Imperial Resources, Inc. - FORM 10-K

Attached files

file	filename
EX-3.4 - CERTIFICATE OF FILING OF GREEN TIDE WATER DISPOSAL LTD., DATED JUNE 15, 2011 - Imperial Resources, Inc.	ex34.htm
EX-21.0 - LIST OF SUBSIDIARIES - Imperial Resources, Inc.	ex21.htm
EX-31.2 - CERTIFICATION - Imperial Resources, Inc.	ex312.htm
EX-10.9 - STATELINE LETTER OF AGREEMENT DATED JANUARY 20, 2011 - Imperial Resources, Inc.	ex109.htm
EX-32.1 - CERTIFICATION - Imperial Resources, Inc.	ex321.htm
EX-10.6 - NUNNELLY FARMOUT AGREEMENT - Imperial Resources, Inc.	ex106.htm
EX-31.1 - CERTIFICATION - Imperial Resources, Inc.	ex311.htm
EX-32.2 - CERTIFICATION - Imperial Resources, Inc.	ex322.htm
EX-10.10 - CONVERTIBLE PROMISSORY NOTE FROM QUARRY BAY CAPITAL, LLC, DATED JUNE 17, 2011 - Imperial Resources, Inc.	ex1010.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended March 31, 2011

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

Commission File Number: 333-152160

IMPERIAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Nevada	83-0512922
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

106 E. 6th ST. Suite 900, Austin, TX 78701

(Address of principal executive offices)

(512) 332-5740

(Issuer’s telephone number)

[Missing Graphic Reference]

(Former name, former address and former fiscal year, if changed since last report)

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

YES o

NO x

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

YES o

NO x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the 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

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

YES x

NO o

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

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

Large accelerated filer o	Accelerated filer o
Non-accelerated filer o (do not check if smaller reporting company)	Smaller reporting company x

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

YES o

NO x

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 last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed fourth fiscal quarter of March 31, 2011: $22,028,292.

As of June 29, 2011, there were outstanding 42,362,100 shares of registrant’s common stock, par value $0.001 per share.

TABLE OF CONTENTS

The statements regarding future financial and operating performance and results, strategic pursuits and goals, market prices, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements. These statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives and other factors detailed in this document and in our other Securities and Exchange Commission filings. See “Risk Factors” in Item 1A for additional information about these risks and uncertainties. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this document. See “Forward-Looking Information” for further details.

		Page

PART I

ITEM 1.	Business.	3

ITEM 1A.	Risk Factors.	8

ITEM 1B.	Unresolved Staff Comments.	13

ITEM 2.	Properties.	13

ITEM 3.	Legal Proceedings.	14

ITEM 4.	(Removed and Reserved)	14

PART II

ITEM 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities.	14

ITEM 6	Selected Financial Information.	15

ITEM 7.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations.	15

ITEM 7A.	Quantitative and Qualitative Disclosure about Market Risk.	21

ITEM 8.	Financial Statement and Supplementary Data.	21

ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	21

ITEM 9A(T)	Controls and Procedures	22

ITEM 9B	Other information	23

PART III

ITEM 10.	Directors, Executive Officers and Corporate Governance.	24

ITEM 11.	Executive Compensation.	26

ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	26

ITEM 13.	Certain Relationships and Related Transactions, and Director Independence.	27

ITEM 14	Principal Accounting Fees and Services.	28

PART IV

ITEM 15.	Exhibits, Financial Statement Schedules	29

	SIGNATURES	31

GLOSSARY OF CERTAIN OIL AND GAS TERMS

The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and included within this Annual Report on Form 10-K:

Abbreviations

Bbl(s). One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Mbbl. One thousand barrels of oil.

Bcf. One billion cubic feet of natural gas.

Mcf. One thousand cubic feet of natural gas.

Mmcf. One million cubic feet of natural gas.

Mmcfe. One million cubic feet of natural gas equivalent.

Energy content of one Mbbl is equivalent to approximately 6 Mmcf

Definitions

Developed reserves. Developed reserves are reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, or a service well.

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

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

Oil. Crude oil and condensate.

Operator. The individual or company responsible for the exploration and/or production of an oil or gas well or lease.

Proved reserves. Proved reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with “reasonable certainty” to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions and operating methods prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Probable reserves. defined as oil and gas additional reserves that are less certain to be recovered than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered.

Possible reserves. i.e. "having a chance of being developed under favorable circumstances".

Royalty interest. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Undeveloped reserves. Undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

The terms “developed reserves”, “development well”, “exploratory well”, “extension well”, “field”, “proved reserves”, “reserves”, “reservoir” and “undeveloped reserves” are defined by the SEC.

PART I

ITEM 1. BUSINESS

Background

Imperial Resources, Inc. (“the Company”) was incorporated under the laws of the State of Nevada on August 2, 2007, with the authorized capital stock of 500,000,000 shares at $0.001 par value.

The Company was organized for the purpose of acquiring and exploring a gold mine property and later abandoned it. The Company has decided to focus its core activities on development and exploration of oil and gas assets in the United States through its wholly owned subsidiary Imperial Oil & Gas Inc. (“Imperial Oil” or “the Company”). Imperial Oil was incorporated under the laws of the State of Delaware on January 8, 2010.

The Company was formerly considered in the Exploration Stage. The Company purchased a producing oil and gas interest on January 10, 2010, of which subsequently 100% of all revenues for the years ended March 31, 2011 and 2010, are attributable to this interest.

The Company has engaged in the exploration and development of oil and natural gas properties of others under arrangements in which we finance the costs in exchange for interests in the oil or natural gas revenue generated by the properties. Such arrangements are commonly referred to as farm-ins to us, or farm-outs by the property owners farming out to us.

As of March 31, 2011, our investment program totaled $322,126 including lease acquisitions, drilling and facilities. Our capital spending was funded through the conversion of a long-term note payable of $900,000 into our common stock, and raising capital through the issuance of subscription agreements for $500,000.

We remain focused on our strategies of pursuing lower risk drilling opportunities that provide more predictable results on our accumulated acreage position. Additionally, we intend to maintain spending discipline and manage our balance sheet in an effort to ensure sufficient liquidity, including cash resources and available credit. We believe these strategies are appropriate for our portfolio of projects and the current industry environment.

Cochran #1 Well

On January 20, 2010, the Company acquired a 14.9% working interest in the oil, gas and mineral leases in the Greater Garwood hydrocarbon exploration project located in Colorado County, Texas (the “Project”). The Project included one producing well known as the Cochran #1 Well, which is being operated by El Paso E & P Company, L.P, and other mineral leases with possible reserves for surrounding areas covering approximately 1,844 gross acres. The Cochran #1 Well produced and sold approximately 22 Mmcfe, net during the twelve months ended March 31, 2011, and 6 Mmcfe net to Imperial for the three months ended March 31, 2010. The Company obtained a reserve report dated December 2009, showing total estimated net proved reserve estimates of approximately 287 Mmcfe for the Cochran #1 Well. All revenues for the years ended March 31, 2011 and 2010 are from the Cochran Well.

The leases on additional acreage in the Greater Garwood Project with possible reserves expired before the year ended March 31, 2011. As such, the Company has incurred $370,295 related to impairment on the expired leases, and has included the impairment charge in the Consolidated Statement of Operations for the year ended March 31, 2011.

The Greater Garwood interests were acquired from the issuance of a $900,000 note payable. On December 10, 2010, the note payable of $900,000, plus $42,534 in accrued interest, was converted to 1,625,059 shares of the Company’s common stock at $0.58 per share. The fair value of the shares on the date of exchange was $1,218,794, which resulted in recording a loss on debt extinguishment of $276,260. This loss is included in our Consolidated Statement of Operations for the year ended March 31, 2011.

Oklahoma Project

In July of 2010, Imperial Oil entered into a participation agreement in an area of mutual interest (AMI) and joint operating agreement to acquire a 50% working interest in leases on up to 5,000 acres in Oklahoma. The agreements provide the Company a 50% working interest in proposed horizontal oil and gas drilling projects in the AMI. As of March 31, 2011, there were no costs incurred on the project. Subsequent to year-end March 31, 2011, the Company has participated in $82,127 of acreage costs and associated expenses. All leases are required to provide a gross net royalty interest of 79.25% or greater. At the Company’s option we may elect to participate in drilling and completion costs.

Nunnelly #1 Project

On January 10, 2011, the Company entered into an Oil and Gas lease (“Agreement”) with the mineral owner of approximately 35 acres and an existing wellbore in Montague County Texas. The Agreement provides for the development of the Project lease area and the existing well, known as Nunnelly #1. The mineral owners’ will retain a 25% royalty interest in the acreage. Imperial has the option, to pay the costs associated with deepening and completion of the well, or alternatively, the drilling and completion of a new well. The Company obtained an evaluation from an independent registered petroleum engineer indicating net probable recoverable oil reserves of approximately 17 Mbbls. Deepening of the existing Nunnelly #1 wellbore is the Company’s first planned option. As of March 31, 2011, $19,760 was capitalized, relating to surface preparation work at the site.

Stateline

On January 25, 2011, the Company entered into a Farmout Agreement ("Agreement") with a private oil and gas exploration company, for the right to earn acreage by drilling up to four wells in an infill development project ("Stateline") in the existing Sawyer Field, in Lea County, New Mexico. The Agreement calls for the Company’s subsidiary to pay a spud fee of $60,000 and drill between one and four wells to earn a 77% net revenue interests in 40 acres for each well drilled, subject to a reservation by the assigning party of a 10% working interest in each well drilled. The Agreement requires that not later than 270 days, drilling must be commenced on the first well. Drilling on the next well must be commenced not later than 180 days following the release of the drilling rig on the first well, with the drilling of subsequent wells having the same commencement requirements as the previously drilled well.

As of March 31, 2011, the Company has invested $60,000 related to the spud fee. The Company conducted an internal Reserve Evaluation and believes estimated net proved undeveloped reserves of approximately 41 Mbbl of oil. The Company’s capital expense for the first well is expected to be around $635,000. Over the four wells it is estimated that total probable reserves will be in excess of 250 Mbbls of oil.

Salt Water Disposal Facility

Subsequent to year end, on April 27, 2011 Imperial Oil entered into a Purchase and Sale Agreement to purchase approximately 41 acres of land, a related salt water disposal facility (”SWDF”) consisting of surface equipment, and a wellbore and associated permits. The acreage is, located in Wise County, Texas. The total purchase price of $500,000 was made through a $50,000 signing payment, plus the execution of a Convertible Promissory Note (the “Note”) totaling $450,000. The Note is secured over the SWDF assets.

The SWDF is located in the heart of the Barnett Shale, the largest gas play by number of wells, in Texas. The SWDF is conveniently located for the disposal of large volumes of salt water generated from essential fracture (“frac”) stimulation operations on Barnett Shale gas wells, some of which have been frac’ed up to four times. There are approximately 6,000 wells within 20 miles of the Facility.

Mara Prospects and Net Profit Interest

On January 19, 2010, Imperial Oil entered into a Net Profit Agreement with Mara Energy, LLC (“Mara”), whereby Imperial agreed to share profits from certain mutually beneficial oil and gas exploration and development opportunities in Canada and the continental United States, which are procured by Mara. The Net Profit Interest of 50% will be assigned to Mara after “Payout", which means the date when the Imperial recovers Net Profits in an amount equal to the initial funded amount. In addition, effective April 1, 2010, Imperial Oil and Mara entered into a Consulting Services Agreement, whereby Imperial Oil and Mara agreed that Mara will provide consulting services associated with any future development of Imperial Oil’s working interest in both the Greater Garwood oil and gas development exploration asset and the producing Cochran #1 well located in the Greater Garwood prospect in Colorado County, Texas. At March 31, 2011, no royalties or consulting fees have been paid. Mara is partially owned by our CEO and director, and a director, and former officers of the Company. Subsequent to year-end March 31, 2011 the Mara Net Profit Agreement was terminated on July 8, 2011 by mutual agreement between Imperial Oil and Mara.

Sydney Oil and Gas Overriding Royalty Interest

On April 1, 2010, Imperial Oil entered into an Assignment of Overriding Royalty Interest Agreement to assign or pay Sydney Oil & Gas, LLC (“Sydney”), a gross overriding royalty of 6.5% of 8/8 for each lease proportionally reduced by the actual working interest acquired by Imperial Oil. Imperial’s CEO owns an interest in and controls Sydney. At March 31, 2011 no royalties have been paid.

Internal Controls Over Reserve Estimation Process and Qualifications of Third Party Engineers

Our policies regarding internal controls over the recording of reserves estimates requires reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles.

Coach Capital, LLC, from whom we acquired our interest in the Garwood Property, commissioned a third party Reservoir Evaluation on the Garwood Property, which was completed on December 22, 2009 (the “Reserve Report”). A copy of the Reserve Report is attached as an Exhibit to this Annual Report on Form 10-K and incorporated herein by reference. The Reserve Report was prepared by Grant Twanow, our former Director, President and Chief Executive Officer. Mr. Twanow is a Petroleum Reservoir Engineering Specialist based in North America with extensive experience in oil and gas joint ventures and operations. We have not engaged any third party to conduct a reserve audit.

The Company has conducted an internal reserve evaluation for our interest in the Stateline wells. For additional information about the risks inherent in our estimates of proved reserves, see “Risk Factors”. Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A.

