- Annual Report (10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________

Form 10-K

R	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended March 31, 2009

OR

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

Commission File No. 000-51430

_______________

INDEX OIL AND GAS INC.

(Exact Name of Registrant as Specified in Its Charter)

Nevada	20-0815369
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

10000 Memorial Drive, Suite 440

Houston, Texas 77024

(Address of principal executive offices, including zip code)

(713) 683-0800

(Registrant’s telephone number, including area code)

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

None

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

Common Stock, $0.001

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No £

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 (§ 229.405 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 £ No R

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

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 definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer £ Accelerated Filer £

Non-accelerated Filer £ Smaller reporting company R

(Do not check if a smaller reporting company)

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

The aggregate market value of the voting stock held by non-affiliates of the registrant based on the closing price of the Registrant’s common stock as quoted on the OTC Bulletin Board on September 30, 2008 was $19,389,292

As of June 30, 2009, there were outstanding 71,656,852 shares of common stock.

Documents Incorporated by Reference

Information required by Part III will either be included in the registrant’s definitive proxy statement filed with the Securities and Exchange Commission or filed as an amendment to this Form 10-K no later than 120 days after the end of the registrant’s fiscal year, to the extent required by the Securities Exchange Act of 1934, as amended.

TABLE OF CONTENTS

PART I	3
Item 1. Business	3
Item 1A. Risk Factors	10
Item 1B. Unresolved Staff Comments	17
Item 2. Properties.	18
Item 3. Legal Proceedings.	22
Item 4. Submission of Matters to a Vote of Security Holders.	22
PART II	24
Item 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.	24
Item 6. Selected Financial Data.	26
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.	26
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.	33
Item 8. Financial Statements and Supplementary Data.	34
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.	34
Item 9A. Controls and Procedures.	34
Item 9A(T). Controls and Procedures.	34
Item 9B. Other Information.	34
PART III	35
Item 10. Directors, Executive Officers, and Corporate Governance.	35
Item 11. Executive Compensation.	35
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	35
Item 13. Certain Relationships and Related Transactions, and Director Independence.	35
Item 14. Principal Accountant Fees and Services.	35
PART IV	36
Item 15. Exhibits and Financial Statement Schedules.	36

SIGNATURES	37

Cautionary Note Regarding Forward Looking Statements

This Annual Report on Form 10-K (the “Annual Report”) contains “forward-looking statements” that represent our beliefs, projections and predictions about future events. All statements other than statements of historical fact are “forward-looking statements”, including any projections of earnings, revenue or other financial items, any statements of the plans, strategies and objectives of management for future operations, any statements concerning proposed new projects or other developments, any statements regarding future economic conditions or performance, any statements of management’s beliefs, goals, strategies, intentions and objectives, and any statements of assumptions underlying any of the foregoing. Words such as “may”, “will”, “should”, “could”, “would”, “predicts”, “potential”, “continue”, “expects”, “anticipates”, “future”, “intends”, “plans”, “believes”, “estimates” and similar expressions, as well as statements in the future tense, identify forward-looking statements.

These statements are necessarily subjective and involve known and unknown risks, uncertainties and other important factors that could cause our actual results, performance or achievements, or industry results, to differ materially from any future results, performance or achievements described in or implied by such statements. Actual results may differ materially from expected results described in our forward-looking statements, including with respect to correct measurement and identification of factors affecting our business or the extent of their likely impact, the accuracy and completeness of the publicly available information with respect to the factors upon which our business strategy is based or the success of our business. Furthermore, industry forecasts are likely to be inaccurate, especially over long periods of time and in relatively new and rapidly developing industries such as oil and gas. Factors that may cause actual results, our performance or achievements, or industry results, to differ materially from those contemplated by such forward-looking statements include without limitation:

• our ability to attract and retain management;

• our growth strategies;

• anticipated trends in our business;

• our future results of operations;

• our ability to make or integrate acquisitions;

• our liquidity and ability to finance our exploration, acquisition and development activities;

• our ability to successfully and economically explore for and develop oil and gas resources;

• market conditions in the oil and natural gas industry;

• the timing, cost and procedure for acquisitions;

• the impact of government regulation;

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

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

• increases in oil and natural gas production;

• the number of wells we anticipate being drilled in the future;

• estimates, plans and projections relating to acquired properties;

• the number of potential drilling locations on lands in which we have an interest;

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

• the possibility that our acquisitions may involve unexpected costs;

• the volatility in commodity prices for oil and natural gas;

• the accuracy of internally estimated proved reserves;

• the presence or recoverability of estimated oil and natural gas reserves;

• the ability to replace oil and natural gas reserves;

• the availability and costs of drilling rigs and other oilfield services use by the operators of properties in which we have an interest;

• environmental risks;

• exploration and development risks;

• competition;

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

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

Forward-looking statements should not be read as a guarantee of future performance or results, and will not necessarily be accurate indications of whether, or the times by which, our performance or results may be achieved. Forward-looking statements are based on information available at the time those statements are made and management’s belief as of that time with respect to future events, and are subject to risks and uncertainties that could cause actual performance or results to differ materially from those expressed in or suggested by the forward-looking statements. Important factors that could cause such differences include, but are not limited to, those factors discussed under the headings “Risk factors”, “Management’s discussion and analysis of financial condition and results of operations”, “Business” and elsewhere in this report.

