition is also presented by alternative fuel sources, which may be more efficient and less costly and may result in our products becoming less desirable.

Any of these factors could prevent us from attaining profitability.

The development and exploitation of oil properties is subject to many risks that are beyond our control. The occurrence of any of these events could have a material adverse effect on our business and results of operations.

Our crude oil drilling and production activities are subject to numerous risks, many of which are beyond our control. These risks include the following:

that no commercially productive crude oil reservoirs will be found;

that crude oil drilling and production activities may be shortened, delayed or canceled; and

that our ability to develop, produce and market our reserves may be limited by title problems, weather conditions, compliance with governmental requirements, and mechanical difficulties or shortages or delays in the delivery of drilling rigs and other equipment.

We cannot assure you that the new wells we drill, or the wells that are currently in existence, will be productive or that we will recover all or any portion of our investment in them. Drilling for crude oil and natural gas may be unprofitable. Dry holes and wells that are productive but do not produce sufficient net revenues after drilling, operating and other costs are unprofitable.

Our industry also experiences numerous operating risks. These operating risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these industry operating risks occur, we could sustain substantial losses. Substantial losses also may result from injury or loss of life, severe damage to or destruction of property, clean-up responsibilities, regulatory investigation and penalties and suspension of operations.

Any of these events could adversely affect our business.

We may not have enough insurance to cover all of the risks we face. If our insurance coverage is inadequate to pay a claim, we would be responsible for payment. The requirement that we pay a significant claim would materially, adversely impact our financial condition and results of operations.

In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance which we may be required to pay could have a material adverse effect on our financial condition and results of operations.

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

Our revenue, profitability, cash flow, future 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 oil and natural gas. Historically, the markets for oil and natural gas have been volatile, and such markets are likely to continue to be volatile in the future. Prices are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. These factors include the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions, the foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. While we attempt to mitigate price volatility when we can by acquiring “puts” to protect our prices, we cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material adverse effect on our financial condition and results of operations.

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

Oil and natural gas operations are subject to various 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 oil and natural gas wells below actual production capacity in order to conserve supplies of 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 oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations. Furthermore, we may be liable 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. While the regulations governing our industry have not had a material adverse effect on our operations to date, the implementation of new laws or regulations, or the modification of existing laws or regulations, could have a material adverse effect on us.

We face strong competition from larger oil and natural gas companies.

Our competitors include major oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than we have. These larger competitors may be able to pay more for exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. We do not represent a significant presence in the oil and gas industry.

We may not be able to replace production with new reserves.

In general, the volume of production from oil and gas properties declines as reserves are depleted. The decline rates depend on reservoir characteristics. Our aggregate reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future natural gas and oil production is highly dependent upon our level of success in finding or acquiring additional reserves.

ITEM 7.

FINANCIAL STATEMENTS

The financial statements and supplementary data required to be included in this Item 7 are set forth at page F-1 of this Annual Report.

ITEM 13.

EXHIBITS

Exhibits

	23	Consent of Weaver and Tidwell, L.L.P.(13)

	31.1	Certification of Chief Executive Officer and Chief Financial Officer (13)

	32	Certification pursuant to Section 906 of the Sarbanes Oxley Act (13)

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: October 7, 2009	GLEN ROSE PETROLEUM CORPORATION

	By:	/s/ Andrew Taylor-Kimmins
		Andrew Taylor-Kimmins
		President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated below on this 16th day of July 2007.

SIGNATURE, TITLE

/s/ Andrew Taylor-Kimmins
Andrew Taylor-Kimmins
Chairman

/s/ Ted Williams
Ted Williams
Director

/s/ Paul K. Hickey
Paul K. Hickey
Director

		Page

Financial Statements

Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets at March 31, 2007 and 2006		F-3

Consolidated Statements of Operations for the years ended March 31, 2007 and 2006		F-5

Consolidated Statements of Changes in Shareholders’ Equity for the years ended March 31, 2007 and 2006		F-6

Consolidated Statements of Cash Flows for the years ended March 31, 2007 and 2006		F-7

Notes to Consolidated Financial Statements		F-8

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

United Heritage Corporation

We have audited the accompanying consolidated balance sheets of Glen Rose Petroleum, a Delaware corporation, formerly known and operating as United Heritage Corporation, a Utah corporation and subsidiaries as of March 31, 2007 and 2006 and the related consolidated statements of operations (as amended), changes in shareholders' equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Glen Rose Petroleum, a Delaware corporation, formerly known and operating as United Heritage Corporation, a Utah corporation and subsidiaries as of March 31, 2007 and 2006, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America. .

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the financial statements, the Company sold all of its proved reserves in 2006 and currently does not have significant revenue producing assets. In addition, the Company has limited capital resources and it’s majority shareholder who was financing the Company’s development filed for bankruptcy subsequent to March 31, 2007, all of which raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also discussed in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 2 to the consolidated financial statements, in 2007 the Company adopted Statement of Financial Accounting Standards No. 123(R), “Share Based Payment.”

/s/ WEAVER AND TIDWELL, L.L.P.

Fort Worth, Texas

July 16, 2007

F-2

UNITED HERITAGE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

MARCH 31, 2007 AND 2006

	2007		2006
ASSETS
CURRENT ASSETS
Cash	$	1,671,672	$	76,366
Accounts receivable		5,602		60,269
Accounts receivable - other		465,068		—
Inventory		31,417		48,626
Prepaid expenses		34,909		47,530
Total current assets		2,208,668		232,791

INVESTMENT in Cano Petroleum common stock, at fair value (restricted)		1,827,000		—


OIL AND GAS PROPERTIES, accounted for using the full cost method, net of accumulated depletion and depreciation of $0 for 2007 and $2,048,818 for 2006
Proved		—		9,353,037
Unproved		5,864,587		5,864,587
		5,864,587		15,217,624
PROPERTY AND EQUIPMENT, at cost
Equipment, furniture and fixtures		74,244		74,244
Vehicles		158,452		57,603
		232,696		131,847
Less accumulated depreciation		149,392		120,657
		83,304		11,190

TOTAL ASSETS	$	9,983,559	$	15,461,605

The Notes to Consolidated Financial Statements are an integral part of these statements.