Reserves and Acreage

All of our reserves and acreage are located in the United States. The table below sets forth the estimate of our net proved reserves as of March 31, 2011. Proved reserves cannot be measured exactly because the estimation of reserves involves numerous judgments and variables. Reserve estimates must be continually revised to as a result of new information obtained from drilling and production history, new geological and geophysical data and changes to economic conditions.

	Oil and Natural Gas Condensate	Natural Gas	Total
	(Mbbls)	(Mmcf)	(Mmcfe)
Producing-Cochran Well #1	3.75	176.42	198.93
Proved Undeveloped-Stateline	40.78	0	244.68
Total Proved	44.53	176.42	443.61

Our proved undeveloped reserves (PUDs) of approximately 41 Mbbls as of March 31, 2011, represents an increase from zero proved undeveloped reserves of condensate and natural gas as of March 31, 2010. This increase is due to our acquisition of an interest in the Stateline project during the year.

The following table sets forth our interest in wells and acreage for proved reserves as of March 31, 2011.

	Number of Productive Wells		Developed Acreage (3)			Undeveloped Acreage
	Gross (1)	Net (2)	Gross (1)		Net (2)	Gross (1)	Net (2)

Natural Gas and Condensate	1	.1	400	44.7		0	0
Oil and Natural Gas	0	0	0	0		40	25

(1) A gross well or acre is a well or acre in which we own an interest.

(2) A net well or acre is deemed to exist when the sum of fractional ownership interests in wells or acres equals 1.

(3) Developed acreage is acreage assignable to productive wells.

Production, Production Prices and Production Costs

Proved Developed Reserves

Our net proved developed reserves from the Cochran #1 Well are summarized in the table below in Mmcfe.

	March 31, 2011		March 31, 2010
	(Mmcfe)		(Mmcfe)
Beginning of the period	222.77	$	229.67
Revisions of previous estimates	-		-
Extensions and discoveries			-
Production	(23.84)		(6.90)
End of the period	198.93	$	222.77

The following table presents certain information with respect to the Cochran #1 Producing Well:

		March 31, 2011	March 31, 2011
Production operations:
Natural gas (Mcf)		21,639	6,327
Crude oil and condensate (Mbbls)		.37	.10
Produced Sales Price:(1)	$	$	$
Natural gas ($/Mcf)		4.07	5.35
Crude oil and condensate ($/Bbl)		80.07	77.21
Production Costs ($/Mcfe)(2)		2.89	1.97

(1)	Represents the average realized sales price for all production volumes and royalty volumes sold during the periods shown

(2)

Production costs include direct lifting costs (labor, repairs and maintenance, materials and supplies), the costs of administration of production offices and insurance, but is exclusive of depreciation and depletion applicable to capitalized lease acquisition, exploration and development expenditures and taxes other than income.

Exploratory and Development Activities

All our exploratory and development activities relate to properties that were acquired during the year ended March 31, 2011.

As of March 31, 2011, we paid a spud fee totaling $60,000 to establish the right to start drilling on our Stateline first well. The Company conducted an internal reserve evaluation and believes estimated net proved undeveloped reserves of approximately 41 Mbbl of oil. The Company’s capital expense for the first well is expected to be around $635,000. The Agreement on the project also requires that not later than 270 days, drilling must be commenced on the first well. Drilling on the next well must be commenced not later than 180 days following the release of the drilling rig on the first well, with the drilling of subsequent wells having the same commencement requirements as the previously drilled well.

As of March 31, 2011, we had incurred development costs for surface preparation work totaling $19,760, to deepen of the existing Nunnelly #1 wellbore. The Company obtained an evaluation in April 2011, from an independent registered petroleum engineer indicating net probable recoverable oil reserves of approximately 17 Mbbls. The Company’s capital expense for the first well is expected to be around $276,625.

Delivery Commitments

As of March 31, 2011, we had no delivery commitments for oil or natural gas under existing contracts or agreements.

Development

Our future operations are dependent upon the identification and successful completion of additional long-term or permanent equity financings, the support of creditors and stockholders, and, ultimately, the achievement of profitable operations. There can be no assurances that we will be successful, which would in turn significantly affect our ability to roll out our business plan. If not, we will likely be required to reduce operations or liquidate assets. We will continue to evaluate our projected expenditures relative to our available cash and to seek additional means of financing in order to satisfy our working capital and other cash requirements.

We continue to operate with very limited administrative support, and our current officers and directors continue to be responsible for many duties to preserve our working capital. We expect no significant changes in the number of employees over the next 12 months.

Subject to available financing, we plan to initiate drilling operations in the next several months, and together with commencing production, we may have some significant ongoing capital expenditures. We believe that, with our current efforts to raise capital, we should have sufficient cash resources to satisfy our needs over the next twelve months. Our ability to satisfy cash requirements thereafter will determine whether we achieve our business objectives. Should we require additional cash in the future, there can be no assurance that we will be successful in raising additional debt or equity financing on terms acceptable to our company, if at all.

Employees

As of March 31, 2011, we had no employees. We currently utilize temporary contract labor throughout the year to address business and administrative needs.

ITEM 1A. RISK FACTORS

An investment in our common stock involves an exceptionally high degree of risk and is extremely speculative. The material risks and uncertainties that management believes affect us are described below. Before making an investment decision, you should carefully consider the risks and uncertainties described below together with all of the other information included or incorporated by reference in this report. The risks and uncertainties described below are not the only ones facing us. Additional risks and uncertainties that management is not aware of or focused on or that management currently deems immaterial may also impair our business operations. This report is qualified in its entirety by these risk factors. If any of the following risks actually occur, our financial condition and results of operations could be materially and adversely affected. If this were to happen, the value of our common stock could decline significantly, and you could lose all or part of your investment.

Risks Related to Our Business and Industry

The duration or severity of the current global economic downturn and disruptions in the financial markets, and their impact on us, are uncertain.

The oil and gas industries generally are highly cyclical, with prices subject to worldwide market forces of supply and demand and other influences. The recent global economic downturn, coupled with the global financial and credit market disruptions, have had a historic negative impact on the oil and gas industry. These events have contributed to an unprecedented decline in crude oil and natural gas prices, weak end markets, a sharp drop in demand, increased global inventories, and higher costs of borrowing and/or diminished credit availability. While we believe that the long-term prospects for oil and gas remain bright, we are unable to predict the duration or severity of the current global economic and financial crisis. There can be no assurance that any actions we may take in response to further deterioration in economic and financial conditions will be sufficient. A protracted continuation or worsening of the global economic downturn or disruptions in the financial markets could have a material adverse effect on our business, financial condition or results of operations.

Our limited operating history may not serve as an adequate basis to judge our future prospects and results of operations.

We have a limited operating history. As such, our historical operating results may not provide a meaningful basis for evaluating our business, financial performance and prospects. We may not be able to achieve a similar growth rate in future periods. Accordingly, you should not rely on our results of operations for any prior periods as an indication of our future performance. Our success is significantly dependent on meeting business objectives. Our operations will be subject to all the risks inherent in the establishment of a developing enterprise and the uncertainties arising from the absence of a significant operating history.

We may be unable to locate recoverable resources or operate on a profitable basis. We are in the development stage and potential investors should be aware of the difficulties normally encountered by enterprises in the development stage. If our business plan is not successful, and we are not able to operate profitably, investors may lose some or all of their investment in our company.

We have incurred losses in prior periods and may incur losses in the future.

We have incurred net losses since inception. We cannot be assured that we can achieve or sustain profitability on a quarterly or annual basis in the future. Our operations are subject to the risks and competition inherent in the establishment of a business enterprise. There can be no assurance that future operations will be profitable. We may not achieve our business objectives and the failure to achieve such goals would have an adverse impact on us.

If we are unable to obtain additional funding our business operations will be harmed and if we do obtain additional financing our then existing stockholders may suffer substantial dilution.

We will need to obtain additional financing in order to complete our business plan. Our business plan calls for significant expenses in connection with our exploration activities. Furthermore, if our exploration program is successful in discovering commercially exploitable reserves of valuable resources, we will require additional funds in order to begin commercial production. Obtaining additional financing will be subject to market conditions, industry trends, investor sentiment and investor acceptance of our business plan and management. These factors may make the timing, amount, terms and conditions of additional financing unattractive or unavailable to us. If we are not successful in achieving financing in the amount necessary to further our operations, implementation of our business plan may fail or be delayed. If we are unsuccessful in obtaining additional financing when we need it, our business may fail before we ever become profitable and our stockholders may lose their entire investment.

Our auditors have expressed substantial doubt about our ability to continue as a going concern.

The auditors' report on our financial statements expressed an opinion that our Company’s capital resources are not sufficient to sustain operations or complete our planned activities for the upcoming year unless we raise additional funds. These conditions raise substantial doubt about our ability to continue as a going concern. If we do not obtain additional funds there is the distinct possibility that we will no longer be a going concern and will cease operation which means any persons purchasing shares will lose their entire investment in our Company.

Oil and gas exploration are highly speculative ventures and it is highly probable that no reserves will be discovered and any funds spent on exploration will be lost.

Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil reservoirs. The wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in those wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that crude is present or may be produced economically. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including, but not limited to:

•	unexpected drilling conditions;
•	pressure or irregularities in formations;
•	equipment failures or accidents;
•	mechanical difficulties, such as lost or stuck oil field drilling and service tools;
•	fires, explosions, blowouts and surface cratering;
•	uncontrollable flows of oil and formation water;
•	environmental hazards, such as oil spills, pipeline ruptures and discharges of toxic gases;
•	other adverse weather conditions; and
•	increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment.

Certain future drilling activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.

Our future operating revenue is dependent upon the performance of our leased properties.

Our future operating revenue depends upon our ability to profitably operate our existing leased properties by drilling and completing wells that produce commercial quantities of oil and gas and our ability to expand our operations through the successful implementation of our plans to explore, acquire and develop additional properties. The successful development of oil and gas properties requires an assessment of potential recoverable reserves, future oil and gas prices, operating costs, potential environmental and other liabilities and other factors. Such assessments are necessarily inexact. No assurance can be given that we can produce sufficient revenue to operate our existing properties or acquire additional oil and gas producing properties and leases. We may not discover or successfully produce any recoverable reserves in the future, or we may not be able to make a profit from the reserves that we may discover. In the event that we are unable to produce sufficient operating revenue to fund our future operations, we will be forced to seek additional, third party funding, if such funding can be obtained. Such options would possibly include debt financing, sale of equity interests in our Company, joint venture arrangements, or the sale of oil and gas interests. If we are unable to secure such financing on a timely basis, we could be required to delay or scale back our operations. If such unavailability of funds continued for an extended period of time, this could result in the termination of our operations and the loss of an investor’s entire investment.

We own rights to properties that have not yet been developed.

We own rights to properties that have limited or no development. There are no guarantees that our properties will be developed profitably or that the potential resources on the property will produce as expected if they are developed.

Market factors in the oil and gas business are out of our control and so we may not be able to profitably sell any reserves that we find.

The potential profitability of oil and gas properties is dependent upon many factors beyond our control. For instance, world prices and markets for oil and gas are unpredictable, highly volatile, potentially subject to governmental fixing, pegging, controls or any combination of these and other factors, and respond to changes in domestic, international, political, social and economic environments. Additionally, due to worldwide economic uncertainty, the availability and cost of funds for production and other expenses have become increasingly difficult, if not impossible, to project. These changes and events may materially affect our future financial performance. These factors cannot be accurately predicted and the combination of these factors may result in our Company not receiving an adequate return on invested capital.

If we are unable to hire and retain key personnel, we may not be able to implement our business plan and our business will fail.

We will compete with other exploration companies in the recruitment and retention of qualified managerial and technical employees. Our success will be largely dependent upon our ability to hire highly qualified personnel. This is particularly true in highly technical businesses such as oil or gas exploration. These individuals may be in high demand and we may not be able to attract the staff we need. In addition, we may not be able to afford the high salaries and fees demanded by qualified personnel, or may lose such employees after they are hired. Currently, we have not hired any key personnel and we do not intend to do so for the next 12 months. If we are unable to hire key personnel when needed, our exploration program may be slowed down or suspended.

Since our executive officers do not have technical training or experience in starting, and operating an oil or gas exploration company there is a higher risk our business will fail.

Our executive officers have no experience in oil or gas exploration and do not have formal training in engineering or in the technical aspects of management of an exploration company. This inexperience means that we will have to rely on the technical services of others with expertise in oil and gas exploration in order for us to carry our planned exploration program. If we are unable to contract for the services of such individuals, it will make it difficult and may be impossible to successfully develop our business. There is thus a higher risk that our operations, earnings and ultimate financial success could suffer irreparable harm and that our stockholders will lose all of their investment.

We depend on the skill, ability and decisions of third party operators to a significant extent.

The success of the drilling, development and production of the properties in which we have or expect to have a working interest is substantially dependent upon the decisions of such third-party operators and their diligence to comply with various laws, rules and regulations affecting such properties. The failure of any third-party operator to make decisions, perform their services, discharge their obligations, deal with regulatory agencies, and comply with laws, rules and regulations, including environmental laws and regulations in a proper manner with respect to properties in which we have an interest could result in material adverse consequences to our interest in such properties, including substantial penalties and compliance costs. Such adverse consequences could result in substantial liabilities to us or reduce the value of our properties, which could negatively affect our results of operations.