PART I

Item 1. Business

Organization

We are an independent oil and natural gas company engaged in the acquisition, exploration, development, production and sale of oil and natural gas properties in North America. We have interests in properties in Kansas, Louisiana and Texas.

Index Oil and Gas Inc. (“Index”, Index Inc.”, “the Company”, or “we”, “us”, or “our”) was incorporated under the laws of the state of Nevada in March 2004 and is the parent company with four group subsidiaries: Index Oil & Gas Limited (“Index Ltd”), a United Kingdom holding company, which provides management services to the Company, and United States operating subsidiaries; Index Oil & Gas (USA) LLC (“Index USA”), an operating company; Index Investments North America Inc. (“Index Investments”); and Index Offshore LLC (“Index Offshore”), a wholly owned subsidiary of Index Investments and also an operating company. We do not currently operate any of our oil and natural gas properties, and we sell our oil and natural gas production to domestic purchasers through agreements primarily negotiated by the operators of our oil and natural gas properties.

Index was originally incorporated under the name Thai One On, Inc. (“Thai”) in March 2004 under the laws of the State of Nevada. In November 2005, Thai entered into a Letter of Intent agreement with Index Ltd for a proposed reverse merger with Thai. Subsequently, Thai changed its name to Index Oil and Gas Inc. In January 2006, the stockholders of Index Ltd entered into agreements that resulted in a change in control of the public entity. Index Ltd was incorporated in the United Kingdom in February 2003 and commenced oil and gas operations in the US later that year.

Prior to the reverse merger, Index Ltd operated with a fiscal year ended March 31. Subsequent to the reverse merger, the Board of Directors of the newly created Index Oil and Gas Inc. resolved to maintain the fiscal year ended March 31 and adopted this fiscal year end for the Company.

Overview

For the fiscal year ended March 31, 2009, Index had year-on-year increases in production and revenue. We have a sustained history of drilling success, measured by the completion rate on wells drilled, while pursuing higher-impact prospects and while remaining debt free (excluding ordinary course trade debt). We have recruited highly experienced senior staff members in exploration and production, land and operations and in accounting to the Index team.

Reserves decreased approximately 67% from 219.469 MBoe (thousand barrels of oil equivalent) of proven reserves as of March 31, 2008 to 87.703 MBoe of proven reserves as of March 31, 2009, primarily as a result of a full write-down of remaining reserves on the Shadyside well, and also on the Friedrich, Cason (3 wells) and Schroeder wells, partially offset by additions related to the Cochran well. As a result we have a low success rate on full cycle commerciality. Production rose approximately 250%, consistent with drilling success, from 28.6 MBoe for the fiscal year ended March 31, 2008 to 47.8 MBoe for the fiscal year ended of March 31, 2009. Total production in the fourth quarter of fiscal year 2009 was 9.8 MBoe. Correspondingly, oil and natural gas revenues increased approximately 65% from $1.7 million for the fiscal year ended March 31, 2008 to $2.8 million for the fiscal year ended March 31, 2009.

For the fiscal year ended March 31, 2009, we recorded a full cost ceiling test impairment write-down to its oil and natural gas properties of approximately $7.0 million, due to a downward adjustment to oil and gas reserves and lower oil and gas market prices at the end of the period. The impact of this impairment charge is that our net loss for the fiscal year ended March 31, 2009 is substantially higher than any prior equivalent period. In addition, the carrying amounts in our balance sheet at March 31, 2009 of oil and natural gas properties, total assets and total stockholders equity are all significantly reduced as a result of this $7.0 million charge. For a further detailed description of the full cost accounting method for oil and natural gas properties and the ceiling test impairment write-down, see Item 2. Business and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Going Concern Issues

Our consolidated financial statements have been prepared assuming that the Company will continue as a going concern. We have suffered recurring losses from operations. The continuation of our company as a going concern is dependent upon attaining and maintaining profitable operations and raising additional capital. We are actively currently seeking additional funding through various methods, but due to current market conditions funding may not be readily available. In addition, our current liabilities exceeded our current assets at March 31, 2009 and at the date of this report. One of the reasons for our current financial position is that we have suffered significant cost overruns on one of our projects, the Armour Runnells well, and we have arranged a payment plan with the operator of that property. This arrangement is not specifically covered in the governing agreements for the project or property, and the operator may seek to rely upon any and all provisions of those agreements. These conditions indicate the existence of a material uncertainty which may cast significant doubt over our ability to continue as a going concern.

Management is currently considering other options should current efforts to secure new funding be unsuccessful. These could include the establishment of a form of liquidating trust to hold the assets of the Company for the benefit of shareholders or the sale of the Company’s assets as part of a liquidation and, after discharging obligations, distributing the remaining proceeds, if any, to shareholders. Our Board of Directors is also actively considering deregistering from the Securities Exchange Act of 1934, if in its best judgment the costs of the requirements of being a compliant public company outweigh the benefits to shareholders and if we are eligible to deregister.

Our financial results depend upon many factors, particularly the price of oil and natural gas and our ability to market our production. Commodity prices are affected by changes in market demands, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future oil and natural gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, if any, production volumes and future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success.

Like all oil and natural gas exploration and production companies, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, an oil and natural gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on costs to add reserves through drilling and acquisitions as well as the costs necessary to produce our reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including the ability to timely obtain drilling permits and regulatory approvals.