F-3

UNITED HERITAGE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

MARCH 31, 2007 AND 2006

	2007			2006

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	1,835,148		$	1,248,763
Accounts payable, related party		797,088			405,000
Accrued expenses		343,750			344,684
Accrued interest, related party		451,485			—
Total current liabilities		3,427,471			1,998,447
LONG-TERM LIABILITIES
Asset retirement obligation		82,942			266,512
Note payable, related parties		2,941,983			1,413,003
Accrued put option liability		2,727,186			—
Deferred tax liability		—			—
Total liabilities		9,179,582			3,677,962
SHAREHOLDERS' EQUITY
Preferred stock, $.0001 par value, 5,000,000 shares authorized, none issued		—			—
Common stock, $.001 par value, 125,000,000 shares authorized, 6,446,758 issued and outstanding		6,447			6,447
Additional paid-in capital		43,796,676			43,341,208
Accumulated deficit		(42,999,146	)		(31,564,012	) )
Total shareholders' equity		803,977			11,783,643
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	9,983,559		$	15,461,605

The Notes to Consolidated Financial Statements are an integral part of these statements.

F-4

UNITED HERITAGE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

YEARS ENDED MARCH 31, 2007 AND 2006

	2007			2006

OPERATING REVENUES
Processed meat products	$	—		$	8,694
Oil and gas sales		1,014,734			592,991
Total operating revenues		1,014,734			601,685
OPERATING COSTS AND EXPENSES
Processed meat products		—			15,996
Production and operating		1,320,401			259,290
Depreciation and depletion		490,507			1,027,155
Accretion of asset retirement obligation		12,402			16,532
Loss on sale of oil and gas assets		(6,125,233	)		—

General and administrative		1,317,456			1,339,920
Put option expense		2,727,186			—
Ceiling test impairment of oil & gas properties		—			23,199,110
Total operating costs and expenses		11,993,185			25,858,003
Loss from operations		(10,978,451	)		(25,256,318	)
OTHER INCOME (EXPENSE)
Gain on forgiveness of debt		—			116,457
Loss on notes receivable		—			(87,500	)

Interest expense		( 456,683	)		( 221,445	)
Miscellaneous income		—			27,486
Income (loss) before income tax		(11,435,134	)		(25,421,320	)
INCOME TAX (EXPENSE) BENEFIT		—			8,049,925
Net income (loss)	$	(11,435,134	)	$	(17,371,395	)
Income (loss) per share:
Basic and diluted	$	(1.77	)	$	(2.98	)
Weighted average number of shares outstanding Basic and diluted		6,446,758			5,830,188

The Notes to Consolidated Financial Statements are an integral part of these statements.

F-5

UNITED HERITAGE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

YEARS ENDED MARCH 31, 2007 AND 2006

	Common Stock				Additional Paid-in		Accumulated
	Shares		Amount		Capital		Deficit			Other
Balance, March 31, 2005 (Restated)		5,182,781	$	5,183	$	39,476,803	$	(14,192,617	)	$	(5,250	)
Stock issued for services		33,333		33		105,324		—			—
Issuance of stock to Lothian Oil Inc.		1,093,333		1,093		3,442,907		—			—
Issuance of stock upon exercise of warrants		138,233		138		311,712		—			—
Stock options for services non-employees		—		—		4,462		—			—
Realization of deferred consulting fees		—		—		—		—			5,250
Net loss		—		—		—		(17,371,395	)		—

Balance, March 31, 2006		6,446,758		6,447		43,341,208		(31,564,012	)		—
Stock options for services of non-employees		—		—		455,468		—			—
Net loss		—		—		—		(11,435,134	)		—
Balance, March 31, 2007		6,446,758	$	6,447	$	43,796,676	$	(42,999,146	)	$	—

The Notes to Consolidated Financial Statements are an integral part of these statements.

F-6

UNITED HERITAGE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED MARCH 31, 2007 AND 2006

	2007			2006

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(11,435,134	)	$	(17,371,395	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		490,507			1,027,155
Loss on sale of oil and gas assets		6,125,233			—
Ceiling test impairment of oil and gas properties		—			23,199,110
Realization of stock options issued to non-employees		455,468			4,462
Put option expense		2,727,186			—
Recognition of services performed for stock		—			105,357
Deferred compensation and consulting recognized in current year		—			5,250
Forgiveness of debt		—			( 116,457	)
Accretion of asset retirement obligation		12,402			16,532
Write off of note receivable		—			87,500
Changes in assets and liabilities:
Accounts receivable		( 410,401	)		29,998
Inventory		17,209			(22,419	)
Prepaid expenses		12,621			77,665
Deferred tax		—			(8,049,925	)
Accounts payable and accrued expenses		1,429,024			939,438
Net cash used in operating activities		( 575,885	)		( 67,729	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of oil and gas interests		6,613,947			625,000
Additions to oil and gas properties		( 5,830,677	)		( 2,533,815	)
Additions to equipment		( 141,059	)		—
Net cash provided by (used in) investing activities		642,211			( 1,908,815	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from exercise of stock warrants		—			311,850
Proceeds from issuance of common stock to Lothian		—			3,444,000
Proceeds from borrowings, related parties		6,338,904			1,493,903
Payments on note payable, related party		(4,809,924	)		( 3,203,994	)
Net cash provided by financing activities		1,528,980			2,045,759
Net increase in cash		1,595,306			69,215
Cash, beginning of year		76,366			7,151
Cash, end of year	$	1,671,672		$	76,366

SUPPLEMENTAL DISCLOSURES OF
CASH FLOWS INFORMATION:
Cash paid during the year for:
Interest	$	—		$	712,030
Taxes	$	—		$	—
SUPPLEMENTAL SCHEDULE OF NONCASH
INVESTING AND FINANCING ACTIVITIES:
Common stock issued in exchange for services	$	—		$	105,357
Acquisition of common stock in sale of oil and gas properties	$	1,827,000		$	—
Forgiveness of debt	$	—		$	116,457

The Notes to Consolidated Financial Statements are an integral part of these statements.

F-7

UNITED HERITAGE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1.

RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS

In April 2006, the Company retained independent petroleum engineers to evaluate its properties. Based on this review and internal assessments, the Company concluded that a downward revision of its stated proved reserves, from 36,492,693 Boe to 1,056,317 Boe, should have been reflected in the March 31, 2005 fiscal year and prior periods. The Company concluded that a revision of the historical proved reserve estimates included in the historical supplemental oil and gas producing disclosures was required. Quantities of estimated proved reserves are used in determining depletion and impairment based on the ceiling limitation. The revisions of historical reserve estimates required the restatement of the Company’s financial statements for the fiscal years ending March 31, 2000 to March 31, 2005 and the first three quarters of March 31, 2006.