Our operations involve substantial costs and are subject to various economic risks.

Our operations are subject to the economic risks typically associated with exploration, development and production activities, including the necessity of significant expenditures to locate and acquire producing properties and to drill exploratory wells. The cost and length of time necessary to produce any reserves may be such that it will not be economically viable. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause our exploration, development and production activities to be unsuccessful. In addition, the cost and timing of drilling, completing and operating wells is often uncertain. We also face the risk that the resources located may be less than anticipated, that we will not have sufficient funds to successfully extract such resources, that we will not be able to market the resources due to a lack of a market and that fluctuations in market prices will make development of those leases uneconomical. This could result in a total loss of our investment.

We are subject to risks arising from the failure to fully identify potential problems related to acquired reserves or to properly estimate those reserves.

Although we perform a review of the acquired properties that we believe is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher-value properties and will sample the remainder, and depend on the representations of previous owners. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties. There are numerous uncertainties inherent in estimating quantities of proved oil reserves and actual future production rates and associated costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates.

A substantial or extended decline in oil and gas prices may adversely affect our business, financial condition, cash flow, liquidity or results of operations as well as our ability to meet our capital expenditure obligations and financial commitments to implement our business plan.

Any revenues, cash flow, profitability and future rate of growth we achieve will be greatly dependent upon prevailing prices for oil and gas. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms is also expected to be dependent on oil and gas prices. Historically, oil and gas prices and markets have been volatile and are likely to continue to be volatile in the future. Prices for oil and gas are subject to potentially wide fluctuations in response to relatively minor changes in supply of and demand for oil and gas, market uncertainty, and a variety of additional factors beyond our control. Those factors include:

•	the domestic and foreign supply of oil and natural gas;
•	the ability of members of the Organization of Petroleum Exporting Countries and other producing countries to agree upon and maintain oil prices and production levels;
•	political instability, armed conflict or terrorist attacks, whether or not in oil or natural gas producing regions;
•	the level of consumer product demand;
•	the growth of consumer product demand in emerging markets, such as China and India;
•	weather conditions, including hurricanes and other natural occurrences that affect the supply and/or demand of oil and natural gas;
•	domestic and foreign governmental regulations and other actions;
•	the price and availability of alternative fuels;
•	the price of foreign imports;
•	the availability of liquid natural gas imports; and
•	worldwide economic conditions.

These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and natural gas. Lower oil and natural gas prices may not only decrease our revenues on a per unit basis, but may also reduce the amount of oil we can produce economically, if any. A substantial or extended decline in oil and natural gas prices may materially affect our future business, financial condition, results of operations, liquidity and borrowing capacity. While our revenues may increase if prevailing oil and gas prices increase significantly, exploration and production costs and acquisition costs for additional properties and reserves may also increase.

Governmental and environmental regulations could adversely affect our business.

Our business is subject to federal, state and local laws and regulations on taxation, the exploration for and development, production and marketing and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste, unitization and pooling of properties and other matters. These laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning our oil wells and other facilities. In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit our revenues.

Our operations are also subject to complex environmental laws and regulations adopted by the various jurisdictions in which we have or expect to have operations. We could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil or water, including responsibility for remedial costs. We could potentially discharge these materials into the environment in any of the following ways:

	•	from a well or drilling equipment at a drill site;
	•	from gathering systems, pipelines, transportation facilities and storage tanks;
	•	damage to oil wells resulting from accidents during normal operations; and
	•	blowouts, cratering and explosions.

Because the requirements imposed by laws and regulations are frequently changed, we cannot assure you that laws and regulations enacted in the future, including changes to existing laws and regulations, will not adversely affect our business. In addition, because we acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage caused by the former operators.

Risks Related to our Common Stock

A limited public trading market exists for our common stock, which makes it more difficult for our stockholders to sell their common stock in the public markets.

Although our common stock is quoted on the OTCBB under the symbol “IPRC,” there is a limited public market for our common stock. No assurance can be given that an active market will develop or that a stockholder will ever be able to liquidate its shares of common stock without considerable delay, if at all. Many brokerage firms may not be willing to effect transactions in the securities. Even if a purchaser finds a broker willing to effect a transaction in these securities, the combination of brokerage commissions, state transfer taxes, if any, and any other selling costs may exceed the selling price. Furthermore, our stock price may be impacted by factors that are unrelated or disproportionate to our operating performance. These market fluctuations, as well as general economic, political and market conditions, such as recessions, interest rates or international currency fluctuations may adversely affect the market price and liquidity of our common stock.

Our common stock may be subject to the penny stock rules which may make it more difficult to sell our common stock.

The Securities and Exchange Commission has adopted regulations which generally define a “penny stock” to be any equity security that has a market price, as defined, less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities may be covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and accredited investors such as, institutions with assets in excess of $5,000,000 or an individual with net worth in excess of $1,000,000 or annual income exceeding $200,000 or $300,000 jointly with his or her spouse. For transactions covered by this rule, the broker-dealers must make a special suitability determination for the purchase and receive the purchaser’s written agreement of the transaction prior to the sale. Consequently, the rule may affect the ability of broker-dealers to sell our securities and also affect the ability of our stockholders to sell their shares in the secondary market.

We have historically not paid cash dividends and do not intend to pay cash dividends.

We have historically not paid cash dividends to our stockholders and management does not anticipate paying any cash dividends on our common stock to our stockholders for the foreseeable future. We intend to retain future earnings, if any, for use in the operation and expansion of our business.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Our office is located at 106 East 6th Street, Suite 900, Austin, Texas.

ITEM 3. LEGAL PROCEEDINGS

We are not aware of any material pending or threatened litigation or of any proceedings known to be contemplated by governmental authorities which are, or would be, likely to have a material adverse effect upon us or our operations, taken as a whole. There are no material proceedings pursuant to which any of our directors, officers or affiliates or any owner of record or beneficial owner of more than 5% of our securities or any associate of any such director, officer or security holder is a party adverse to us or has a material interest adverse to us.

ITEM 4. (Removed and Reserved)

Not applicable.

PART II

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

Market Information

Our common stock is available for trade on the Over the Counter Bulletin Board under the symbol IPRC. Over the Counter Bulletin Board (which we refer to as the “OTCBB”), which is sponsored by the Financial Industry Regulatory Authority (which we refer to as “FINRA”). The OTCBB is a network of security dealers who buy and sell stock. The dealers are connected by a computer network, which provides information on current “bids” and “asks” as well as volume information. The OTCBB is not considered a “national exchange.”

Our common stock is available for trade on the Over the Counter Bulletin Board, however, until the last quarter of March 31, 2011 there was not any active trading. The high for our fourth quarter ended March 31, 2011 was $1.19, and the low was $.47. As of March 31, 2011, the closing bid quotation for our common stock was $0.52 per share.

Stockholders

As of July 1, 2010, there were 42,362,100 shares of common stock issued and outstanding held by 29 stockholders of record (not including street name holders).

Dividends

We have not paid any cash dividends to date and do not anticipate paying any cash dividends in the foreseeable future. Our Board of Directors intends to follow a policy of retaining earnings, if any, to finance our growth. The declaration and payment of dividends in the future will be determined by our Board of Directors in light of conditions then existing, including our earnings, financial condition, capital requirements and other factors.

Securities Authorized for Issuance under Equity Compensation Plans

None

Sales of Unregistered Securities

On December 31, 2010, Imperial entered into a Securities Purchase Agreement with an accredited investor. This Agreement provides that in the Investor’s sole discretion that, in addition to the first subscription of $500,000, it can subscribe for shares of the Company’s common stock until December 31, 2011, from a minimum subscription amount of $500,000 to a maximum subscription amount of $2,500,000, to be priced at a 15% discount to the Volume Weighted Average closing Price (“VWAP”) for the ten business days prior to the date of each subscription or the price of $0.6784 per share, whichever is greater. The total subscription price of $500,000 (“First Subscription”) is due to be paid in cash within fourteen days of the Agreement. No commission or other fee is payable. We issued all of the shares to one (1) U.S. person under the exemption from registration afforded by Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”), and Rule 506 of Regulation D as promulgated by the United States Securities and Exchange Commission under the Securities Act. Following the issuance of shares under the Agreement, the total number of issued and outstanding shares of the Company’s common stock was 42,362,100.

ITEM 6. SELECTED FINANCIAL INFORMATION

Not applicable.

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

The following discussion should be read in conjunction with the information contained in our financial statements and the notes thereto, which form an integral part of the financial statements, which are attached hereto. The financial statements mentioned above have been prepared in conformity with accounting principles generally accepted in the United States of America and are stated in United States dollars.

Our Form 10-K includes a number of forward-looking statements that reflect our current views with respect to future events and financial performance. Forward-looking statements are often identified by words such as: believe, expect, estimate, anticipate, intend, project and similar expressions, or words which, by their nature, refer to future events. You should not place undue certainty on these forward-looking statements, which apply only as of the date of this Form 10-K. These forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from historical results or our predictions.

Overview and Plan of Operation

Producing Wells

Cochran #1 Well

On January 20, 2010, the Company acquired a 14.9% working interest in the oil, gas and mineral leases in the Greater Garwood hydrocarbon exploration project located in Colorado County, Texas (the “Project”). The Project included one producing well known as the Cochran #1 Well. The well produced and sold approximately 22 Mmcfe, net during the twelve months ended March 31, 2011, and 6 Mmcfe net to Imperial for the three months ended March 31, 2010. The Company obtained a reserve report dated December 2009, showing total estimated net proved reserve estimates of approximately 287 Mmcfe for the Cochran #1 Well. All revenues for the years ended March 31, 2011 and 2010 are from the Cochran Well.

Based on the increasing costs in production on the well, we have estimated impairment on the Cochran #1 Well to be approximately $216,000 as of March 31, 2011. In addition, leases on additional acreage in the Greater Garwood Project with possible reserves expired before the year ended March 31, 2011. As such, the Company has incurred approximately $370,000 related to impairment on the expired leases. Total impairment charges of approximately $586,000 are included in the Consolidated Statement of Operations for the year ended March 31, 2011.

Exploratory Wells

Oklahoma Project

In July of 2010, Imperial Oil entered into a participation agreement in an area of mutual interest (AMI) agreement and joint operating agreement to acquire a 50% working interest in leases on up to 5,000 acres in Oklahoma, including a 50% working interest in horizontal oil and gas drilling projects. As of March 31, 2011, there were no costs incurred. Subsequent to year-end March 31, 2011, the Company has participated in $82,127 of acreage costs and associated expenses. Total estimated acreage costs related to the project are $398,750. All leases are required to provide a gross net royalty interest of 79.25% or greater. At the Company’s option they may elect to participate in drilling and completion costs.

Nunnelly #1 Project

On January 10, 2011, the Company entered into an Oil and Gas lease (“Agreement”) with the mineral owner of approximately 35 acres and an existing wellbore in Montague County Texas. The Agreement provides for the development of the Project lease area and the existing well, known as Nunnelly #1. The mineral owners’ will retain a 25% royalty interest in the acreage. The Company obtained an evaluation from an independent registered petroleum engineer indicating net probable recoverable oil reserves of approximately 17 Mbbls. Deepening of the existing Nunnelly #1 wellbore is the Company’s first planned option. As of March 31, 2011, $19,760 was capitalized, relating to surface preparation work at the site.

Stateline

On January 25, 2011, the Company entered into a Farmout Agreement ("Agreement") with a private oil and gas exploration company, for the right to earn acreage by drilling up to four wells in an infill development project ("Stateline") in the existing Sawyer Field, in Lea County, New Mexico. The Agreement calls for drilling between one and four wells to earn a 77% net revenue interests in 40 acres for each well drilled, subject to a reservation by the assigning party of a 10% working interest in each well drilled. As of March 31, 2011, the Company has invested $60,000 related to the spud fee. The Company conducted an internal Reserve Evaluation and believes estimated net proved undeveloped reserves of approximately 41 Mbbl of oil. The Company’s capital expense for the first well is expected to be around $635,000. Over the 4 wells it is estimated that total probable reserves will be in excess of 250 Mbbls of oil.

Salt Water Disposal Facility

Subsequent to March 31, 2011, Imperial Oil entered into a Purchase and Sale Agreement to purchase approximately 41 acres of land, a related salt water disposal facility (”SWDF”) consisting of surface equipment, and a wellbore and associated permits, located in Wise County, Texas. The total purchase price of $500,000 was made through a $50,000 signing payment, plus the execution of a Convertible Promissory Note (the “Note”) totaling $450,000. The Note is secured over the SWDF assets.

Comparison of Fiscal Years Ended March 31, 2011 and March 31, 2010:

The Cochran #1 well produced and sold approximately 22 Mmcfe, net during the twelve months ended March 31, 2011, and 6 Mmcfe net to Imperial for the three months ended March 31, 2010 (from acquisition date). All revenues for the years ended March 31, 2011 and 2010, are from the Cochran Well. The lease is also subject to a 25% freehold royalty. The Cochran #1 Well has a net book value of $242,366 as of the year ended March 31, 2011. Depletion expense totaled $69,612 for the twelve months ended March 31, 2011, plus an impairment of $216,439 of which both amounts are included in our Consolidated Statement of Operations.