Strengths and Strategies

We are a non-operating partner or participant in oil and natural gas projects in Texas, Louisiana and Kansas. We have interests in lands and properties and rely on third party operators to drill and operate wells on those properties. With each new drilling project on our properties, we have the opportunity to participate based on the proposal submitted to us by the operator for the specific project. We mitigate our risk by performing our own analysis of the proposed wells and the geological features of the target structures or horizons. Our technical staff has considerable experience in the oil and natural gas industry with specific expertise in the regions where our properties are located. As a non-operator, we are able to avoid some of the direct risks associated with operating oil and natural gas properties; although, because we rely on third party operators, certain of those risks may affect the properties and, if the risk is realized, would lower our returns on our investment in the properties.

We are able to access opportunities through ongoing business relationships and contacts made through our current staff and associated consultants. Each of these persons is able, through their experience and industry contacts, to provide us with a flow of business opportunities. Technical and financial due diligence and analysis of these opportunities allows us to select the most appropriate for participation. We are then able to add value to the ventures through high quality technical analysis and advice.

Our strategy has been to establish a presence in the onshore gulf coast region through participation in various projects with the goal of having those operations reach a level of production sufficient to support the business at its current levels while maintaining a debt-free basis (except for ordinary course trade debt). As of the end of our fiscal year ending March 31, 2009, following the reserve write-downs we have suffered and the drop in oil and, in particular, natural gas prices, we believe that we have not achieved this level of production with our existing interests in producing properties.

If we are able to secure new additional funding on terms satisfactory to management, on a go-forward basis, our goals are to enhance shareholder value by increasing our reserves, production, cash flow and profitability by (1) participating in the development of our existing core properties, (2) establishing new opportunities for exploration in moderate risk, moderate reward properties, (3) completing acquisitions and selective divestitures, (4) maintaining technical expertise, (5) focusing on cost control, and (6) maintaining financial flexibility. We have previously adjusted our business strategy to include more high-impact wells that can deliver, if successful, much higher value, volume, and follow-on potential that has the potential to deliver growth. We have tried to protect ourselves and our investors by limiting any single prospect investment to a small percentage of the overall funding that we have at our disposal. We will pursue appropriate opportunities to acquire or merge with businesses that share our risk-balanced approach to drilling opportunities and whose assets will enhance our growth and shareholder value. While we currently do not operate our properties, we will not preclude becoming an operator in the future if the opportunity and higher risk and cost structure meet with our expectations for enhanced shareholder value.

Our Operating Areas

We own producing and non-producing oil and natural gas properties in Kansas, Louisiana, and Texas. See Item 2. Property for a description of our proved reserves in each state. In each area we are pursuing geological objectives and projects that are consistent with our technical expertise to provide the highest potential economic returns. For the fiscal year ended March 31, 2009, we participated in 7.0 gross and 0.3588 net wells, for which principal drilling and, where applicable, completion operations were concluded in the year. Of these wells, 6.0 gross and 0.265 net wells became productive. The following is a summary of our major operating areas in which we discuss their various characteristics, including our working interests (“WI”) and our net revenue interests (“NRI”) in various properties and wells.

Kansas

Properties Summary . At March 31, 2009, we owned approximately 227 net acres in Kansas. Our production is concentrated in Stafford and Barton Counties. Total net production for the fiscal year ended March 31, 2009, for all Kansas wells was approximately 2,500 Bbls or 15.0 MMcfe (thousand Mcf of natural gas equivalent).

Operations Summary . Our Kansas properties represent a very low risk, low cost, low working interest, and limited upside project which is not expected to be a significant contributor to future growth. Our working interest in the Kansas wells is either 5% for wells drilled in Stafford County or 3.25% for wells drilled in Barton County, and the net revenue interest is either approximately 4.155% or 2.64%, respectively. The operating economics of our Kansas wells are very sensitive to the relationship of oil price and operating costs, and at March 31, 2009, a number of wells were shut in or were producing marginally. As of March 31, 2009, we had interests in 29 gross productive oil wells in Kansas (1.3725 and expect that participation to remain broadly constant in the fiscal year ending March 31, 2010, taking into account possible participation in new wells and shut-ins of existing wells.

Louisiana

Properties Summary . At March 31, 2009, we owned approximately 17 net acres in Calcasieu and St. Mary Parishes. Total net production for the fiscal year ended March 31, 2009, for 2.0 gross wells in Louisiana was approximately 47.6 Mmcfe.

Operations Summary . The Company’s onshore drilling program in Louisiana is comprised of its interest in the Walker 1 well (WI 12.5%, approximate NRI 9.36%) and the Shadyside 1 well (30% WI, 22.5% NRI). Future production from the Walker well, if any, is expected to be marginally economic. The Shadyside 1 well has experienced production issues and had workover operations performed which were unsuccessful in restoring production. The Company has fully written off its proved reserves on the well. We are in discussions, via our operator, to assign ownership of the Shadyside wellbore to a third party, which would avoid the requirement for us to plug and abandon the well. Should this assignment not proceed our proportion of the costs to plug and abandon the well are expected to be approximately $18,000, which we expect to be materially offset by salvage proceeds.