In addition to the restatements required as a result of the reserve revisions, the Company determined that approximately $76,822 of merger costs and $34,131 of vehicle costs net of accumulated depreciation were inappropriately included in the Company’s proven properties in the March 31, 2005 financial statements and prior years. The Company determined that a revision of the historical financial statements for these reclassifications was required to determine the appropriate depletion and impairment based on the ceiling limitation.

Reserve Restatement

The reserve restatement resulted in the following revisions to our estimated proved reserves as of March 31, 2005:

	March 31, 2005
	As Reported		As Restated

Estimated Proved Reserves (Unaudited)
Oil (Bbls)		35,225,600	567,189
Gas (Mcf)		7,602,559	2,934,765
Oil and Gas (Boe)		36,492,693	1,056,317

Estimated Proved Developed Reserves (Unaudited)
Oil (Bbls)		5,629,000	567,189
Gas (Mcf)		2,538,000	2,934,765
Oil and Gas (Boe)		6,052,000	1,056,317

The cumulative impact of the restatement on the Company’s shareholders’ equity as of March 31, 2005 was a reduction of approximately $1,800,873.

The Company’s historical consolidated statements of operations for the year ended March 31, 2005 and for each of the quarters in that year and the first three quarters of the fiscal year ended March 31, 2006 reflect the effects of the restatement on the calculation of historical depletion. The Company did not amend the Annual Report filed on Form10-KSB for the year ended March 31, 2005 or the Quarterly Reports filed on Form 10-QSB for any periods prior to March 31, 2006. The financial statements and related information contained in those reports should no longer be relied upon. A summary of the effects of the restatement on reported amounts for the year ended March 31, 2005 and the quarters ended June 30, 2005, September 30, 2005 and December 31, 2005 is presented below. The information presented represents only those statements of operations, balance sheet and cash flow statement line items affected by the restatement.

F-8

NOTE 1.

RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS (continued)

	March 31, 2005
	As Reported			As Restated

Balance Sheet:
Prepaid expenses	$	48,374		$	125,195
Proved oil and gas properties		38,565,819			2,301,263
Accumulated depletion		204,706			1,026,934
Unproved oil and gas properties		834,579			35,215,630
Vehicles		22,045			57,603
Accumulated depreciation		85,637			115,384
Total Assets		39,683,457			37,882,584
Accumulated deficit		(12,391,744	)		(14,192,617	)
Total liabilities and shareholders’ equity		39,683,457			37,882,584

	Quarters Ended (Unaudited)
	June 30, 2005								September 30, 2005								December 31, 2005
	As Reported				As Restated				As Reported				As Restated				As Reported				As Restated
Statement of Operations:
Depreciation and depletion		$	11,734			$	64,005			$	14,187			$	389,435			$	21,269			$	234,880
Ceiling test impairment			—				—				—				23,199,110				—				—
Total operating costs and expenses			271,475				323,746				418,970				23,993,328				354,531				568,142
Loss from operations			(144,392	)			(196,663	)			(234,528	)			(23,808,886	)			(173,095	)			(386,706	)
Income tax			—				—				—				8,049,925				—				—
Net loss			(219,013	)			(271,284	)			(304,821	)			(15,865,481	)			(209,792	)			(423,403	)
Basic and diluted loss per share			(0.04	)			(0.05	)			(0.06	)			(2.98	)			(0.03	)			(0.07	)

	Quarters Ended (Unaudited)
	June 30, 2005								September 30, 2005								December 31, 2005
	As Reported				As Restated				As Reported				As Restated				As Reported				As Restated
Statement of Cash Flows:
Net loss		$	(219,013	)		$	(271,284	)		$	(304,821	)		$	(15,865,481	)		$	(209,792	)		$	(423,403	)
Depreciation, depletion and amortization			11,734				64,005				14,187				389,435				21,269				234,880
Ceiling test impairment			—				—				—				23,199,110				—				—
Deferred tax			—				—				—				(8,049,925	)			—				—

F-9

NOTE 2.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Presentation

The consolidated financial statements include the accounts of United Heritage Corporation (the Company) and its wholly owned subsidiaries, UHC Petroleum Corporation, UHC Petroleum Services Corporation, UHC New Mexico Corporation and National Heritage Sales Corporation. All intercompany transactions and balances have been eliminated upon consolidation.

Nature of Operations

United Heritage Corporation owns various oil and gas properties located in south Texas. The Company began production of the Texas properties during the year ended March 31, 2000. The Company continues to operate its oil and gas properties.

Revenue

Oil and gas production revenues are recognized at the point of sale. Production not sold at the end of the fiscal year is included as inventory in the accompanying financial statements. Revenue from the sale of meat products was recognized when products were delivered to customers.

Inventory

Inventory consists of oil in tanks, which is valued at the lower of the cost to produce the oil or the current available sales price.

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas properties, which are located in the southwestern United States. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves are capitalized.

All capitalized costs, including the estimated future costs to develop proved reserves are amortized on the unit-of-production method using estimates of proved reserves. Investments in unproved properties and major development projects will not be amortized until proved reserves associated with the projects can be determined or until impairment occurs. Oil and gas reserves and production are converted into equivalent units based upon estimated relative energy content.

The Company is currently participating in oil and gas exploitation and development activities. As of March 31, 2007 the following associated property costs have been excluded in computing amortization of the full cost pool, by the year in which such costs were incurred:

	Total			2007		2006			Prior

Acquisition costs	$	31,752,741		$	0	$	26,566		$	31,726,175
Exploration costs		0			0		0			0
Development costs		3,918,199			0		428,744			3,489,455
Sale of deep rights		(625,000	)		0		(625,000	)		0
Unproved impairment		(29,181,353	)		0		(29,181,353	)		0
	$	5,864,587		$	0	$	(29,351,043	)	$	35,215,630

F-10

The Company will begin to amortize the remaining acquisition costs when the project evaluation is complete. This will be dependent upon the Company finding the necessary financing.

Potential impairment of producing properties and significant unproved properties and other plant and equipment are assessed periodically. If the assessment indicates that the properties are impaired, the amount of the impairment will be added to the capitalized costs to be amortized.

In addition, the capitalized costs are subject to a “ceiling test”, which limits such costs to the aggregate of the estimated present value using a 10% discount rate (based on prices and costs at the balance sheet date) of future net revenues from proved reserves based on current economic and operating conditions, plus the lower of cost (net of impairments) or fair market value of unproved properties.