Total revenue for the fiscal year ended March 31, 2011 increased to $117,484 from $29,724 for the fiscal year ended March 31, 2010, due to revenues from four quarters of operations in 2011, versus one quarter of operations from acquisition date of January 19, 2010 to March 31, 2010. Likewise, lease operating expenses for the fiscal year ended March 31, 2011 were $73,435 for four quarters of operations compared to operations from acquisition date January 29, 2010 to March 31, 2010 of $13,620. Total lease operating expenses for the year ended March 31, 2011, included approximately $58,000 related to repairs to the well.

The production information on the Cochran #1 Well is as follows:

		March 31, 2011	March 31, 2010
Production operations:
Natural gas (Mcf)		21,639	6,327
Crude oil and condensate (Mbbls)		.37	.10
Produced Sales Price:(1)	$	$	$
Natural gas ($/Mcf)		4.07	5.35
Crude oil and condensate ($/Bbl)		80.07	77.21
Production Costs ($/Mcfe)(2)		2.89	1.97

The leases on additional acreage in the Greater Garwood project with possible reserves expired before the year ended March 31, 2011. As such, the Company has incurred $370,295 related to impairment on the expired leases, and has included the impairment charge in the Consolidated Statement of Operations for the year ended March 31, 2011.

The Greater Garwood project was acquired from the issuance of a $900,000 note payable. On December 10, 2010, the note payable of $900,000 plus $42,534 in accrued interest, was converted to 1,625,059 shares of the Company’s common stock at $0.58 per share. The fair value of the shares on the date of exchange was $1,218,794, resulting in a loss on debt extinguishment of $276,260, which is included in other expenses in the Statement of Operations for the year ended March 31, 2011.

Administrative expenses increased from approximately $29,000 as of March 31, 2010, to approximately $188,000 for the year ended March 31, 2011, for a total of $159,000 due to the following in approximation:

Accounting and Audit expenses	$	20,000
Directors and Officer Liability insurance	$	17,000
Directors Fees	$	27,000
Professional Fees	$	18,000
Legal Fees	$	46,000
Other administrative expenses	$	31,000

The Company was formerly considered in the Exploration stage for the year ended March 31, 2010, and has acquired several additional oil and gas properties for the year ended March 31, 2011. As such, professional fees and other operating expenses have increased during the current period.

Period from inception, August 2, 2007, to March 31, 2010

We have an accumulated deficit during the exploration stage of $124,091.

Liquidity and Capital Resources

We reported total current assets of $393,394 on March 31, 2011, consisting of $364,891 in cash, $28,503 of accounts receivable and $322,126 in an oil and gas properties. Current liabilities of $82,697 relate to vendor payables. Stockholders deficiency of $44,467 at March 31, 2010, became positive equity of $632,823 at March 31, 2011, as result of the conversion of the note payable on the Greater Garwood Project, and the issuance of shares for our capital raise of $500,000.

As of March 31, 2011, we had cash of approximately $365,000. We had net operating losses of $1,049,306 for the fiscal year ended March 31, 2011, which related primarily from the loss on the conversion of the note payable to common stock on the Greater Garwood Project of $276,260; impairment on the Greater Garwood expired leases of $370,295 and impairment on the Cochran #1 Well for $216,439.

For the fiscal year ended March 31, 2011 and 2010, we used $55,349 and $10,454, respectively, in cash for operating activities. For the same periods we used $79,760 and $900,000, respectively in cash for oil and gas properties. We raised $500,000 in capital from the issuance of shares for the period ended March 31, 2011. During the fiscal year ended March 31, 2011 and 2010, we had cash of $364,891and $0, respectively.

We continue to operate with very limited administrative support, and our current officers and directors continue to be responsible for many duties to preserve our working capital.

The note is repayable monthly at $9,529.59 for fifty-four months at a 6% fixed interest rate, commencing on June 1, 2011. The outstanding principal balance plus any accrued interest under the Note is convertible into common shares six months after execution of the agreement upon the option of the Holder. The Note is convertible into the number of shares equal to the balance of the principal and interest being converted divided by a 15% discount to the daily volume weighted average price per share for the ten business days prior to the date of the conversion notice.

On June 17, 2011, the Green Tide Water Disposal, Ltd., a wholly owned subsidiary of the Imperial Oil (“Green Tide”), signed a Convertible Promissory Note in the amount of $1,200,000.00 payable to Quarry Bay Capital, LLC for Green Tide to rework and operate the SWDF.

The note provides that Green Tide will pay interest at a rate of twenty percent per annum with principal and interest paid monthly in amounts equal to eighty percent of the net cash flow generated by the operations of the SWDF. The lender may convert at its option, the unpaid balance of the note into limited partner interests in Green Tide of up to 50% of the equity.

Imperial Oil plans to use the funds from the loan to deepen the well to a depth currently approved by the Texas Railroad Commission, service amortization payments on the Legion Note, conduct initial marketing operations and to reopen the Facility to dispose of up to 15,000 barrels of salt water a day. Disposal rates in the area range from approximately $0.40 to $0.60 per barrel of water, even at less attractive, generally more distant facilities. In addition to disposal revenues the Company expects to benefit from materially additional revenues generated by the Facility from the recovery and re-sale of oil contained in frac water. Facility operating costs are expected at around $30,000 per month, resulting in an estimated operating break-even point of only 2,225 barrels of water per day, even assuming low end $0.45 per barrel disposal rates and excluding any recovered oil revenues.

On July 8, 2011 Imperial Resources, Inc., pursuant to the Securities Purchase Agreement with an accredited investor dated December 31, 2010, entered into a second Securities Purchase Agreement the accredited investor, it subscribing $150,000 for 532,461 shares of common stock at a 10% discount to the Volume Weighted Average closing Price for the ten business days prior to the Agreement, this being a price of $0.2817 per share, as mutually agreed between the Company and the accredited investor. Following the issuance the total number of issued shares of the Company’s common stock will be 42,894,561.

During the year ended March 31, 2011, we have incurred expenses related to the acquisition of additional leases and acreage for development. We funded our operations from equity and debt financing and from our oil and gas revenues. We plan to continue to seek financings, and we believe that this will provide sufficient working capital to fund our operations for at least the next twelve months. This and other exploration activities, increased expenses, additional acquisitions, or other events, may require us to raise a significant amount of capital through equity or debt financings. There can be no assurance that we will be successful in raising additional funds and, if unsuccessful, our plans for expanding operations and business activities may have to be curtailed. Any attempt to raise funds, through debt or equity financing, would likely result in dilution to existing stockholders.

Off-Balance Sheet Arrangements

Stateline

Recent pronouncements

In January 2010, the FASB issued Accounting Standard Update (“ASU”) 2010-6, Improving Disclosures About Fair Value Measurements, which requires reporting entities to make new disclosures about recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair-value measurements and information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair-value measurements. ASU 2010-6 is effective for annual reporting periods beginning after December 15, 2009, except for Level 3 reconciliation disclosures which are effective for annual periods beginning after December 15, 2010. The adoption of ASU 2010-6 did not have a material impact on our consolidated financial statement disclosures.

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions included changes to the pricing used to estimate reserves utilizing a 12-month average price rather than a single day spot price which eliminates the ability to utilize subsequent prices to the end of a reporting period, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, and permitting disclosure of probable and possible reserves. The SEC required companies to comply with the amended disclosure requirements for annual reports on Form 10-K for fiscal years ending on or after December 15, 2009. Earlier adoption was not permitted.

In January 2010, the FASB issued ASC Topic No. 932 to amend existing oil and gas reserve accounting and disclosure guidance (formerly FASB Staff Position No. 69), Extractive Activities-Oil and Gas, to align its requirements with the SEC’s Modernization of Oil and Gas Reporting rule. The significant revisions involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve-month arithmetic average of the first day of the month prices and additional disclosure requirements. In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. The amendments are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments. Application of the amended guidance has only resulted in changes to the prices used to determine proved reserves at December 31, 2010 and 2009, respectively. The new guidelines have expanded the definition of proved undeveloped reserves that can be recorded from an economic producer. The opportunity to prove reasonable certainty for spacing areas located more than one direct development spacing area from economic producer did not impact the Company’s proved developed or undeveloped reserves.

The primary changes in the amended ASC Topic No. 932 are as follows:

●	Amending the definition of proved oil and gas reserves to indicate that entities must use the average, first-day-of-the-month price during the 12-month period before the ending date of the period covered by the report (the 12-month average price) rather than the year-end price, when estimating whether reserve quantities are economical to produce.
●	Change the price used to calculate the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future cash flows from the year-end price to the 12-month average price used in calculating proved reserves.
●	Adding to and amending other definitions in the Master Glossary used in estimating proved oil and gas reserves quantities (for example, reliable technology and reasonable certainty).
●	Requiring that an entity disclose separately information about reserve quantities and financial statement amounts for geographic areas that represent 15 percent or more of proved reserves. In addition, Topic No. 932 is amended to indicate that the quantity of reserves is not the only factor that should be considered in determining whether reserves are significant (that is, an entity would be required to consider all facts and circumstances in determining whether reserves are significant).
●	Clarifying that an entity’s equity method investments must be considered in determining whether it has significant oil- and gas producing activities.

Critical Accounting Policies

Use of Estimates in the Preparation of Consolidated Financial Statements

Preparation of the accompanying 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. The oil and natural gas reserve estimates, and the related future net cash flows derived from those reserves, are used in the determination of depletion expense and the full cost ceiling test and are inherently imprecise. Actual results could differ from those estimates.

Property and Equipment:

Oil and natural gas properties:

The Company follows the successful efforts method of accounting and will capitalize successful wells and related leasehold costs. Acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole costs are expensed. Development costs, including costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves are capitalized.

These costs are amortized using the unit of production method. Dry hole and related leasehold costs are expensed. On March 31, 2011, the Company had a 14.9% working interest in one producing gas well.

Impairment of Long-Lived Assets:

The Company reviews and evaluates long-term assets for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. The assets are subject to impairment consideration under ASC 60-10-35-17 if events or circumstances indicate that their carrying amount might not be recoverable. When the Company determines that an impairment analysis should be done, the analysis will be performed using the rules of ASC 930-360-35 Asset Impairment, and 360-10-15-3 through 15-5, Impairment or Disposal of Long-Term Assets.

Basic and Diluted Net Loss Per Share

Net loss per share is presented in accordance FASB ASC Topic No. 260 (formerly SFAS No. 128) Earnings Per Share. Basic net loss per share is computed based on the weighted average shares of common stock outstanding for the period. Common stock equivalents which represent stock options have been excluded from the computation of diluted net loss per share at March 31, 2011 and 201 as their effect is anti-dilutive

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Not applicable.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Reference is made to the financial statements, the reports of our independent registered public accounting firm, and the notes thereto of this report, which financial statements, reports, and notes are incorporated herein by reference.

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

a) On January 27, 2011, Imperial Resources, Inc. (“Imperial or the Company”) was notified by the SEC that the Public Accounting Oversight Board (“PCAOB”) had revoked the registration of J. Crane CPA, P.C. (“J. Crane”) on January 19, 2011. J. Crane was the Company’s former independent registered public accounting firm for the year ended March 31, 2009.

On June 17, 2009, J. Crane was dismissed as the Company’s Independent Auditor.

Between August 2, 2007, (the date of engagement) and June 17, 2009 (the date of resignation) there were no disagreements with J. Crane on any matter of accounting principles or practices, financial statement disclosure, or auditing procedure, other than an audit scope modification due to Company’s uncertainty regarding its ability to continue as a going concern for the period from August 7, 2007 to March 31, 2008, and for the year ended March 31, 2009.

The Company furnished J. Crane with a copy of this disclosure at the last known address of 47 Third Street, Suite 301, Cambridge Massachusetts, 02141. Taking into account the detail of the revocation of J. Crane’s registration order dated January 19, 2011 issued by the PCAOB, which states that J. Crane prevented PCAOB inspections and failed to provide inspection materials to the PCAOB during 2009 and 2010, and based on the fact that the Company is unable to contact J. Crane, we do not anticipate receipt of a response from J. Crane.

b) On June 17, 2009, upon the authorization and approval of the board of directors, the Company engaged Madsen & Associates, CPA’s INC., Certified Public Accountant (“Madsen”) as its independent registered public accounting firm.

No consultations occurred between the Company and Madsen during the period from inception August 2, 2007 through June 17, 2009, regarding either (i) the application of accounting principles to a specific completed or contemplated transaction, the type of audit opinion that might be rendered on the Company’s financial statements, or other information provided that was an important factor considered by the Company in reaching a decision as to an accounting, auditing, or financial reporting issue, or (ii) any matter that was the subject of disagreement requiring disclosure under Item 304(a)(1)(iv) of Regulation S-K or reportable event requiring disclosure under Item 304(a)(1)(v) of Regulation S-K.

While the Company’s current independent registered public accounting firm issued a report dated June 25, 2010, with regards to the Consolidated Balance Sheets of Imperial Resources, Inc. and subsidiary (Exploration stage company) at March 31, 2010, and the related Consolidated Statements of operations, changes in stockholders' equity, and cash flows for the year then ended, and for period from August 2, 2007 (date of inception) to March 31, 2010., they relied solely on the prior auditors report dated June 23, 2009, and their opinion insofar as it related to the amounts included in the financial statements of Imperial Resources, Inc. at March 31, 2009, and for the year then ended was based solely on the report of the other auditors.