Texas

Properties Summary . At March 31, 2009, we owned approximately 1,956 net acres in Texas. Our production is in Brazoria, Matagorda, Victoria, Goliad, Wharton, Colorado, and Nacogdoches counties. Total net production for the fiscal year ended March 31, 2009, for all Texas wells was approximately 223.9 MMcfe or 37.3 MBoe. The table below shows our net production from the various Texas wells during the fiscal year ended March 31, 2009:

Texas Production

Year ending March 31, 2009

Well name	Gas, MMcf		Oil, MBbl		Equivalent, MBoe		Equivalent, MMcfe

Vieman 1		2.382		0.005		0.402		2.413
Hawkins 1		27.352		0.005		4.564		27.352
Freidrich Gas Unit 1		29.708		0.000		4.951		29.708
Schroeder Gas Unit 1		1.421		0.000		0.237		1.421
Cason wells *		14.661		0.000		2.444		14.661
Outlar 1		71.022		4.412		16.249		97.493
Ducroz 1		36.692		0.034		6.149		36.894
Cochran 1		12.856		0.190		2.333		13.998
Total		196.094		4.646		37.328		223.940

* Cason 1, Cason 2 and Cason 3

Operations Summary . As at March 31, 2009 we carried proved reserves against only the following Texas wells:

Outlar 1; Wharton County; WI 10.9% (9.38% after prospect payout ** ), NRI 8.2% (7.0% after prospect payout).

Ducroz 1; Brazoria County; WI 7.5%, NRI 5.25%.

Hawkins 1; Matagorda County; WI 12.5%, NRI 10.01%.

Cochran #1; Garwood County; WI 5%, NRI 3.75%.

** defined as that point in time when the gross proceeds of the sale of oil and/or gas produced and sold from all wells drilled in the prospect, and/or sale of any wells in the prospect, after deducting all lease burdens, including all overriding royalty interests, and taxes, (including gross production taxes, windfalls profit taxes, if any, and ad valorem taxes) equals the actual costs of drilling, testing, completing, equipping, and operating the test well, and/or any subsequent wells, in addition to the leasehold, overhead, and geological costs of the prospect.

All other wells in the above production table have suffered various depletion and production maintenance issues and were non-productive either at March 31, 2009 or the date of this report. We divested of our interest in the Cason wells and related leases in June 2006, for minimal cash consideration.

We also hold an interest in the following exploration projects in Texas:

Alligator Bayou prospect:

The Alligator Bayou prospect is a deep Wilcox trend high impact exploration prospect, located in Matagorda County, Texas, covering a large 4-way structural closure of approximately 10,000 acres defined by 2D seismic. The Armour-Runnells #1 ST exploratory well has been drilled to a total depth of 23,830 feet, has encountered multiple sands with logged pay and is currently awaiting the commencement of phase 2 testing operations. Index holds a 5% WI and a 3.5% NRI in the well and leases over the prospect. Management views this prospect as a potentially very significant exploration project, although, as of the date of this report, we cannot quantify what that impact may be or provide any assurances that the potential will be realized.

Garwood field:

The Garwood field is a three-way structural closure upthrown to a major Wilcox expansion fault, located in Colorado County, Texas, and has the potential to extend the highly productive Ewers/Meine trend tested in three nearby fields. The Cochran #1 well tested zones at approximately 16,600 feet and 13,800 feet, and is currently producing from the upper zone. The well has proved up at least two further development and three probable locations, with most likely reserves for each such well estimated by management as 2.5 Bcfe gross and 5.0 Bcfe gross, respectively. Index holds a 5% WI and a 3.75% NRI in the Cochran #1 well and leases over the prospect.

We also hold leases in Texas in: (i) the Supple Jack Creek lease area, at a 20% WI, in which a first well, HNH Gas Unit 1, was drilled and is currently suspended pending further evaluation of potential logged pay intervals; and (ii) the West Wharton prospect area, on which the Outlar 1 well was drilled. The second well, Stewart 1, including a sidetrack in which Index did not participate, was a dry hole and the overall project is now under review.

In general we must fund our share of costs of any proposed new operation, described in an Authorization for Expenditure (AFE) issued by an operator, for any existing or new well under an operating agreement in place or go “non-consent”. If we elect to go “non-consent” on an AFE, we generally will lose our interest in the well for which the operation was proposed until actual payout of the operation, plus a penalty as a percentage of payout. In general, under our joint operating agreements we can elect to go “non-consent” on wells, and we continue to evaluate the appropriate circumstances in which we choose to make that election.

Index is generally contractually liable for our share of all operational costs not covered by an AFE, such as, for example, well repair costs under a certain amount specified in an operating agreement or the costs of well plugging and abandonment. Index is also contractually liable for all costs it has agreed to under an AFE. Index must fund its share of any lease renewal or lease maintenance costs on any acreage not held by production, or it will lose its interest in that acreage.

Our Industry

Over the past few years, oil and natural gas prices have been high; however, over the last couple of years, the cost of services, equipment and goods has increased to offset most of the gain from high product prices. In general, very large companies have focused on onshore plays in which they have a significant acreage position and technological supremacy. Smaller companies have searched for niche plays that have been overlooked. We have tried to capitalize by using an expertise and intelligence to select those prospects that rank highly against our current portfolio.