As discussed in Note 1, the Company retained outside independent petroleum engineers to evaluate the properties of the Company as of March 31, 2006. Based on this review and internal assessments, the Company concluded that a downward revision for its unproved properties was required. As of March 31, 2006, the Company impaired $29,181,353 of unproved properties and included these costs in the full cost pool subjecting these costs to the ceiling limitation and depletion for the fiscal year ended March 31, 2006. The ceiling test resulted in a write-down during 2006 of $ 23,199,110. Depreciation and depletion increased approximately $763,414 primarily due to the addition of these unproved properties to the full cost pool. As of March 31, 2007 the Company determined that no impairment of its unproved properties was required.

NOTE 2.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income. Abandonments of properties are accounted for as adjustments of capitalized costs with no loss recognized. During the year ended March 31, 2007 the Company sold 100% of its proved reserves for net proceeds of $8,440,947. The sale resulted in a loss of $6,125,233 which is reflected in the Statements of Operations.

Property and Equipment

Property and equipment are stated at cost. Depreciation is provided over the estimated useful lives of the assets primarily by the straight-line method as follows:

Equipment, furniture and fixtures	3-7 years
Vehicles	3-5 years

Earnings (Loss) Per Common Share

Basic earnings (loss) per common share are computed based on the weighted average number of common shares outstanding for the period. Diluted earnings (loss) per common share are computed assuming all dilutive potential common shares were issued. Dilutive potential common shares consist of stock options and warrants. Diluted earnings per share have not been presented since the inclusion of potential common shares would be antidilutive.

F-11

NOTE 2.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Cash Flows Presentation

For purposes of the statement of cash flows, the Company considers all highly liquid investments purchased with maturities of three months or less to be cash equivalents.

Advertising

The Company expenses all advertising costs as incurred. No advertising cost was incurred for the years ended March 31, 2007 or 2006.

Use of Estimates

The preparation of consolidated 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of oil and gas reserves, the asset retirement obligation and impairment on unproved properties are inherently imprecise and may change materially in the near term.

Financial Instruments

Financial instruments consist of cash and cash equivalents, accounts receivable, notes receivable, accounts payable and notes payable. Recorded values of cash, receivables and payables approximate fair values due to short maturities of the instruments. Notes payable are to Lothian Oil Inc., the Company’s majority shareholder, and the difference between fair value and recorded amount is not material, based on the stated interest rates available to the Company.

Investment Securities

Securities are classified as held to maturity and carried at amortized cost when management has the positive intent and ability to hold them until maturity. Securities to be held for indefinite periods of time are classified as available for sale and carried at fair value, with the unrealized holding gains and losses reported as a component of other comprehensive income, net of tax. Securities held for resale in anticipation of short-term market movements are classified as trading and are carried at fair value, with changes in unrealized holding gains and losses included in income. Management determines the appropriate classification of securities at the time of purchase.

Interest income includes amortization of purchase premiums and discounts. Realized gains and losses are derived from the amortized cost of the security sold. Declines in the fair value of held-to-maturity and available-for-sale securities below their cost that are deemed to be other than temporary are reflected in earnings as realized losses. In estimating other-than-temporary impairment losses, management considers, among other things, (i) the length of time and the extent to which the fair value has been less than cost, (ii) the financial condition and near-term prospects of the issuer, and (iii) the intent and ability of the Company to retain its investment in the issuer for a period of time sufficient to allow for any anticipated recovery in fair value.

At March 31, 2007, the Company owned 404,204 shares of restricted common stock in Cano Petroleum, Inc. which was classified as available for sale.

F-12

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Stock-based Employee Compensation

Effective April 1, 2006, the Company adopted Statement of Financial Accounting Standard No. 123(R), Share-Based Payment, (“SFAS No. 123(R)”), using the modified prospective transition method. SFAS No. 123(R) requires equity-classified share-based payments to employees, including grants of employee stock options, to be valued at fair value on the date of grant and to be expensed over the applicable vesting period. Under the modified prospective transition method, share-based awards granted or modified on or after April 1, 2006 are recognized in compensation expense over the applicable vesting period. Also, any previously granted awards that are not fully vested as of April 1, 2006 are recognized as compensation expense over the remaining vesting period. No retroactive or cumulative effect adjustments were required upon the Company’s adoption of SFAS No. 123(R).

Prior to adopting SFAS No. 123(R), the Company accounted for its employee stock options using the intrinsic-value based method prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees , (“APB No. 25”) and related interpretations. This method required compensation expense to be recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price.

Had the Company elected the fair value provisions of SFAS No. 123(R), fiscal year 2006 net loss and net loss per share would have differed from the amounts actually reported as shown in the following table.

The fair value of the options granted in the year ended March 31, 2006 was estimated on the date of grant using a Black-Scholes option pricing model and the following assumptions: a risk-free rate of return of 3.00% to 4.37%; an expected life of three to ten years; expected volatility of 88% to 96%; and no expected dividends.

Using the above assumptions, the fair value of the options granted to employees and directors on a pro forma basis would result in additional compensation expense of $359,571 for the year ended March 31, 2006. As such, pro forma net loss per share would be as follows for the years ended March 31, 2006.

	Fiscal Year Ended
	March 31, 2006

Net loss, as reported	$	(17,371,395	)
Expense recognized		343,750
Additional compensation		(703,321	)
Pro forma net loss	$	(17,730,966	)
Loss per share as reported	$	(2.98	)
Pro forma net loss per share	$	(3.04	)

Long-lived Assets

Long-lived assets to be held and used by the Company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company continuously evaluates the recoverability of its long-lived assets based on estimated future cash flows and the estimated liquidation value of such long-lived assets, and provides for impairment if such undiscounted cash flows are insufficient to recover the carrying amount of the long-lived assets.

F-13

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Income Taxes

Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes on temporary differences between the amount of taxable income and pretax financial income and between the tax bases of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled as prescribed in FASB Statement No. 109, Accounting for Income Taxes . As changes in tax laws or rate are enacted, deferred tax assets and liabilities are adjusted through the provision for income taxes.