The Company engaged its current independent auditors to perform the work necessary to express an opinion on both the Consolidated Balance Sheets of Imperial Resources, Inc. and subsidiary (Exploration stage company) at March 31, 2010 and 2009, and the related Consolidated Statements of operations, changes in stockholders' equity, and cash flows for the years then ended and for period from August 2, 2007 (date of inception) to March 31, 2010.

The Company filed a 10-K/A on May 17, 2011, which reflected a new report by our current independent auditors. The previous report issued by other auditors was unqualified with an explanatory paragraph due to the Company’s uncertainty regarding its ability to continue as a going concern. The new report issued herein is also unqualified with and an explanatory paragraph due to the Company’s uncertainty regarding its ability to continue as a going concern.

The amounts previously presented in the Consolidated Balance Sheets at March 31, 2010 and 2009, and the related Consolidated Statements of operations, changes in stockholders' equity, and cash flows for the year ended March 31, 2010 and 2009, and for the period from August 2, 2007 (date of inception) to March 31, 2010, did not change from amounts previously presented, with the following exceptions:

-	We adjusted stockholders’ equity to not give retroactive effect to share cancellations. Retroactive effect is only being given for the November 3, 2009 stock dividend.
-	We reclassified exploration costs to impairment loss on mineral claim to follow our related accounting policy whereby we capitalize mineral claim acquisition costs, and subsequently assess these costs for impairment.

-	Related to the reclassification adjustment described above, we adjusted our cash flows statement to show the impairment loss in the operating activities section, with the acquisition costs being shown in the investing section.
-	We updated Footnote 2 for recent accounting pronouncements.

-	We have updated the footnotes to replace FASB references with the related codification references.

ITEM 9A(T). – CONTROLS AND PROCEDURES

At the end of the period covered by this report, an evaluation was carried out under the supervision of and with the participation of our management, including the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), of the effectiveness of the design and operations of our disclosure controls and procedures (as defined in Rule 13a - 15(e) and Rule 15d - 15(e) under the Exchange Act). Based on that evaluation the CEO and the CFO have concluded that as of the end of the period covered by this report, our disclosure controls and procedures were not adequately designed and were not effective in ensuring that: (i) information required to be disclosed by us in reports that we file or submit to the Securities and Exchange Commission under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in applicable rules and forms and (ii) material information required to be disclosed in our reports filed under the Exchange Act is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow for accurate and timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, in accordance with Rules 13a-15 and 15d-15 of the Exchange Act. Under the supervision and with the participation of our management, we, in conjunction with an independent third party, conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework set forth by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission in Internal Control — Integrated Framework.

Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America. Internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our internal control over financial reporting as of March 31, 2011. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework. Based on this evaluation and those criteria, our management, with the participation of our Chief Executive Officer and Chief Financial Officer, concluded that, as of March 31, 2011 our internal control over financial reporting was not effective.

Our management has identified a deficiency that constitutes a material weakness in our technical accounting expertise necessary for an effective system of internal control and timely financial reporting. In an effort to mitigate these material weaknesses, our management has hired additional staff with accounting technical expertise. At any time, if it appears that any control can be implemented to continue to mitigate such control deficiencies in a cost effective manner, we will attempt to implement the control.

This Form 10-K does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting pursuant to rules of the SEC that permit the Company to provide only management’s report in this Form 10-K.

This report shall not be deemed to be filed for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, and it is not incorporated by reference into any of our filings, whether made before or after the date hereof, regardless of any general incorporation language in such filings.

Changes In Internal Control Over Financial Reporting

We have implemented additional controls and procedures designed to ensure that the disclosure provided by us meets the then current requirements of the applicable filing made under the Exchange Act. To address our lack of sufficient accounting technical expertise, during the fourth quarter ended March 31, 2011, we retained additional accounting technical expertise. Other than these there have been no changes in our internal control over financial reporting during the fourth quarter ended March 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B – OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Each of our directors serves until his or her successor is elected and qualified. Each of our officers is elected by the Board of Directors to a term of one (1) year and serves until his or her successor is duly elected and qualified, or until he or she is removed from office. The Board of Director has no nominating or compensation committees.

The ages of the directors, executive officers and key employees are shown as of March 31, 2011.

Name and Address	Position(s)	Age

Rob Durbin(1)	Director, Chief Executive Officer and President	54

Mike Mackey(2)	Chief Financial Officer	54

Tom Barr (3)	Director	51

(1) Rob Durbin was appointed a director, Chief Executive Officer and President on December 10, 2010.

(2) On March 3, 2011, Imperial Resources, Inc. appointed Michael Mackey as its CFO.

(3) Tom Barr was appointed as director on December 21, 2010 pursuant to its powers under the Company’s bylaws to fill vacant seats on the Board.

Background of Officers and Directors

Mr. Durbin has been the director and the Chief Executive Officer of the wholly owned subsidiary of the company, Imperial Oil & Gas Inc., a Delaware company, since April 2010. Mr. Durbin is an attorney who practices exclusively in the areas of oil and gas. From 2003 to the present he has acted as counsel through his firm to several oil and gas exploration and production companies and related service companies. From 2002 to 2003 he was General Counsel and Vice President of Star of Texas Energy Services, Inc. From 1987 to 2002 Mr. Durbin practiced at his own firm primarily in the areas of oil and gas and civil litigation. From 1998 to 2002 he was Adjunct Professor, at the Southwestern Professional Institute. From 1979 to 1986 he was regional manager at APL Services, Inc.

Mr. Mackey has been an Associate with vcfo since the fall of 2008. Since joining vcfo, he has provided numerous clients with Chief Financial Officer level support and guidance. Previously, Mr. Mackey was with Ascent Synergy Solutions as the Principal and Founder. His consulting firm focused on companies, typically in the technology, services or consulting markets, needing guidance and assistance at both a strategic and tactical level to realize their strategy and projections. Prior to Ascent Synergy Solutions, Mr. Mackey was the President, COO and one of the Founders of Empyrean Benefit Solutions. He was responsible for recruiting a high caliber management team to assist in the formation of the company that included designing and implementing the operational, accounting and administrative infrastructure. Prior to Empyrean Benefit Solutions, Mr. Mackey was the CFO and EVP Finance & Administration for Synhrgy HR Technologies and FastWeb.com. Prior to FastWeb.com, Mr. Mackey was the CFO, EVP Finance & Administration for DA Consulting Group. He played a critical role in evaluation and selection of underwriters, drafting of prospectus, strenuous international road show and successful $34.5 million Initial Public Offering. Prior to DA Consulting Group, he was the CFO, EVP Finance & Administration for Global Software and was instrumental in a complex spin-off from a publicly traded company. Mr. Mackey has also worked for MicroAge Computer as CFO, Kirchman Corporation as a Lead Financial Analyst, PricewaterhouseCoopers as an Auditor and Lockheed Martin as a Lead Financial Analyst. Mr. Mackey received his BS in Accounting from the University of Florida, Gainesville, and his MS in Accounting & MBA from the University of Central Florida, Orlando.

Mr. Barr, age 51, has served as a director of Bio-AMD, Inc. (f/k/a Flex Fuels Energy, Inc.) a Nevada corporation since December 2006 and as Chief Executive Officer of that company since December 2008. From January 2005 to April 2007, Mr. Barr acted as a corporate consultant to various small and medium sized private and public enterprises. From 2001 to 2004 Mr. Barr served as a consultant to EasyScreen PLC, a fully listed London Stock Exchange company. From 1996 to 2001 Mr. Barr was a private analyst and investor in publicly quoted stocks. From 1981 to 1996, Mr. Barr worked in the North Sea as a professional saturation diver in the Oil and Gas industry. Mr. Barr obtained a BSc from Stirling University, Scotland, in 1981. Mr. Barr is a citizen of the United Kingdom.

Relationships between Directors and Officers

None of our executive officers or directors or key employees is related by blood, marriage or adoption to any other director or executive officer.

Arrangements between Directors and Officers

Mr. Durbin has a 15% interest in Mara which has a Consulting Services Agreement with Imperial Oil and Gas, Inc., the Company’s main operating subsidiary. At March 31, 2011 no consulting fees have been paid to Mara.

On April 1, 2010, Imperial Oil entered into an Assignment of Overriding Royalty Interest Agreement to assign or pay Sydney Oil & Gas, LLC a gross overriding royalty of 6.5% of 8/8 for each lease or working interest acquired by Imperial Oil. Rob Durbin owns an interest in and controls Sydney. At March 31, 2011 no royalties have been paid to Sydney.

Mr. Barr has a 10.8% interest in Mara Energy, LLC, a Delaware corporation which has a Consulting Services Agreement with Imperial Oil and Gas, Inc., the Company’s main operating subsidiary.

Compliance with Section 16(a) of the Securities Exchange Act of 1934

Based solely upon a review of Forms 3, 4 and 5 delivered to us as filed with the Securities Exchange Commission, our executive officers and directors, and persons who own more than 10% of our Common Stock timely filed all required reports pursuant to Section 16(a) of the Securities Exchange Act.

Code of Ethics

We have adopted a Code of Business Ethics and Control for the Board of Directors applicable to our principal executive officer and principal financial officer in their role as directors. Given the overlap between our executive officers and directors, we have not thought it necessary to adopt a separate Code of Ethics for our executive officers. A copy of the Code of Business Ethics and Control for the Board of Directors may be obtained free of charge, upon written request to the Company.

ITEM 11. EXECUTIVE COMPENSATION

To date we have no employees other than our officers. No compensation has been awarded, earned or paid to our officers.

As of March 31, 2011, we have no standard arrangement to compensate directors for their services in their capacity as directors. Directors are not paid for meetings attended. All travel and lodging expenses associated with corporate matters are reimbursed by us, if and when incurred.

Board Compensation

In January, 2011, our Board of Directors approved a compensation plan pursuant to which Rob Durbin would receive the following compensation:

●

Monthly director fees of $9,000;

●

reimbursement of expenses related to service in the capacity of a member of the Board.

Mr. Durbin will not be employed pursuant to a written agreement by the Company. Subsequent to board approval he will be paid a fee of not less than $8,500 per month and provided with employee benefits for health and other typical benefits of an executive officer up to an annual dollar cost to the Company of $10,000. This compensation is in addition to any of the compensation that Mr. Durbin is already entitled to as the operating officer of Imperial Oil & Gas Inc. The salary and other amounts may be paid either by the Company or Imperial Oil & Gas Inc. on behalf of the Company. Mr. Durbin will also be provided with director and officer insurance coverage, as determined by and available to the Company and will be provided an indemnification agreement, in a form to be negotiated, which will provide for the fullest protection and indemnification rights that are available under Nevada law.

Mr. Barr will not be initially employed pursuant to a written agreement by the Company and will work on a part time basis. The Company intends to reach an agreement with Mr. Barr for a remuneration package in 2011. Mr. Barr is also intended to be provided with director and officer insurance coverage, as determined by and available to the Company and will be provided an indemnification agreement, in a form to be negotiated, which will provide for the fullest protection and indemnification rights that are available under Nevada law.

On March 3, 2011, the Company’s Board of Directors ratified the January 19, 2011 letter agreement between Imperial Resources Inc. (the “Company”) and virtualcfo, Inc. (d/b/a/ vcfo), engaging the services of vcfo to provide oversight and guidance to the finance and accounting team. Under the Agreement, Mike Mackey, a CFO at vcfo, will be assigned to the Company as CFO for the Company, including assisting the Company with operational and public reporting requirements, oversight and guidance of finance and accounting matters, and such other assistance as needed by the Company’s finance and accounting team.

The Agreement provides that the Company will pay a $7,500 retainer to vcfo, and consulting fees will be incurred on an hourly basis and billed weekly. Mike Mackey’s services will be billed at $175 per hour. The Company has also agreed to pay certain expenses incurred by vcfo in providing the contracted services.

The Company has agreed to add vcfo employees to its Directors and Officers Insurance policy. The Company has also agreed to indemnify and hold harmless vcfo and its officers, directors, employees, agents and successors and assigns against any and all demands, claims, causes of actions, damages, costs, expenses, penalties, losses and liabilities arising from the services for which vcfo has been engaged. The parties also signed a Mutual Confidentiality Agreement.

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

As of March 31, 2011 there were no shares owned beneficially by each of our directors, officers and key employees, individually and as a group. There is one present owner of 5% or more of our total outstanding shares. Share ownership is deemed to include all shares that may be acquired through the exercise or conversion of any other security immediately or within sixty days of June 29, 2011. Such shares that may be so acquired are also deemed outstanding for purposes of calculating the percentage of ownership for that individual or any group of which that individual is a member. Unless otherwise indicated, the stockholders listed possess sole voting and investment power with respect to the shares shown.

Title of Class	Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership	Percent of Class
Common Stock	ANIL APPUKUTTAN KARIMBANAYCHAL HOUSE POOMANGALAM, INDIA 6806888	2,475,000	6	%
Common Stock	Directors and Executive Officers as a Group (3 persons)	0	0	%

Equity Compensation Plan Information

We have no active equity compensation plans and there are currently no outstanding options from prior plans.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Transactions with Related Persons

Current officers-directors and their families have no shares in the Company, and have made no advances to the Company as of March 31, 2011. Prior officers have made contributions to capital totaling $7,800 in the form of expenses paid on behalf of the Company for the year ended March 31, 2011.