Competitive Conditions in the Business

We are a small independent oil and natural gas exploration and production company that represents fractions of a percent of the oil and natural gas industry. We face competition from other oil and natural gas companies in all aspects of our business, including acquisition of producing properties and oil and natural gas leases, and obtaining goods, services and labor. Many of our competitors have substantially greater financial and other resources. Factors that affect our ability to acquire properties include available funds, available information about the property and our standards established for minimum projected return on investment. Many of these companies explore for, produce and market oil and natural gas, carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling operations, locating and acquiring attractive producing oil and natural gas properties, and obtaining purchasers and transporters of the oil and natural gas we produce. There is also competition between producers of oil and natural gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing natural gas and oil and may prevent or delay the commencement or continuation of a given operation. The effect of these risks cannot be accurately predicted.

Customers

Through contracts negotiated by our operators, we sell our crude oil and natural gas production to independent purchasers (collectively, “purchasers”), as allowed by our joint operating agreements. Additionally, we may sell directly to our operator crude oil and natural gas under our joint operating agreement. We have limited input into the terms of the contracts for the marketing or sale of our oil and natural gas production to purchasers. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil and natural gas purchases within forty-five days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers or our operators are collectible. All transportation costs are accounted for as costs that are offset against oil and natural gas sales revenue. In the fiscal year ended March 31, 2009, approximately 36%, 22% and 13% of revenues from our share of oil production were sold to three independent crude oil and gas purchasers, who also are our operators and who act on our behalf under our joint operating agreements as the purchaser of our oil and / or natural gas production and who maintain purchasing agreements with the underlying physical purchasers, and for the 2008 fiscal year ended March 31, 2008, approximately 28%, 25% and 17% of oil sales were sold to three independent crude oil purchasers. We do not believe the loss of any one of our purchasers would materially affect our ability to sell the oil and natural gas we produce. We believe that other purchasers are available in our areas of operations.

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil and natural gas and can also delay drilling activities, disrupting our overall business plans. Demand for natural gas is typically higher in the fourth and first quarters resulting in higher natural gas prices. Conversely, oil is in greater demand in the summer months. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of results, which may be realized on an annual basis.

Operational Risks

Oil and natural gas exploration and development involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that we or the operators of our properties will discover or acquire additional oil and gas in commercial quantities. Oil and natural gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other circumstances that may cause accidental leakage of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment, or cause significant injury to persons or property may occur. In such event, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could substantially reduce available cash and possibly result in loss of oil and gas properties. Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities. We are not aware of any of these instances that have occurred to date that need to be accrued for. As is common in the oil and natural gas industry, we, and to our knowledge the operators of our properties, will not be insured fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position and results of operations. For further discussion on risks see section titled “Risk Factors” set forth in “Item 1A. Risk Factors.”

Governmental Regulation

Domestic exploration for, and production and sale of, oil and natural gas are extensively regulated at both the federal and state levels. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding on the oil and natural gas industry that often are costly to comply with and that carry substantial penalties for failure to comply. In addition, production operations are affected by changing tax and other laws relating to the petroleum industry, constantly changing administrative regulations and possible interruptions or termination by government authorities.

Thus, the operation of our properties is subject to extensive and continually changing regulation affecting the oil and natural gas industry. Many departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding on the oil and natural gas industry and its individual participants. The failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases its cost of doing business and, consequently, affects its profitability. As a non-operator, we are not directly affected by these regulations and we do not believe that our properties are affected in a significantly different manner by these regulations than are our competitors’ properties.

Transportation and Sale of Natural Gas

Even though we initially focused on crude oil production, management believes that natural gas sales could contribute a substantial part to our total sales in fiscal year 2009. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation rates and various other matters, by the Federal Energy Regulatory Commission (“FERC”). Federal wellhead price controls on all domestic natural gas were terminated on January 1, 1992 and none of our natural gas sales prices are currently subject to FERC regulation. Index cannot predict the impact of future government regulation on any natural gas operations.

Regulation of Production

The production of crude oil and natural gas is subject to regulation under a wide range of state and federal statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds, and reports concerning operations. Texas, Louisiana and Kansas, the states in which we own properties, have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells, the spacing of wells, and the plugging and abandonment of wells and removal of related production equipment. Texas, Louisiana and Kansas also restrict production to the market demand for crude oil and natural gas. These regulations can limit the amount of oil and natural gas which can be produced from our wells, limit the number of wells, or limit the locations at which it can conduct drilling operations. Moreover, each state generally imposes a production or severance tax with respect to production and sale of crude oil, natural gas and gas liquids within its jurisdiction.

Environmental Regulations

Operation of our properties is subject to numerous stringent and complex laws and regulations at the federal, state and local levels governing the discharge of materials into the environment or otherwise relating to human health and environmental protection. These laws and regulations may, among other things, require acquisition of a permit before drilling or development commences, restrict the types, quantities and concentrations of various materials that can be released into the environment in connection with development and production activities, and limit or prohibit construction or drilling activities in certain ecologically sensitive and other protected areas. Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements and the imposition of injunctions to force future compliance. Our business and prospects could be adversely affected to the extent laws are enacted or other governmental action is taken that prohibits or restricts our development and production activities or imposes environmental protection requirements that result in increased costs to it or the oil and natural gas industry in general.