Recently Issued Accounting Standards Not Yet Adopted

FASB Staff Position (FSP) FAS 19-1 amends SFAS statement No. 19 to provide revised guidance concerning the criteria for continued capitalization of exploratory costs when wells have found reserves that cannot yet be classified as proved. FAS 19-1 provides circumstances that would permit the continued capitalization of exploratory well costs beyond one year, other than when additional exploration wells are necessary to justify major capital expenditures and those wells are under way or firmly planned for the near future. Generally, the statement allows exploratory well costs to continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project.

In February 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 155, “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140.” SFAS No. 155 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and also resolves issues addressed in SFAS No. 133 Implementation Issue No. D1, “Application of Statement 133 to Beneficial Interests in Securitized Financial Assets.” SFAS No. 155 was issued to eliminate the exemption from applying SFAS No. 133 to interests in securitized financial assets so that similar instruments are accounted for in a similar fashion, regardless of the instrument’s form. The Company does not believe that its financial position, results of operations or cash flows will be impacted by SFAS No. 155 as it does not currently hold any hybrid financial instruments.

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No. 109” (“FIN 48”). This interpretation provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding derecognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. The adoption of this Interpretation is not expected to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”), which establishes an approach requiring the quantification of financial statement errors based on the effect of the error on each of the company’s financial statements and the related financial statement disclosures. This model is commonly referred to as a “dual approach” because it requires quantification of errors under both the “iron curtain” and “roll-over” methods. The roll-over method focuses primarily on the impact of a misstatement on the income statement, including the reversing effect of prior year misstatements; however, its use can lead to the accumulation of misstatements in the balance sheet. The iron curtain method focuses primarily on the effect of correcting the period end balance sheet with less emphasis on the reversing effects of prior year errors on the income statement. The Company will initially apply the provisions of SAB 108 in connection with the preparation of the Company’s annual financial statements for the year ending March 31, 2007. The use of the dual approach is not expected to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.

F-14

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

In September 2006, the FASB issued SFAS No. 157 , ”Fair Value Measurements”, which addresses how companies should measure fair value when companies are required to use a fair value measure for recognition or disclosure purposes under generally accepted accounting principles (“GAAP”). As a result of SFAS 157, there is now a common definition of fair value to be used throughout GAAP. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. Although the disclosure requirements may be expanded where certain assets or liabilities are fair valued such as those related to stock compensation expense and hedging activities, the Company does not expect the adoption of SFAS 157 to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.

In December 2006, the FASB issued FASB Staff Position FSP EITF 00-19-2, Accounting for Registration Payment Arrangements . This FASB Staff Position, or FSP, specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB Statement No. 5, Accounting for Contingencies . This FSP also requires certain disclosures regarding registration payment arrangements and liabilities recorded for such purposes. This FSP is immediately effective for registration payment arrangements entered into or modified after December 21, 2006. The guidance of this FSP is effective for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years for registration payment arrangements entered into prior to December 21, 2006. This FSP requires adoption by reporting a change in accounting principle through a cumulative-effect adjustment to the opening balance of our partners’ capital accounts as of the first interim period of the year in which this FSP is initially applied. The adoption of this FSP is not expected to materially affect the Company’s financial position, results of operations or cash flows.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” which provides entities with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This Statement is effective as of the beginning of the first fiscal year that begins after November 15, 2007. The Company is currently evaluating the impact that SFAS No. 159 will have on its consolidated financial statements

Reclassifications

Certain prior year amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on the reported prior year net loss.

NOTE 3. GOING CONCERN

The Company’s financial statements have been prepared on a going concern basis which contemplates the realization of assets and the liquidation of liabilities in the ordinary course of business. The Company has incurred substantial losses from operations and it has a working capital deficit which raises substantial doubt about its ability to continue as a going concern. The Company sustained a net loss of $11,435,134 for the fiscal year ended March 31, 2007 and it had an accumulated deficit of $42,999,146 at March 31, 2007. The Company is currently looking for financing to provide the needed funds for operations. However, the Company is not certain that it will be able to obtain the financing it needs to develop its properties and alleviate doubt about its ability to continue as a going concern.

F-15

NOTE 4 SECURITIES

At March 31, 2007, securities consisted of the following:

	Amortized Cost		Gross Unrealized Gain	Gross Unrealized (Loss)	Estimated Fair Value

Restricted Common Stock	$	1,827,000			$	1,827,000

Total	$	1,827,000			$	1,827,000

At March 31, 2007 securities consisted of $1,827,000 of restricted common stock in Cano Petroleum, Inc. with an estimated fair value that approximated cost.

NOTE 5. REVERSE STOCK SPLIT

On December 19, 2005, the Company’s shareholders approved a one-for-three reverse stock split. The reverse stock split was effective December 22, 2005. The Company retained the current par value of $.001 per share for all common shares. All references in the financial statements and notes to the number of shares outstanding, per share amounts, and stock option and warrant data have been restated to reflect the reverse stock split for all periods presented.

NOTE 6. ASSET RETIREMENT OBLIGATIONS

The FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, which is effective for fiscal years beginning after June 15, 2002. This statement, adopted by the Company as of April 1, 2003, establishes accounting and reporting standards for the legal obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction or development and the normal operation of long-lived assets. It requires that the fair value of the liability for asset retirement obligations be

NOTE 6. ASSET RETIREMENT OBLIGATIONS (continued)

recognized in the period in which it is incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by increasing the carrying amount of the long-lived asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is allocated to expense using a systematic method over the asset’s useful life. Changes in the liability for the asset retirement obligation are recognized for (a) the passage of time and (b) revisions to either the timing or the amount of the original estimate of undiscounted cash flows.

A reconciliation of the changes in the estimated asset retirement obligation follows:

	2007			2006

Beginning asset retirement obligation	$	266,512		$	249,980
Additional liability incurred		0			0
Liabilities assumed by others		(125,455	)		0
Accretion expense		12,402			16,532
Asset retirement cost incurred		(70,517	)		0

Ending asset retirement obligation	$	82,942		$	266,512

F-16

During the years ended March 31, 2007 and 2006, accretion expense of $12,402 and $16,532, respectively, was recognized and is reported in the consolidated statements of operations. Asset retirement obligations at March 31, 2007 were $82,942 related to the wells on the Texas properties.

NOTE 7. CONCENTRATIONS OF CREDIT RISK

Financial instruments which potentially subject the Company to concentrations of credit risk consist of cash equivalents and trade receivables. During the years ended March 31, 2007 and 2006, the Company maintained money market accounts with a bank, which at times exceeded federally insured limits.