Mr. Robert Durbin, Imperial Oil’s Chief Executive Officer and Chairman of the Board, owns a 15% interest in Mara. For the year ended March 31, 2011 there were no payments made in connection with the Mara agreement.

Mr. Tom Barr, a director of Imperial owns a 10.8% interest in Mara. For the year ended March 31, 2011 there were no payments made in connection with the Mara agreement.

On April 1, 2010, Imperial Oil entered into an Assignment of Overriding Royalty Interest Agreement whereby Imperial Oil agrees to pay Sydney Oil & Gas, LLC, a Texas limited liability company controlled by Mr. Robert Durbin, a gross overriding royalty of 6.5% of 8/8 for each lease or working interest acquired by Imperial Oil. Mr. Durbin owns an interest in and controls Sydney Oil & Gas, LLC. At March 31, 2011 no royalties have been paid or assigned.

Effective April 1, 2010, Grant Twanow resigned as Director, Chief Executive Officer, President, and all other officer roles of Imperial Oil. In connection with such resignation, Imperial Oil and GNP Resources, Ltd., a company wholly-owned by Mr. Twanow (“GNP”), entered into a Royalty Termination Agreement, whereby the parties agreed to terminate a Royalty Agreement between the parties, whereby Imperial Oil agreed to pay GNP a gross overriding royalty of 5% in any lands acquired by Imperial Oil in Prospects procured by GNP or Mr. Twanow. Additionally, the parties mutually agreed to terminate a Supply of Services Agreement between Imperial Oil, GNP, and Mr. Twanow, whereby Mr. Twanow acting on behalf of GNP provided services to Imperial Oil related to the maintenance and development of Imperial Oil’s oil and gas exploration and development interests. There were no payments made under any of the agreements.

Effective April 1, 2010, Neil McPherson resigned as a director of Imperial Oil. In connection with such resignation, Imperial Oil and Little Eagle Resources Inc., a company wholly-owned by Mr. McPherson (“Little Eagle”), entered into a Royalty Termination Agreement, whereby the parties agreed to terminate a Royalty Agreement between the parties, whereby Imperial Oil agreed to pay Little Eagle a gross overriding royalty of 1.5% in any lands acquired by Imperial Oil in the North West Premont Prospect and the Ricinus Area Prospect procured by Little Eagle or Mr. McPherson. Additionally, the parties mutually agreed to terminate a Supply of Services Agreement between Imperial Oil, Little Eagle, and Mr. McPherson, whereby Mr. McPherson acting on behalf of Little Eagle provided services to Imperial Oil related to the maintenance and development of Imperial Oil’s oil and gas exploration and development interests. There were no payments made under any of the agreements.

Transactions with Promoters

We have not engaged any promoters and have not had any transactions with any promoters.

Director Independence

During the past fiscal year we did not have any independent directors on our board. We evaluate independence by the standards for director independence established by applicable laws, rules, and listing standards including, without limitation, the standards for independent directors established by The New York Stock Exchange, Inc., The NASDAQ National Market, and the Securities and Exchange Commission.

Subject to some exceptions, these standards generally provide that a director will not be independent if (a) the director is, or in the past three years has been, an employee of ours; (b) a member of the director’s immediate family is, or in the past three years has been, an executive officer of ours; (c) the director or a member of the director’s immediate family has received more than $120,000 per year in direct compensation from us other than for service as a director (or for a family member, as a non-executive employee); (d) the director or a member of the director’s immediate family is, or in the past three years has been, employed in a professional capacity by our independent public accountants, or has worked for such firm in any capacity on our audit; (e) the director or a member of the director’s immediate family is, or in the past three years has been, employed as an executive officer of a company where one of our executive officers serves on the compensation committee; or (f) the director or a member of the director’s immediate family is an executive officer of a company that makes payments to, or receives payments from, us in an amount which, in any twelve-month period during the past three years, exceeds the greater of $1,000,000 or two percent of that other company’s consolidated gross revenues.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

The aggregate fees billed by the Company’s independent registered public accounting firm for professional services rendered in connection with the audit of the Company’s annual consolidated financial statements for the twelve months ended March 31, 2011 and 2010 and reviews of the consolidated financial statements included in the Company’s Forms 10-K and 10-Q for 2011 and 2010 were approximately $13,500 and $4,750, respectively.

Audit-Related Fees

The aggregate fees billed by the Company’s independent registered public accounting firm for any additional fees for assurance and related services that are reasonably related to the performance of the audit or review of the Company’s financial statements and are not reported under “Audit Fees” above for 2011 were $3,150.

Tax Fees

The aggregate fees billed by the Company’s independent registered public accounting firm for professional services for tax compliance, tax advice, and tax planning for 2011 and 2010 were approximately $5,000 and $0, respectively.

All Other Fees

The aggregate fees billed by the Company’s independent registered public accounting firm for all other non-audit services rendered to the Company, such as attending meetings and other miscellaneous financial consulting, for 2010 and 2009 were $0.

PART IV

ITEM 15. EXHIBITS , FINANCIAL STATEMENTS SCHEDULES

(a) (1) Financial Statements. The following financial statements are included in this report:

Title of Document		Page

Report of Madsen & Associates CPA’s Inc.		32

Consolidated Balance Sheet as at March 31, 2011 and 2010		33

Consolidated Statement of Operations for the years ended March 31, 2011 and 2010		34

Consolidated Statement of Changes in Stockholders’ Equity (Deficiency) for the years ended March 31, 2011 and 2010		35

Consolidated Statement of Cash Flows for the years ended March 31, 2011 and 2010		36

Notes to Consolidated Financial Statements		37 to 47

(a) (2) Financial Statement Schedules

The following financial statement schedules are included as part of this report: None.

(a) (3) Exhibits-The following exhibits are included or are included as part of this report by reference:

Exhibit Number	Name
3.1(1)	Certificate of Incorporation
3.2(1)	Articles of Incorporation
3.3(1)	By-laws
3.4	Certificate of filing of Green Tide Water Disposal Ltd., dated June 15, 2011

10.1(7)	Cochran #1 Well and Greater Garwood Prospect Reservoir Evaluation, dated December 22, 2009.
10.2(2)	Carry Agreement, dated October 27, 2009, between Baytor Energy LLC and Coach Capital, LLC
10.3(3)	Net Profits Agreement, dated January 19, 2010, between Mara Energy, LLC and Imperial Oil and Gas, Inc.
10.4(4)	Supply of Services Agreement, dated April 1, 2010, between Sydney Oil & Gass, LLC, Robert R. Durbin and Imperial Oil and Gas, Inc.
10.5(4)	Consulting Services Agreement, dated April 1, 2010, between Mara Energy, LLC and Imperial Oil and Gas, Inc.
10.6	Nunnelly Farmout Agreement
10.7(6)	Note Conversion Agreement dated as of December 10, 2010, made by and among Imperial Oil and Gas, Inc.,, and Coach Capital, LLC
10.8(6)	Securities Purchase Agreement dated December 31, 2010, pursuant to a private offering of $500,000 worth of common stock
10.9	Stateline Letter of Agreement dated January 20, 2011
10.10	Convertible Promissory Note from Quarry Bay Capital, LLC, dated June 17, 2011
10.11(5)	Husky Letter Agreement dated July 10, 2011

21	List of Subsidiaries

31.1	Certification of Principal Executive Officer Pursuant to 18 U.S.C., Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Financial Officer Pursuant to 18 U.S.C., Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(1)	Incorporated by reference from our Registration Statement on Form S-1 filed on July 7, 2008.
(2)	Incorporated by reference to exhibits previously filed on our Current Report on Form 8-K filed on January 22, 2010.
(3)	Incorporated by reference to exhibits previously filed on our Current Report on Form 8-K filed on February 1, 2010.
(4)	Incorporated by reference to exhibits previously filed on our Current Report on Form 8-K filed on April 6, 2010.
(5)	Incorporated by reference to exhibits previously filed on our Current Report on Form 8-K filed on July 16, 2010.
(6)	Incorporated by reference to exhibits previously filed on our Quarterly Report on Form 10Q filed on February 18, 2011.
(7)	Incorporated by reference to exhibits previously filed on our Annual Report on Form 10K filed on July 9, 2010

SIGNATURES

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

IMPERIAL RESOURCES, INC.

(Registrant)

Dated: July 14, 2011	/s/ Rob Durbin
	By: Rob Durbin
	Its: President, Chief Executive Officer and Director (Principal Executive Officer)

Pursuant to requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:

Signature	Capacity	Date

/s/ Rob Durbin	President, Chief Executive Officer and Director	July 14, 2011
Rob Durbin	(Principal Executive Officer)

/s/ Mike Mackey	Chief Financial Officer	July 14, 2011
Mike Mackey	(Principal Financial Officer and Principal Accounting Officer)

/s/Tom Barr	Director	July 14, 2011
Tom Barr

MADSEN & ASSOCIATES CPA’s INC.	684 East Vine Street, #3
Certified Public Accountants	Murray, Utah, 84107
	Telephone 801-268-2632
	Fax 801-262-3978

To the Board of Directors and

Stockholders of Imperial Resources, Inc. and Subsidiary

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have audited the accompanying consolidated balance sheets of Imperial Resources, Inc. and Subsidiary (The Company) as of March 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity (deficiency), and cash flows for each of the years in the two-year period ended March 31, 2011. The Company’s management is responsible for these financial statements. Our responsibility is to express an opinion on these 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 financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purposes of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Imperial Resources, Inc. and Subsidiary as of March 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the years in the two-year period ended March 31, 2011, 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. The Company will need additional working capital to service its debt and for its planned activity, which raises substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are described in the notes to the financial statements. These financial statements do not include any adjustments that might result from the outcome of this uncertainty.

“Madsen & Associates, CPA’s Inc.”

Salt Lake City, Utah

July 14, 2011

IMPERIAL RESOURCES, INC. AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

	March 31, 2011		March 31, 2010

ASSETS
Cash	$	364,891	$	-
Accounts receivable		28,503		29,724
Total Current Assets		393,394		29,724

Oil and Gas Leases		322,126		898,712

TOTAL ASSETS	$	715,520	$	928,436


LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIENCY)

Accounts payable	$	82,697	$	41,563
Accounts payable – related parties		-		31,340
Total Current Liabilities		82,697		72,903


Note Payable	-	900,000

Total Liabilities	82,697	972,903

STOCKHOLDERS’ EQUITY (DEFICIENCY)
Common stock
500,000,000 shares authorized, at $0.001 par value;
42,362,100 shares issued and outstanding at March 31, 2011; 49,900,000 shares issued and outstanding at March 31, 2010		42,362			49,900
Capital in excess of par value		1,763,858			29,725
Accumulated Deficit		(1,173,397	)		(124,092	)
Total Stockholders’ Equity (Deficiency)		632,823			(44,467	)

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIENCY)	$	751,520		$	928,436

The accompanying notes are an integral part of these consolidated financial statements.

IMPERIAL RESOURCES, INC. AND SUBSIDIARY

CONSOLIDATED STATEMENT OF OPERATIONS

For the years ended March 31, 2011 and 2010

	Year ended March 31, 2011			Year ended March 31, 2010

Operating Revenue:
Natural Gas and condensate	$	117,484		$	29,724

Operating Expenses:
Lease operating costs		73,435			13,620
Depletion		69,612			1,288
Impairment of Oil & Gas Properties		586,734			-
Accounting and audit		30,873			10,400
Director’s Fees		27,000			-
Insurance		17,485			-
Professional Fees		16,699			-
Legal		46,094			-
Management fees		6,000			12,000
Travel and Entertainment		25,930			-
Other Administrative Expenses		17,617			6,276
Total Operating Expenses		917,479			28,676

LOSS FROM OPERATIONS		(799,995	)		(13,860	)

Other Income and (Expenses):
Gain on debt forgiveness from prior officers		60,699			-
Interest on promissory note		(33,750	)		(8,753	)
Loss on Debt Extinguishment		(276,260	)		-
Total Other Expenses		(249,311	)		(8,753	)

NET LOSS	$	(1,049,306	)	$	(22,613	)

NET LOSS PER COMMON SHARE
Basic and diluted	$	(0.03	)	$	(0.00	)
AVERAGE OUTSTANDING SHARES
Basic and diluted		40,803,297			49,900,000

The accompanying notes are an integral part of these consolidated financial statements.