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior and various other federal, state, and local environmental, zoning, health and safety agencies, to evaluate major agency actions having the potential to significantly impact the environment human, animal and plant health, and affect our operations and costs. In recent years, environmental regulations have taken a cradle to grave approach to waste management, regulating and creating liabilities for the waste at its inception to final disposition. Exploration, development and production of our properties are subject to numerous environmental programs, some of which include solid and hazardous waste management, water protection, air emission controls and situs controls affecting wetlands, coastal operations and antiquities.

In the course of evaluations, an agency will have an Environmental Assessment prepared that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of the current exploration and production activities on our properties, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

In addition, environmental programs typically regulate the permitting, construction and operations of a facility. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Once operational, enforcement measures can include significant civil penalties for regulatory violations regardless of intent. Under appropriate circumstances, an administrative agency can request a cease and desist order to terminate operations.

Our operators conduct development and production activities designed to comply with all applicable environmental regulations, permits and lease conditions, including, monitoring subcontractors for environmental compliance. While we believe operations of our properties conform to those conditions, it remains at risk for inadvertent noncompliance, conditions beyond our control and undetected conditions resulting from activities by prior owners or the operators. Pursuant to industry customs, a project’s operator obtains insurance policy coverage for each of the participant’s in a particular project at a level of coverage that is commensurate with the potential loss.

Federal, State or Native American Leases

The operation of our properties on federal, state or Native American oil and natural gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land Management, Minerals Management Service and other agencies.

Waste Handling

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, affect oil and natural gas exploration and production activities by imposing regulations on the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and on the disposal of non-hazardous wastes. Under the auspices of the Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil, natural gas, or geothermal energy constitute “solid wastes”, which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or the individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration and production wastes as “hazardous wastes”.

We believe that the operators of our properties are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that they hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws.

We may be required in the future to make substantial outlays to comply with environmental laws and regulations. The additional changes in operating procedures and expenditures required to comply with future laws dealing with the protection of the environment cannot be predicted.

Compliance – General

We find it demanding to meet the overall compliance requirements across our business and the cost of such compliance is a significant component of our total expenses.

Employees

As of March 31, 2009, we had employment agreements with the following officers: Mr. Lyndon West, CEO, Mr. Andrew Boetius, CFO and Secretary, Mr. Dan Murphy, Chairman (who changed to three days per week from July 1, 2008) and Mr. Gregory Mendez, Controller. In addition, we had consulting agreements with entities owned and controlled by Dr. Ronald Bain, Chief Operating Officer, and Mr. Samuel Culpepper, Vice President Land and Operations, respectively. In addition, we had a letter agreement with Mr. David Jenkins, our non-executive director. We also had one employee on our administrative staff. As of March 31, 2009 we had five total and four full time employees, excluding the above consulting positions.

We also contract for the services of independent consultants involved in petroleum engineering, land, regulatory accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

Access to Company Reports

For further information pertaining to us, you may inspect without charge at the public reference facilities of the SEC at 100 F Street, NE, Room 1580, Washington, D.C. 20549 any of our filings with the SEC. Copies of all or any portion of the documents may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a website that contains reports, proxy and information statements and other information that is filed electronically with the SEC. The website can be accessed at www.sec.gov .

Corporate Governance Matters

Our website is http://www.indexoil.com . All corporate filings with the SEC can be found on our website, as well as other information related to our business. Under the Corporate Governance tab of the Investor Relations section you can find copies of our Code of Business Conduct and Ethics and our Whistleblower policy.

Item 1A. Risk Factors

You should carefully consider the risks described below as well as other information provided to you in this document, including information in the section of this document entitled “Information Regarding Forward Looking Statements.” The risks and uncertainties described below are not the only ones facing the Company. Additional risks and uncertainties not presently known to the Company or that the Company currently believes are immaterial may also impair the Company’s business operations. If any of the following risks actually occur, the Company’s business, financial condition or results of operations could be materially adversely affected, the value of the Company’s Common Stock could decline, and you may lose all or part of your investment.

Risks Related To Index’s Financial Results

We are at an early stage of development and have a limited operating history.

We were formed in 2003 operating as a private company, Index Ltd, formed under the laws of the United Kingdom and through which entity operations were conducted prior to the reverse merger into a public shell company, which occurred in 2006. As of the date of this Annual Report, we have a limited operating history upon which you can base an evaluation of our business and prospects. As a company in the early stage of development, we are subject to substantial risks, uncertainties, expenses and difficulties. You should consider an investment in Index in light of these risks, uncertainties, expenses and difficulties. To address these risks and uncertainties, we must do the following:

• Successfully execute our business strategy, including being able to attract adequate capital;

• Continue to develop our oil exploration and production assets;

• Respond to competitive developments; and

• Attract, integrate, retain and motivate qualified personnel.

We may be unable to accomplish one or more of these objectives, which could cause our business to suffer. In addition, accomplishing one or more of these objectives might be very expensive, which could harm our financial results. As a result, there can be no assurance that we will be successful in our oil and natural gas activities. Our future performance will depend upon our management and our ability to locate and negotiate additional oil and natural gas opportunities in which we are solely involved or participate in as a project partner. There can be no assurance that we will be successful in our efforts. Our inability to locate additional opportunities, successfully execute our business strategy, hire additional management and other personnel, or respond to competitive developments, could have a material adverse effect on our results of operations. There can be no assurance that our operations will be profitable.