Concentrations of credit risk with respect to trade receivables consist principally of oil and gas companies operating within the United States.

Receivables due to the sale of the Cato San Andres properties comprised 99% of the receivable balance at March 31, 2007. Receivables from an oil and gas customer at March 31, 2006 comprised 55% of the trade receivable balance. No allowance for doubtful accounts has been provided since recorded amounts are determined to be fully collectible based upon management’s review of customer accounts, historical experience and other pertinent factors.

NOTE 8. INVENTORY

Inventory consists of the following:

	2007		2006

Oil in tanks	$	31,417	$	48,626

	$	31,417	$	48,626

NOTE 9. OIL AND GAS PROPERTIES AND OPERATIONS

Capitalized costs related to oil and gas producing activities and related accumulated depletion, depreciation and amortization at March 31 are as follows:

	2007		2006

Capitalized costs of oil and gas properties:
Proved	$	0	$	11,401,855
Unproved		5,864,587		5,864,587
		5,864,587		17,266,442
Less accumulated depletion, depreciation and amortization		0		2,048,818
	$	5,864,587	$	15,217,624

F-17

Costs incurred in oil and gas producing activities were as follows:

	2007		2006

Property acquisitions
Proved	$	0	$	0
Unproved		0		26,566
Exploration		0		0
Development		5,830,677		2,507,249

	$	5,830,677	$	2,533,815

Results of operations of oil and gas producing activities for the years ended March 31 are as follows:

	2007			2006

Revenues from oil and gas producing activities:
Sales to unaffiliated parties Expenses	$	1,014,734		$	592,991
Production and operating		1,320,401			259,290
Depreciation, depletion and accretion		502,909			1,040,250
General and administrative		300,952			191,150
Loss on sale of oil and gas assets		6,125,233			0
Ceiling test impairment of oil and gas properties		0			23,199,110

Total expenses		8,249,495			24,689,800

Pretax income (loss) from producing activities		(7,234,761	)		(24,096,809	)
Income tax expense		0			0

Results of oil and gas producing activities (excluding corporate overhead and interest costs)	$	(7,234,761	)	$	(24,096,809	)

NOTE 10. NOTES PAYABLE, RELATED PARTIES

The Company has a $4,000,000 loan agreement with Lothian, its majority shareholder. The loan was subsequently increased to $8,000,000 during 2007. Advances to the Company under this agreement were $2,182,843 as of March 31, 2007 and $1,217,264 as of March 31, 2006. The agreement, dated October 7, 2005, provides for draws as needed for the development of the Cato San Andres Unit in New Mexico. The note bears interest at 1% over the Citibank prime rate (8.75% at March 31, 2007) and is secured by a deed of trust and assignment of production, among other provisions. Loan advances are repayable monthly from 70% of the oil and gas proceeds produced by the Cato San Andres Unit. The note is due and payable on October 7, 2015 and is subordinated to the Sterling Bank agreement discussed below. The loan was reduced by $4,397,760 from the proceeds of the sale of the Cato San Andres Unit and the Tom Tom and Tomahawk Field on March 30, 2007. After the sale of these properties, the loan was then secured by 404,204 shares of restricted Cano Petroleum common stock. Effective June 2007, Lothian accepted the Cano Petroleum common stock as full payment of the loan and accrued interest.

The Company has an additional $2,500,000 loan agreement with Lothian, its majority shareholder. Advances to the Company under this agreement were $759,140 and $195,739 as of March 31, 2007 and 2006, respectively. The agreement, dated as of March 31, 2006, provides for draws as needed for the development of the Wardlaw Field in Texas. The note bears interest at 1% over the Citibank prime rate (8.75% at March 31, 2006) and is secured by a deed of trust and assignment of production, among other provisions. Loan advances are repayable monthly from 70% of the oil and gas proceeds produced by the Wardlaw Field. The note is due and payable on March 31, 2016. There were no payments made during the 2006 or 2007 fiscal years.

F-18

Reducing Revolving Line of Credit Agreement

The Company, as a co-Borrower with its largest shareholder, entered into an Amended and Restated reducing revolving line of credit agreement of up to $20 million (“Credit Agreement”) with Sterling Bank as of March 31, 2006. The line was substantially repaid on March 30, 2007. The Company was thereafter released by Sterling Bank as a co-borrower under the Credit Agreement.

NOTE 11. MAJOR CUSTOMERS

During March 31, 2007 and 2006, the Company only operated in oil and gas producing activities.

The Company recorded oil and gas sales to the following major customers for the years ended March 31:

	2007					2006
	Amount		Percent			Amount		Percent

Customer A	$	799,332		78.8	%	$	230,144		38.8	%
Customer B		215,402		21.2	%		362,847		61.2	%
	$	1,014,734		100	%	$	592,991		100.0	%

NOTE 12. UNREGISTERED SALE OF EQUITY SECURITIES TO LOTHIAN OIL INC.

On December 19, 2005, the Company’s shareholders approved the sale of 1,093,333 shares of the Company’s common stock, $0.001 par value, and warrants to purchase an additional 2,906,666 shares of common stock to Lothian Oil Inc. Proceeds from the sale of these securities were used to repay a line of credit made to the Company by ALMAC Financial Corporation, a corporation wholly-owned by Walter G. Mize, formerly the largest shareholder of the Company. Any funds remaining after payment of the line of credit were used by the Company for working capital purposes.

As part of the agreement, Lothian and the Company entered into a development and operating agreement relative to certain properties belonging to the Company’s wholly-owned subsidiaries, UHC Petroleum Corporation and UHC New Mexico Corporation.

In addition, Lothian purchased 2,666,667 restricted shares of Company common stock from Walter G. Mize, Chairman of the Board of Directors and formerly the Company’s largest shareholder, President and Chief Executive Officer, and six other shareholders for an aggregate purchase price of $10,651,000 or $3.99 per share. Lothian paid the purchase price with a promissory note.

NOTE 13. STOCK OPTION PLANS

Directors of the Company adopted the 1995 Stock Option Plan effective September 11, 1995. This Plan set aside 66,667 shares of the authorized but unissued common stock of the Company for issuance under the Plan. Options may be granted to directors, officers, consultants, and/or employees of the Company and/or its subsidiaries.

Options granted under the Plan must be exercised within five years after the date of grant, but may be affected by the termination of employment. No options have been granted since 1998 and none are outstanding.