IMPERIAL RESOURCES, INC. AND SUBSIDIARY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (DEFICIENCY)

For the years ended March 31, 2011 and 2010

	Common Shares			Stock Amount			Capital in Excess of Par Value			Accumulated Deficit			Total

Balance as of March 31, 2009		247,665,000		$	247,665		$	(183,640	)	$	(101,479	)	$	(37,454	)

Capital contributions – officer expenses		-			-			15,600			-			15,600
Cancellation of common shares – October 22, 2009		(168,300,000	)		(168,300	)		168,300			-			-
Stock dividend – 65:1 – November 3, 2009
Cancellation of common shares – January 27, 2010		(29,465,000	)		(29,465	)		29,465			-			-
Net loss for the year ended March 31, 2009		-			-			-			(22,613	)		(22,613	)

Balance as of March 31, 2010		49,900,000		$	49,900		$	29,725		$	(124,092	)	$	(44,467	)

Cancellation of common shares – April 29, 2010		(9,900,000	)		(9,900	)		9,900			-			-
Capital contributions-officer expenses		-			-			7,800			-			7,800
Note payable converted to 1,625,059 shares of common Stock		1,625,059			1,625			1,217,170			-			1,218,795
Shares of Common stock issued for cash		737,041			737			499,263						500,000
Net loss for the year ended March 31, 2011		-			-			-			(1,049,306	)		(1,049,306	)

Balance as of March 31, 2011		42,362,000		$	42,362		$	1,763,858		$	(1,173,398	)	$	632,823

The accompanying notes are an integral part of these consolidated financial statements

IMPERIAL RESOURCES, INC. AND SUBSIDIARY

CONSOLIDATED STATEMENT OF CASH FLOWS

For the years ended March 31, 2011 and 2010

	Year ended March 31, 2011			Year ended March 31, 2010

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,049,306	)	$	(22,613	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion expense		69,612			1,288
Impairment of oil and gas properties		586,734			-
Loss on note payable conversion to common stock		276,260			-
Gain on debt forgiveness		(60,699	)		-
Capital contributions – expenses		7,800			15,600
Changes in accounts receivable		1,222			(29,724	)
Changes in accounts payable		113,027			24,995

Net Cash Used in Operations		(55,349	)		(10,454	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of oil and gas lease		-			(900,000	)
Lease acquisition payments and exploration activities		(79,760	)		-
Net Cash used by Investing Activities		(79,760			(900,000	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from loan from related party		-			10,397
Note payable – purchase of oil and gal leases		-			900,000
Proceeds from issuance of common stock		500,000			-
Net Cash Provided by Financing Activities		500,000			910,397

Net Increase (Decrease) in Cash		364,891			(57	)
Cash at Beginning of Period		-			57
CASH AT END OF PERIOD	$	364,891		$	-

Supplemental disclosures:
Note payable of $900,000 plus accrued interest of $42,534 converted into 1,625,059 shares of common stock		1,218,795			-
Cash paid for interest		-			8,753

The accompanying notes are an integral part of these consolidated financial statements

IMPERIAL RESOURCES, INC. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2011 and 2010

1.	ORGANIZATAION AND BASIS OF PRESENTATION

Imperial Resources, Inc. (“the Company”) was incorporated under the laws of the State of Nevada on August 2, 2007 with the authorized capital stock of 500,000,000 shares at $0.001 par value.

The Company was organized for the purpose of acquiring and exploring a mineral property and later abandoned it. The Company has decided to focus its core activities on development and exploration of oil and gas assets in the United States through its wholly-owned subsidiary Imperial Oil & Gas Inc. (“Imperial Oil” or “IOG”) which was formed under the laws of the State of Delaware on January 8, 2010.

The Company is engaged in the exploration and development of oil and natural gas properties of others under arrangements in which we finance the costs in exchange for interests in the oil or natural gas revenue generated by the properties. Such arrangements are commonly referred to as farm-ins to us, or farm-outs by the property owners farming out to us.

2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial statements included herein, presented in accordance with accounting principles generally accepted in the United States of America and stated in US dollars, have been prepared by the Company, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”).

(a)	Basis of Consolidation

The accompanying financial statements present the consolidated accounts of the Company and its wholly owned subsidiary Imperial Oil. All intercompany account balances and transactions have been eliminated.

(b)	Nature of Operations

The Company’s focus is on the acquisition, development and exploitation of long-lived oil and natural gas reserves and, to a lesser extent, exploration for new oil and natural gas reserves. The Company’s business activities are currently carried out in New Mexico and Texas.

(c)	Concentration of Credit Risk

Financial instruments that potentially expose the Company to concentrations of credit risk consist primarily of unsecured accounts receivable from unaffiliated crude oil purchasers and the well operator. A substantial portion of the Company’s oil reserves are exposed to the impact of delays or interruptions of production from these wells due to mechanical problems, damages to the current producing reservoirs and significant governmental regulation, including any curtailment of production or interruption of transportation of oil or natural gas produced from the properties.

(d)	Property and Equipment

Oil and natural gas properties:

The costs are amortized using the unit of production method. Dry hole and related leasehold costs are expensed. On March 31, 2011, the Company had a 14.9% working interest in one producing gas well.

IMPERIAL RESOURCES, INC. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2011 and 2010

Other Property and Equipment:

Maintenance and repairs are charged to operations. Renewals and improvements are capitalized to the appropriate property and equipment accounts.

Upon retirement or disposition of assets other than oil and natural gas properties, the cost and related accumulated depreciation are removed from the accounts with the resulting gains or losses, if any, recognized in income. Depreciation of other property and equipment is computed using the straight-line method based on the estimated useful lives of the property and equipment.

(e)	Impairment of Long-Lived Assets:

Based on rising production costs the Company has evaluated the Cochran #1 Well, our only producing well, as of March 31, 2011. The Company has estimated $216,439 in impairment charges representing the excess of book value over undiscounted future net cash flows from the well as of March 31, 2011.

(f)	Income Taxes

The Company accounts for federal income taxes using the liability method. Under the liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Under the liability method, the effect on previously recorded deferred tax assets and liabilities resulting from a change in tax rates is recognized in operating results in the period in which the change is enacted.

(g)	Basic and Diluted Net Loss Per Share

Net loss per share is presented in accordance FASB ASC Topic No. 260 (formerly SFAS No. 128) Earnings Per Share. Basic net loss per share is computed based on the weighted average shares of common stock outstanding for the period. There are no potentially dilutive common stock equivalents such as stock options or warrants outstanding, and as such basic and diluted net loss per share is the same.

(h)	Use of Estimates in the Preparation of Consolidated Financial Statements

(i)	Fair value of financial instruments

The Company calculates the fair value of its assets and liabilities which qualify as financial instruments and includes this additional information in the notes to consolidated financial statements when the fair value is different than the carrying value of these financial instruments. The estimated fair value of accounts receivable, accounts payable and accrued liabilities approximate their carrying amounts due to the relatively short maturity of these instruments. None of these instruments are held for trading purposes.

ASC Topic 820, Fair Value Measurements and Disclosures, defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles, and requires certain disclosures about fair value measurements. In general, fair values of financial instruments are based upon quoted market prices, where available (Level 1). If such quoted market prices are not available, fair value is based upon internally developed models that primarily use, as inputs, observable market-based parameters (Level 2). Valuation adjustments may be made to ensure that financial instruments are recorded at fair value. These adjustments may include amounts to reflect counterparty credit quality and the customer’s creditworthiness, among other things, as well as unobservable parameters (Level 3). Any such valuation adjustments are applied consistently over time.

IMPERIAL RESOURCES, INC. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2011 and 2010

(j)	Cash Equivalents

For purposes of the consolidated statements of cash flows, the Company considers all demand deposits, money market accounts and certificates of deposit purchased with an original maturity of three months or less to be cash equivalents.

(k)	Revenue Recognition

Oil and natural gas revenues are recorded using the sales method, whereby the Company recognizes oil and natural gas revenue based on the amount of oil and natural gas sold to purchasers. The Company did not have any oil or natural gas imbalances recorded. The Company does not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists; (ii) delivery has occurred or services have been rendered; (iii) the seller’s price to the buyer is fixed or determinable; and (iv) collectability is reasonably assured.

(l)	Reclassifications

Certain prior period amounts have been reclassified to conform to current period presentation.

(m)	Recent Accounting Pronouncements

In January 2010, the FASB issued ASC Topic No. 932 to amend existing oil and gas reserve accounting and disclosure guidance (formerly FASB Staff Position No. 69), Extractive Activities-Oil and Gas, to align its requirements with the SEC’s Modernization of Oil and Gas Reporting rule. The significant revisions involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month arithmetic average of the first day of the month prices and additional disclosure requirements. In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. The amendments are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments. Application of the amended guidance has only resulted in changes to the prices used to determine proved reserves at December 31, 2010 and 2009, respectively. The new guidelines have expanded the definition of proved undeveloped reserves that can be recorded from an economic producer. The opportunity to prove reasonable certainty for spacing areas located more than one direct development spacing area from economic producer did not impact the Company’s proved developed or undeveloped reserves.

IMPERIAL RESOURCES, INC. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2011 and 2010

The primary changes in the amended ASC Topic No. 932 are as follows:

●	Amending the definition of proved oil and gas reserves to indicate that entities must use the average, first-day-of-the-month price during the 12-month period before the ending date of the period covered by the report (the 12-month average price) rather than the year-end price, when estimating whether reserve quantities are economical to produce.
●	Change the price used to calculate the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future cash flows from the year-end price to the 12-month average price used in calculating proved reserves.
●	Adding to and amending other definitions in the Master Glossary used in estimating proved oil and gas reserves quantities (for example, reliable technology and reasonable certainty).
●	Requiring that an entity disclose separately information about reserve quantities and financial statement amounts for geographic areas that represent 15 percent or more of proved reserves. In addition, Topic No. 932 is amended to indicate that the quantity of reserves is not the only factor that should be considered in determining whether reserves are significant (that is, an entity would be required to consider all facts and circumstances in determining whether reserves are significant).
●	Clarifying that an entity’s equity method investments must be considered in determining whether it has significant oil- and gas producing activities.

3.	OIL AND GAS LEASES

The Company has a total of $322,126 in oil and gas investments as of March 31, 2011, as follows:

	March 31, 2011
Producing Well	$	529,705
Accumulated depletion on producing well		(70,900	)
Impairment on producing well		(216,439	)
Net producing well		242,366
Other Greater Garwood Project leases		370,295
Impairment on Other Greater Garwood Project leases		(370,295	)
Exploratory Wells		79,760
Total oil and gas leases	$	322,126

Greater Garwood Project and Cochran #1 Well

The Cochran #1 well produced and sold approximately 22 Mmcfe, net during the twelve months ended March 31, 2011, and 6 Mmcfe net to Imperial for the three months ended March 31, 2010 (from acquisition date). The Company obtained a reserve report dated December 2009, showing total estimated net proved reserve estimates of approximately 287 Mmcfe for the Cochran #1 Well. All revenues for the years ended March 31, 2011 and 2010, are from the Cochran Well. The lease is also subject to a 25% freehold royalty. The Cochran #1 Well has a net book value of $242,366 as of the year ended March 31, 2011. Depletion expense totaled $69,612 for the twelve months ended March 31, 2011, plus impairment of $216,439, of which both amounts are included in our Consolidated Statement of Operations.

IMPERIAL RESOURCES, INC. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2011 and 2010

The Greater Garwood Project was acquired from the issuance of a $900,000 note payable. On December 10, 2010, the note payable of $900,000 plus $42,534 in accrued interest, was converted to 1,625,059 shares of the Company’s common stock at $0.58 per share. The fair value of the shares on the date of exchange was $1,218,794, resulting in a loss on debt extinguishment of $276,260, which is included in other expenses in the Statement of Operations.

As of March 31, 2011, impairment on the Greater Garwood Project and Cochran #1 well totaled $586,734.

Oklahoma Project

On July 12, 2010, Imperial Oil entered into a participation agreement, four areas of mutual interest (AMI) agreement and joint operating agreement to acquire leases on up to 5,000 acres in Oklahoma. The agreement provides for a 50% working interest in horizontal oil and gas drilling projects. As of March 31, 2011, there were no costs incurred. Subsequent to year-end March 31, 2011, the Company has participated in $82,127 of acreage costs.

Nunnelly #1 Project

On January 10, 2011, the Company entered into an Oil and Gas lease (“Agreement”) with the mineral owner of approximately 35 acres and an existing wellbore in Montague County Texas. The Agreement provides for the development of the Project lease area and the existing well, known as Nunnelly #1. The mineral owners’ will retain a 25% royalty interest in the acreage. Imperial has the option, to pay the costs associated with deepening and completion of the well, or alternatively, the drilling and completion of a new well. Deepening of the existing Nunnelly #1 wellbore is the Company’s first planned option. As of March 31, 2011, $19,760 is capitalized relating to surface preparation work at the site.

Stateline

On January 25, 2011, the Company entered into a Farmout Agreement ("Agreement") with a private oil and gas exploration company, for the right to earn acreage by drilling up to four wells in an infill development project ("Stateline") in the existing Sawyer Field, in Lea County, New Mexico. The Agreement calls for the Company’s subsidiary to pay a spud fee of $60,000 and drill between one and four wells to earn a 77% net revenue interests in 40 acres for each well drilled, subject to a reservation by the assigning party of a 10% working interest in each well drilled. The Agreement requires that not later than 270 days, drilling will commence on the first well. Drilling on the next well must commence not later than 180 days following the release of the drilling rig on the first well, with the drilling of subsequent wells having the same commencement requirements as the previously drilled well.

As of March 31, 2011, the Company has invested $60,000 related to the spud fee. The Company’s capital expense for the first well is expected to be around $635,000.

4.	NOTE PAYABLE

On January 19, 2010, Imperial Oil borrowed $900,000 from Coach pursuant to a promissory note, with interest of 5% per year, and maturity of January 19, 2013. If the note and accrued interest are not repaid in full between one year and three years after January 19, 2010, Coach will be paid 75% of the production revenue received by Imperial Oil from the lease, excluding the interest in the Cochran #1 well. If the note and accrued interest are not repaid in full after three years from January 19, 2010, Coach will be paid 100% of the net production revenue received by Imperial Oil from the lease, excluding the interest in the Cochran #1 well. The accrued interest on the Note for the period from issuance to December 10, 2010 was $42,534.