We have incurred significant losses since inception and anticipate that we will continue to incur losses for the foreseeable future.

In the fiscal year ended March 31, 2009, we incurred a financial loss of approximately $9.4 million, after taxation and inclusive of impairment write-downs of approximately $7.0 million. In the future we may plan to significantly increase our corporate expenses and general overhead. There is no assurance, however, that we will be able to successfully achieve an increase in production and reserves so as to operate in a profitable manner. If the business of oil and natural gas well exploration and development slows, and commodity prices notably decline, our margins and profitability will suffer. We are unable to predict whether our operating results will be profitable.

Our operations have consumed a substantial amount of cash since inception. We expect to continue to spend substantial amounts to:

• identify and exploit oil and natural gas opportunities;

• maintain and increase the company’s human resources, including full time and consultant resources;

• evaluate drilling opportunities; and

• evaluate future projects and areas for long term development.

We expect to have increased cash requirements to fund our properties.

We expect that our cash requirement for operations and capital expenditures will increase significantly over the next several years. We will be required to raise additional capital to meet anticipated needs. Our future funding requirements will depend on many factors, including, but not limited to:

• success of ongoing operations;

• forward commodity prices; and

• operating costs (including human resources costs).

To date, our sources of cash have been primarily limited to the sale of equity securities. We cannot be certain that additional funding will be available on acceptable terms, or at all. To the extent that we raise additional funds by issuing equity securities, our stockholders may experience significant dilution. Any debt financing, if available, may involve restrictive covenants that impact our ability to conduct our business. If we are unable to raise additional capital, when required, or on acceptable terms, we may have to significantly delay, scale back or discontinue our operations, or cause our business to fail in its entirety.

We may be unable to effectively maintain our oil and gas exploration business.

Timely, effective and successful oil exploration and production is essential to maintaining our reputation as a developing oil exploration company. Lack of opportunities or success may significantly affect our viability. The principal components of our operating costs include salaries paid to corporate staff, costs of retention of qualified independent engineers and geologists, annual system maintenance and rental costs, insurance, transportation costs and substantial equipment and machinery costs. Because the majority of these expenses are fixed, a reduction in the number of successful oil exploration projects, failures in discovery of new opportunities or termination of ongoing projects will result in lower revenues and margins. Prior success in exploration or production of wells does not guarantee future success in similar ventures; thus, our revenues could decline and our ability to effectively engage in oil recovery business would be harmed.

At March 31, 2009, and as of the date of this annual report, our current liabilities exceeded our current assets and our independent accountants have raised doubt about our ability to continue as a going concern.

One of the reasons for this position is that we have suffered significant cost overruns on one of our projects and we have arranged a payment plan with the operator of that oil and natural gas property. This arrangement is not embodied in the governing agreements for the project or property and the operator may seek to rely upon any and all provisions of those agreements. In addition net proceeds from any future financings may be required to fund some or all of these past costs. The continuation of our company as a going concern is dependent upon our attaining and maintaining profitable operations and raising additional capital. We are actively seeking additional funding through various methods, but due to current market conditions, funding is not readily available. These conditions indicate the existence of a material uncertainty which may cast significant doubt over our ability to continue as a going concern.

Fluctuations in our operating results and announcements and developments concerning our business affect our stock price.

Our quarterly operating results, the number of stockholders desiring to sell their shares, changes in general economic conditions and the financial markets, the execution of new contracts and the completion of existing agreements and other developments affecting us, could cause the market price of our common stock to fluctuate substantially because of the limited daily trading volumes in our shares.

Risks Related to Our Business

We are dependent on the skill, ability and decisions of third party operators.

We do not operate any of our properties. The success of the drilling, development, production and marketing of the oil and natural gas from our properties is 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 operators may be unable to renew or maintain contracts with independent purchasers, which would harm our business and financial results.

Upon expiration of our independent purchasers’ contracts, we are subject to the risk that the oil and natural gas purchasers will cease buying our oil and gas production output. It is not always possible for our operators to immediately obtain replacement oil and natural gas purchasers as the industry is extremely competitive. If these contracts are not renewed, it could result in a significant negative impact on our business.

We may be subject to liability risks, which could be costly and negatively impact our business and financial results.

We may be subject to liability claims as an owner of working interests with respect to certain types of liabilities. There are currently many known environmental hazards associated with the exploration, discovery and delivery of natural gas and oil. Other significant hazards may be discovered in the future. To protect against possible liability, we maintain liability insurance with coverage that we believe is consistent with industry practice and appropriate in light of the risks attendant to our business. However, if we are unable to maintain insurance in the future at an acceptable cost or at all, or if our insurance does not fully cover us and a successful claim was made against us, we could be exposed to liability. Any claim made against us not fully covered by insurance could be costly to defend against, result in a substantial damage award against us and divert the attention of management from our operations, which could have an adverse effect on our financial performance.

Loss of key executives and failure to attract qualified managers, technologists, independent engineers and geologists could limit our growth and negatively impact our operations.