F-19

NOTE 13. STOCK OPTION PLANS (continued)

Directors of the Company adopted the 1998 Stock Option Plan effective July 1, 1998. This Plan and its subsequent amendment set aside 66,667 shares of the authorized but unissued common stock of the Company for issuance under the Plan. Options may be granted to directors, officers, consultants, and/or employees of the Company and/or its subsidiaries. Options granted under the Plan are exercisable over a period to be determined when granted, but may be affected by the termination of employment. As a result of a grant in January 2006 to the Company’s chief executive officer, discussed in more detail below, options to purchase 66,667 shares are outstanding under this plan.

Directors of the Company adopted the 2000 Stock Option Plan effective June 5, 2000. This Plan set aside 1,666,667 shares of the authorized but unissued common stock of the Company for issuance under the Plan. Options may be granted to directors, officers, consultants, advisors, and/or employees of the Company and/or its subsidiaries. Options granted under the Plan must be exercised within the number of years determined by the Stock Option Committee and allowed in the Stock Option Agreement. The Stock Option Agreement may provide that a period of time must elapse after the date of grant before the options are exercisable. The options may not be exercised as to less than 100 shares at any one time.

On May 30, 2003 the Company granted 1,051,667 options under the 2000 Stock Option Plan. The options were granted to directors, employees and others. The options vest over a two-year period with terms of three to five years. The exercise price is $1.50 per share. During fiscal year 2006, the Company granted an option for 40,000 shares to a member of the Board of Directors for and in consideration of services provided to the Company. The option was issued at $2.91 per share for a term of five years with vesting over a three-year period.

On May 24, 2005, the Company granted options to certain members of the Board of Directors for and in consideration of services provided to the Company, as shown in the table below. The options were issued at $1.50 for a term of three years.

On January 3, 2006, the Company granted options to purchase 500,000 shares to the Company’s chief executive officer for and in consideration of services provided to the Company. The options were issued at $1.05 per share for a term of three years with one-third of the options being exercisable immediately and one-third exercisable in each of the following two years. The fair value of each option was determined to be $2.50.

The following schedule summarizes pertinent information with regard to the Plans for the years ended March 31:

	2007				2006
	Shares outstanding		Weighted average exercise price		Shares outstanding		Weighted average exercise price

Beginning of year		1,725,000	$	1.40		1,051,667	$	1.50
Granted		0				673,333		1.25
Exercised		0				0		0
Forfeited		0				0		0
Expired		0				0		0

End of year		1,725,000	$	1.40		1,725,000	$	1.40

Options granted to non-employees under the above three plans resulted in compensation expense of $4,462 for the year ended March 31, 2006. The intrinsic value of options issued in 2006 resulted in expense of $343,750 being accrued in the accompanying financial statements. At March 31, 2007 there is no intrinsic value associated with the outstanding or exercisable options as the Company’s stock price is lower than the exercise price of the options.

F-20

NOTE 13. STOCK OPTION PLANS (continued)

The following table summarizes information for options outstanding as of March 31, 2007:

Options Outstanding								Options Exercisable
Exercise Price		Number		Weighted Average Remaining Life- Years		Weighted Average Exercise Price		Number		Weighted Average Exercise Price		Weighted Average Remaining Life Years

$	1.50		1,185,000		2.17	$	1.50		1,185,000	$	1.50		2.17
	2.91		40,000		2.17		2.91		26,667		2.91		2.17
	1.05		500,000		8.76		1.05		333,333		1.05		8.76

$	1.05-$2.91		1,725,000		4.08	$	1.36		1,545,000	$	1.43		3.59

As of March 31, 2007 and 2006, nonvested options were comprised of the following:

	Number of shares		Weighted average grant date fair value

Nonvested March 31, 2005		0		0
Granted		673,333		2.15
Vested		313,334		1,81
Expired/forfeited		0		0
Nonvested, March 31, 2006		359,999		2.44
Granted		0		0
Vested		179,999		2.44
Expired/forfeited		0		0
Nonvested, March 31, 2007		180,000		2.44

As of March 31, 2007, approximately $439,000 of total unrecognized compensation cost related to nonvested share-based compensation arrangements is to be recognized over the next year.

The option agreements related to the options with $1.50 and $2.91 exercise prices were modified to extend the expiration date to March 31, 2009, add a put feature where the option holder can put the option back to the Company for the difference between $4.00 per share and the purchase price between April 1, 2008 and April 10, 2008 and add a call feature whereby the Company can call the option for the difference between $7.50 and the purchase price. Since the put feature does not subject the holder to the normal risks of share ownership, the options are classified as liability awards and recorded at fair value. A liability and corresponding expense of $2,727,186 has been recorded in the accompanying financial statements.

F-21

NOTE 14. STOCK WARRANTS

The Company entered into a stock warrant agreements effective January 12, 2004. Pursuant to the agreements, the Company issued 500,000 warrants to purchase common stock in connection with a private placement. Warrants issued under the agreements must be exercised by March 15, 2014.

The Company entered into a stock warrant agreements effective April 2004 in connection with the offering of convertible promissory notes. Pursuant to the agreements, the Company issued 1,766,667 warrants to purchase common stock. Warrants issued under the agreements must be exercised by March 15, 2014.

On December 19, 2005, the Company’s shareholders approved the issuance of warrants to purchase an additional 2,906,666 shares of Common Stock to Lothian Oil Inc. The warrants are exercisable upon issuance and have a term of five years and were issued as follows:

Warrant for the purchase of 953,333 shares with an exercise price of $3.15 per share;

Warrant for the purchase of 1,000,000 shares with an exercise price of $3.36 per share;

Warrant for the purchase of 953,333 shares with an exercise price of $3.75 per share.

The following schedule summarizes pertinent information with regard to the stock warrants for the years ended March 31:

	2007				2006
	Shares outstanding		Weighted average exercise price		Shares outstanding			Weighted average exercise price

Beginning of year		5,085,334	$	3.08		2,266,667		$	2.64
Granted		0				2,956,900			3.39
Exercised		0				(138,233	)		2.25
Forfeited		0				0			0
Expired		0				0			0

End of year		5,085,334	$	3.08		5,085,334		$	3.08

Exercisable		5,085,334	$	3.08		5,085,334		$	3.08

The warrants issued in fiscal 2006 include those issued to Lothian Oil Inc. and 50,234 warrants issued for legal services exercisable at $1.50 per share to satisfy liabilities. No warrants were issued in 2007. No warrants were issued in 2007.