IMPERIAL RESOURCES, INC. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2011 and 2010

On December 10, 2010, Imperial Oil entered into a Note Conversion Agreement (“the “Agreement”) with Coach relating to the Note dated January 19, 2010. The Agreement provided Coach with an option, up until full repayment of the Note and accrued interest, to fully convert the Note into common stock of the Company at $0.58 per share. The Agreement also provided for, if the option was exercised, the terms of the Note relating to the Coach’s share of production from the producing well and potential future share of production in certain leased lands associated with that well, to be made null and void.

On December 10, 2010, pursuant to the Agreement, Coach served a valid notice on the Company to fully convert the Note of $900,000 plus $42,534 in accrued interest, to 1,625,059 shares of the Company’s common stock. The fair value of the shares on the date of exchange was $1,218,794, resulting in a loss on debt extinguishment of $276,260.

5.	CAPITAL STOCK

On October 31, 2007, Company completed a private placement consisting of 198,000,000 post dividend common shares sold to directors and officers for a total consideration of $3,000. On December 31, 2007, the Company completed a private placement of 49,665,000 post dividend common shares a total consideration of $37,625. On November 3, 2009, the Company issued a stock dividend to shareholders of record whereby the Company issued sixty-five shares of its common stock for each share of common stock held by such investors (all share references in these consolidated financial statements have been retroactively adjusted for this stock dividend). On October 22, 2009, 168,300,000 post dividend common shares were returned to Treasury and cancelled, and on January 27, 2010, a further 29,465,000 post dividend common shares were returned to Treasury and cancelled, leaving an outstanding balance at March 31, 2010 of 49,900,000 common shares. On April 29, 2010, a stockholder of the Company returned 9,900,000 shares of the Company’s common stock to treasury for cancellation. As a result, the number of shares of the Company’s common stock outstanding was reduced from 49,900,000 to 40,000,000.

On December 10, 2010 Imperial Resources, Inc. (the “Company”) and its wholly owned subsidiary, Imperial Oil and Gas, Inc. (“IOG”) entered into a Note Conversion Agreement (“the “Agreement”) with Coach Capital LLC (“Coach) relating to a Loan Note (“Note”) from Coach to IOG dated January 19, 2010. At December 10, 2010, the debt under the Note was $900,000 in principal and $42,534 in accrued interest, totaling $942,534. On December 10, 2010, under the Agreement, Coach served a valid notice on the Company to fully convert the Note. Accordingly Coach has been issued 1,625,059 shares of the Company’s common stock. The Note and its terms are cancelled. Following the issuance the total number of issued shares of the Company’s common stock was 41,625,059.

IMPERIAL RESOURCES, INC. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2011 and 2010

6.	INCOME TAXES

For the years ended March 2011 and 2010, the Company had net operating losses and, accordingly, no provision for income taxes has been recorded. In addition, no benefit for income taxes has been recorded due to the uncertainty of the realization of any tax assets. At March 2011, the Company has accumulated operating losses totaling approximately $1,173,000. The net operating loss carry forwards will begin to expire in 2027 if not utilized. The Company has recorded net operating losses in each year since its inception through March 31, 2011. Based upon all available objective evidence, including the Company’s loss history, management believes it is more likely than not that the net deferred assets will not be fully realized. Therefore, the Company has provided a valuation allowance against its deferred tax assets at March 2011 and 2010.

Non-current deferred tax assets for the years ended March 31, are as follows:

	2011			2010
Net operating losses	$	397,831		$	42,191
Less: valuation allowance		(397,831	)		(42,191	)
Net non-current deferred tax asset	$	-		$	-

Reconciliation between the income tax benefit determined by applying the applicable Federal statutory income tax rate to the pre-tax loss is as follows for the period indicated:

	2011			2010
Tax benefit at statutory income tax rate	$	(355,640	)	$	(7,688	)
Change in valuation allowance		355,640			7,688
Tax benefit reported	$	–		$	–

7.	COMMITMENTS ANDCONTINGENCIES

Stateline

As of March 31, 2011, the Company has invested $60,000 related to the spud fee. The Company’s capital expense for the first well is expected to be around $635,000.

IMPERIAL RESOURCES, INC. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2011 and 2010

8.	SIGNIFICANT TRANSACTIONS WITH RELATED PARTY

Consulting Agreements

Mara Prospects and Net Profit Interest

On January 19, 2010, Imperial Oil entered into a Net Profit Agreement with Mara Energy, LLC (“Mara”), whereby Imperial agreed to share profits from certain mutually beneficial oil and gas exploration and development opportunities in Canada and the continental United States, which are procured by Mara. The Net Profit Interest of 50% was to be assigned to Mara after “Payout", which means the date when the Imperial recovers Net Profits in an amount equal to the initial funded amount. Subsequent to year-end March 31, 2011 the Mara Net Profit Agreement was terminated on July 8, 2011 by mutual agreement between Imperial Oil and Mara.In addition, effective April 1, 2010, Imperial Oil and Mara entered into a Consulting Services Agreement, whereby Imperial Oil and Mara agreed that Mara will provide consulting services associated with any future development of Imperial Oil’s working interest in both the Greater Garwood oil and gas development exploration asset and the producing Cochran #1 well located in the Greater Garwood prospect in Colorado County, Texas. At March 31, 2011, no royalties or consulting fees have been paid. Mara is partially owned by our CEO and director, and former officers of the Company. Subsequent to year-end March 31, 2011 the Mara Consulting Services Agreement was terminated on July 8, 2011 by mutual agreement between Imperial Oil and Mara.

Sydney Oil and Gas Overriding Royalty Interest

On April 1, 2010, Imperial Oil entered into an Assignment of Overriding Royalty Interest Agreement to assign or pay Sydney Oil & Gas, LLC (“Sydney”), a gross overriding royalty of 6.5% of 8/8 for each lease or working interest acquired by Imperial Oil. Imperial’s CEO owns an interest in and controls Sydney. At March 31, 2011 no royalties have been paid.

Officers-directors and their families have no shares in the Company and have made no interest, demand loans to the Company of $31,340 and have made contributions to capital of $39,000 in the form of expenses paid for the Company.

9.	GOING CONCERN

The Company intends to seek business opportunities that will provide a profit. However, the Company does not have the working capital necessary to be successful in this effort and to service its debt, which raises substantial doubt about its ability to continue as a going concern.

Continuation of the Company as a going concern is dependent upon obtaining additional working capital and the management of the Company has developed a strategy, which it believes will accomplish this objective through additional loans from related parties, and equity funding, which will enable the Company to operate for the coming year.

10.	SUBSEQUENT EVENTS

Subsequent to March 31, 2011, on April 27, 2011 Imperial Oil entered into a Purchase and Sale Agreement to purchase approximately 41 acres of land, a related salt water disposal facility (”SWDF”) consisting of surface equipment, and a wellbore and associated permits, located in Wise County, Texas. The total purchase price of $500,000 was made through a $50,000 signing payment, plus the execution of a Convertible Promissory Note (the “Note”) totaling $450,000. The Note is secured over the SWDF assets.

IMPERIAL RESOURCES, INC. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2011 and 2010

The note is repayable monthly at $9,529.59 for fifty four months at a 6% fixed interest rate, commencing on June 1, 2011. The outstanding principal balance plus any accrued interest under the Note is convertible into common shares six months after execution of the agreement upon the option of the Holder. The Note is convertible into the number of shares equal to the balance of the principal and interest being converted divided by a 15% discount to the daily volume weighted average price per share for the ten business days prior to the date of the conversion notice.

On June 15, 2011, the Green Tide Water Disposal, Ltd., was formed as a wholly owned subsidiary of the Imperial Oil (“Green Tide”), signed a Convertible Promissory Note on June 17, 2011, in the amount of $1,200,000.00 payable to Quarry Bay Capital, LLC for Green Tide to rework and operate the SWDF.

On July 8, 2011 Imperial Oil and Mara Energy, LLC (“Mara”) mutually terminated a Consulting Services Agreement, whereby Imperial Oil and Mara had agreed that Mara would provide consulting services associated with any future development of Imperial Oil’s working interest in both the Greater Garwood oil and gas development exploration asset and the producing Cochran #1 well located in the Greater Garwood prospect in Colorado County, Texas. At March 31, 2011 and up to the date of termination on July 8, 2011, no royalties or consulting fees have been paid or are due to Mara.

11.	SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES

Oil and Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

In January 2010, the FASB issued ASC Topic No. 932 to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC’s Modernization of Oil and Gas Reporting rule. The significant revisions involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month arithmetic average of the first day of the month prices and additional disclosure requirements. In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. The amendments are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments. Application of the amended guidance has only resulted in changes to the prices used to determine proved reserves. The new guidelines have also expanded the definition of proved undeveloped reserves that can be recorded from an economic producer.

IMPERIAL RESOURCES, INC. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2011 and 2010

The opportunity to prove reasonable certainty for spacing areas located more than one direct development spacing area from economic producer did not impact the Company’s proved developed or undeveloped reserves.

As of March 31, 2011, the Company adopted the guidance in ASC 932 related to oil and gas reserve estimation and disclosures in conjunction with the year-end reserve reporting as a change in accounting principle that is inseparable from a change in accounting estimate. The impact of the adoption of this guidance on the Company’s financial statements was not practicable to estimate due to the challenges associated with computing a cumulative effect of adoption by preparing reserve reports under both the old and new guidance.

Oil and Gas Producing Activities

Estimates of total proved reserves for the producing Cochran #1 Well at March 31, 2011 and 2010, were based on December 2009 studies performed by Grant Twanow, our former Director, President and Chief Executive Officer. Mr. Twanow is a Petroleum Reservoir Engineering Specialist based in North America with extensive experience in oil and gas joint ventures and operations. The December 2009 reserve report estimates were based on year end prices for oil and natural gas. As there were no major discoveries or other favorable or unfavorable events since the report was issued, there was deemed no material change in the estimates of proved developed reserves for the Cochran #1 Well since the December 2009 report.

Our proved undeveloped oil reserves for the Stateline first well have been estimated internally. These reserves have not been presented herein until we obtain a review or audit of our internal estimates.

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. 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 changes in economic factors.

Capitalized Costs Relating to Oil and Gas Producing Activities

The following table illustrates the total amount of capitalized costs relating to natural gas and crude oil producing activities and the total amount of related accumulated depreciation, depletion and amortization.

Cochran #1 Well	March 31, 2011			March 31, 2010
Capitalized costs	$	529,705		$	529,705
Accumulated Depletion		(70,900	)		(1,288	)
Impairment		(216,439	)		-
Total Producing wells	$	242,366		$	528,417

Costs Incurred in Oil and Gas Producing Activities:

	March 31, 2011		March 31, 2010
Acquisition costs-proved and developed-Cochran #1 Well	$	-	$	529,705
Exploration costs		-		-
Total Costs Incurred	$	-	$	529,705

IMPERIAL RESOURCES, INC. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2011 and 2010

Results of Operations from Oil and Gas Producing Activities:

All our results of operations are from the Cochran #1 Well production and sales, which are reported in the Statement of Operations for the periods ended March 31, 2011 and 2010.

Proved Developed Reserves

Our proved developed reserves are summarized in the table below in Mmcfe.

	March 31, 2011			March 31, 2010
Beginning of the period	$	222.77		$	229.67
Revisions of previous estimates		-			-
Extensions and discoveries		-			-
Production		(23.84	)		(6.90	)
End of the period	$	198.93		$	222.77

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

The December 2009 reserve report estimates were based on year end prices for oil and natural gas. As there were no major discoveries or other favorable or unfavorable events since the report was issued, there was deemed no material change in the estimates of proved developed reserves for the Cochran #1 Well since the December 2009 report. Based on internal analysis the standardized value was estimated to be approximately $172,953 as of March 31, 2011.

Management does not solely use the following information when making investment and operating decisions. These decisions are based on a number of factors, including estimates of proved reserves, and varying price and cost assumptions considered more representative of a range of anticipated economic conditions.

Standardized Measure is as follows:

	March 31, 2011			March 31, 2010
Future cash inflows	$	512,433		$	2,211,051
Future production costs		(263,154	)		(460,775	)
Future development costs					-
Future net cash flows		249,279			1,750,276
10% annual discount		(76,326	)		(462,276	)
Standardized measure	$	172,953		$	1,288,000

Income taxes are expected to be zero.

Changes in the Standardized Measure

The principle sources of change in the standardized measure of discounted future net cash flows for the years ended Decemnber 31, 2010 and 2009 were as follows:

	March 31, 2011			March 31, 2010
Balance - beginning of year	$	1,288,000		$	-
Sales, net of operating expenses		(44,048	)		-
Extensions and discoveries		-			1,288,000
Accretion of discount		-			-
Net changes in prices and productions costs		(1,070,999	)		-
Revisions of prior estimates		-			-
Balance - end of year	$	172,953		$	1,288,000

Income taxes are expected to be zero.

Imperial Resources, Inc. - FORM 10-K - July 14, 2011

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Imperial Resources, Inc. Reports