F-22

The following table summarizes information for warrants outstanding as of March 31, 2007:

Warrants Outstanding				Warrants Exercisable
Exercise Price Range		Number	Weighted Average Remaining Life-Years	Weighted Average Exercise Price		Number	Weighted Average Exercise Price

$	2.25-$3.00	2,178,668	.7.00	$	2.62	2,178,668	$	2.62
	3.15-3.75	2,906,666	3.72		3.42	2,906,666		3.42

$	2.25-$3.75	5,085,334	5.13	$	3.08	5,085,334	$	3.08

During the years ended March 31, 2007 and 2006, the Company did not record any expenses for services rendered related to warrants issued under the agreements.

NOTE 15.

INCOME TAXES

Deferred income tax assets and liabilities are computed annually for differences between financial statement and tax bases of assets and liabilities that will result in taxable or deductible amounts in the future based on enacted tax laws and rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances are established when necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred tax assets and liabilities.

The Company’s federal tax provision consists of the following:

	2007			2006

Current	$	0		$	0
Adjustments of beginning of year valuation allowance		0			(3,099,000	)
Deferred		3,729,296			(4,950,925	)
Valuation allowance		(3,729,296	)		0
Federal	$	0		$	(8,049,925	)

The effective tax rate on the net loss before income taxes differs from the U.S. statutory rate as follows:

	2007			2006

U.S. statutory rate		34	%		34	%
Valuation allowance		(34	)%		0
Other		0			(2	)%
Effective tax rate		0			32	%

F-23

NOTE 15.

INCOME TAXES continued

At March 31, the deferred tax asset and liability balances are as follows:

	2007			2006

Deferred tax asset
Net operating loss	$	5,207,899		$	3,089,263
Accrued put option		927,243			—
Accrued expenses		145,075			207,489
		6,280,217			3,296,752
Deferred tax liability - oil and gas properties		(680,865	)		(1,426,696	)

Net deferred tax asset		5,599,352			1,870,056
Valuation allowance		(5,599,352	)		(1,870,056	)
Deferred tax asset (liability)	$	0		$	0

The net change in the valuation allowance for 2007 was an increase of $3,729,296 and 2006 had a decrease of $1,228,944. The deferred tax asset is due primarily to the net operating loss carryover and the accrued put option expense. The deferred tax liability results from difference in the basis of oil and gas properties for tax and financial reporting purposes.

The Company has a net operating loss carryover of approximately $15.3 million available to offset future income for income tax reporting purposes, which will ultimately expire in 2027, if not previously utilized. Due to the change in control in 2006, the use of the net operating loss each year will be limited based on applicable Internal Revenue Code provisions.

NOTE 16.

STOCK BONUS PLAN

The Company has a stock bonus plan, which provides incentive compensation for its directors, officers, and key employees. The Company has reserved 30,000 shares of common stock for issuance under the plan. As of March 31, 2007, 27,800 shares had been issued in accordance with the plan. No shares were issued under the plan in 2007.

NOTE 17.

CONTINGENCIES

The Company is involved in various claims incidental to the conduct of our business. Based on consultation with legal counsel, we do not believe that any claims, either individually or in the aggregate, to which the Company is a party will have a material adverse effect on our financial condition or results of operations.

NOTE 18.

2002 CONSULTANT EQUITY PLAN

In August 2002, the Company adopted “The 2002 Consultant Equity Plan,” whereby 333,333 shares of unissued common stock were reserved for issuance to consultants, independent contractors and advisors in exchange for bona fide services rendered not in connection with a capital raising transaction. All shares reserved under the plan have been issued as of March 31, 2006.

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NOTE 19.

SUBSEQUENT EVENT

On June 13, 2007 Lothian Oil Inc., the Company’s largest shareholder, filed a petition under Chapter 11 of the U.S. Bankruptcy Code. In the past, the Company relied on Lothian Oil Inc. to provide funds for its operations. The Company does not know what effect this action will have on its ability to continue its operations.

NOTE 20.

SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Proved Reserves

Independent petroleum engineers have estimated the Company’s proved oil and gas reserves, all of which are located in the United States. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available.

The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors.

	Oil (Bbls)			Gas (Mcf)

March 31, 2005 (Restated)		567,189			2,934,765
Extensions, additions and discoveries		—			—
Revisions of previous estimates		(67	)		(222,358	)
Production		(7,380	)		(110,336	)

March 31, 2006		559,742			2,602,071
Extensions, additions and discoveries		0			0
Revisions of previous estimates		0			0
Oil and gas asset sales		(543,661	)		(2,534,085	)
Production		(16,081	)		(67,986	)

March 31, 2007		0			0

Proved Developed Reserves

March 31, 2006	559,742	2,602,071

March 31, 2007	0	0

Standardized Measure

The standardized measure of discounted future net cash flows (“standardized measure”) and changes in such cash flows are prepared using assumptions required by the Financial Accounting Board. Such assumptions include the use of year-end prices for oil and gas and year-end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Discounted future net cash flows are calculated using a 10% rate. Estimated future income taxes are calculated by applying year-end statutory rates to future pre-tax net cash flows, less the tax basis of related assets and applicable tax credits.

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The standardized measure does not represent management’s estimate of the Company’s future cash flows or the value of proved oil and gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, year-end prices used to determine the standardized measure of discounted cash flows, are influenced by seasonal demand and other factors and may not be the most representative in estimating future revenues or reserve data.

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

	March 31, 2007		March 31, 2006

Future cash inflows	$	0	$	40,126,480
Future costs:
Production		0		(15,824,512	)
Development		0		(6,922,896	)

Future net cash flows before income tax		0		17,379,072
Future income tax		0		0

Future net cash flows		0		17,379,072
10% annual discount		0		(9,271,088	)

Standardized measure of discounted future net cash flows	$	0	$	8,107,984

Changes in Standardized Measure of Discounted Future Net Cash Flows

	March 31, 2007			March 31, 2006

Sales of oil and gas net of production costs	$	305,667		$	(333,701	)
Net changes in prices and production and development costs		0			32,496
Sale of reserves in place		(6,114,000	)		0
Revision of quantity estimates and timing		0			(435,706	)
Accretion of discount		0			891,817
Incurred development costs		(3,110,449	)		—
Net change in income taxes		0			0
Other		810,798			(965,094	)
Net decrease	$	(8,107,984	)	$	(810,188	)

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Attached files

Glen Rose Petroleum CORP Reports

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