We depend upon our management team to a substantial extent. In particular, we depend upon Mr. Lyndon West, our President and Chief Executive Officer, Mr. Daniel Murphy, our Chairman of the Board of Directors, Dr. Ronald Bain, our Chief Operating Officer, Mr. Andrew Boetius, our Chief Financial Officer, Mr. Samuel Culpepper, our Vice President Land and Operations, and Mr. Gregory Mendez, our Controller, for their skills, experience, and knowledge of the company and industry contacts. Currently, we have employment or non-executive director agreements with all of our directors who are Lyndon West, Daniel Murphy, David Jenkins and Andrew Boetius. The loss of any of these executives, or other members of our management team, could have a material adverse effect on our business, results of operations or financial condition.

As we grow, we may increasingly require field managers with experience in our industry and skilled engineers, geologists and technologists to operate our diagnostic, seismic and 3D equipment. It is impossible to predict the availability of qualified managers, technologists, skilled engineers and geologists or the compensation levels that will be required to hire them. In particular, there is a very high demand for qualified technologists who are particularly necessary to operate systems similar to the ones that we operate. We may not be able to hire and retain a sufficient number of technologists, engineers and geologists and we may be required to pay bonuses and higher independent contractor rates to our technologists, engineers and geologists which would increase our expenses. The loss of the services of any member of our senior management or our inability to hire qualified managers, technologists, skilled engineers and geologists at economically reasonable compensation levels could adversely affect our ability to operate and grow our business.

Complying with federal and state regulations is an expensive and time-consuming process, and any failure to comply could result in substantial penalties.

Our operations are directly or indirectly subject to extensive and continually changing regulation affecting the oil and natural gas industry. Many departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding on the oil and natural gas industry and our individual participants. The failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability.

If operations of our properties are found to be in violation of any of the laws and regulations to which we are subject, we may be subject to the applicable penalty associated with the violation, including civil and criminal penalties, damages, fines and the curtailment of operations. Any penalties, damages, fines or curtailment of operations, individually or in the aggregate, could adversely affect our ability to operate our business and our financial results. In addition, many of these laws and regulations have not been fully interpreted by the regulatory authorities or the courts, and their provisions are open to a variety of interpretations. Any action against us for violation of these laws or regulations, even if we successfully defend against it, could cause us to incur significant legal expenses and divert management’s attention from the operation of our business.

We may experience competition from other oil and natural gas exploration and production companies, and this competition could adversely affect our revenues and our business.

The market for oil and natural gas recovery projects is generally highly competitive. Our ability to compete depends on many factors, many of which are outside of our control. These factors include: operation of our properties by third party operators, timing and market acceptance, introduction of competitive technologies, price, and purchaser’s interest in acquiring our oil and natural gas output.

Many existing competitors, as well as potential new competitors, have longer operating histories, greater name recognition, substantial track records, and significantly greater financial, technical and technological resources than us. This may allow them to devote greater resources to the development and promotion of their oil and natural gas exploration and production projects. Many of these competitors offer a wider range of oil and natural gas opportunities not available to us and may attract business partners consequently resulting in a decrease of our business opportunities. These competitors may also engage in more extensive research and development, adopt more aggressive strategies and make more attractive offers to existing and potential purchasers, and partners. Furthermore, competitors may develop technology and oil and natural gas exploration strategies that are equal or superior to us and achieve greater market recognition. In addition, current and potential competitors have established or may establish cooperative relationships among themselves or with third parties to better address the needs of our target market. As a result, it is possible that new competitors may emerge and rapidly acquire significant market share.

There can be no assurance that we will be able to compete successfully against our current or future competitors or that competition will not have a material adverse effect on our business, results of operations and financial condition.

We will need to increase the size of our organization, and may experience difficulties in managing growth.

We are a small company with only four full-time employees and one part-time employee as of March 31, 2009. We expect to experience a period of significant expansion in headcount, facilities, infrastructure and overhead and anticipate that further expansion will be required to address potential growth and market opportunities. Future growth will impose significant added responsibilities on members of management, including the need to identify, recruit, maintain and integrate additional independent contractors and managers. Our future financial performance and our ability to compete effectively will depend, in part, on our ability to manage any future growth effectively.

Oil and natural gas prices are volatile, and low prices could have a material adverse impact on our business.

Our revenues, profitability and future growth and the carrying value of our properties depend substantially on prevailing oil and natural gas prices. Prices also affect the amount of cash flow available for capital expenditures, if any, and our ability to borrow and raise additional capital. The amount we will be able to borrow under any senior revolving credit facility will be subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce and have an adverse effect on the value of our properties. Prices for oil and natural gas have increased significantly and have been more volatile over the past twelve months. Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause volatility are:

•	the domestic and foreign supply of oil and gas;

•	the ability of members of the Organization of Petroleum Exporting Countries, or OPEC, 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 gas producing regions;

•	the level of consumer product demand;

•	the growth of consumer product demand in emerging markets, such as China;

•	labor unrest in oil and natural gas producing regions;

•	weather conditions, including hurricanes and other natural disasters;

•	the price and availability of alternative fuels;

•	the price of foreign imports;

•	worldwide economic conditions; and

•	the availability of liquid natural gas imports.

These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and gas and our ability to raise capital.

Transportation delays, including as a result of disruptions to infrastructure, could adversely affect our operations.

Our business will depend on the availability of a distribution infrastructure. Any disruptions in this infrastructure network, whether caused by earthquakes, storms, other natural disasters or human error or malfeasance, could materially impact our business. Therefore, any unexpected delay in transportation of our produced oil and natural gas could result in significant disruption to our operations. We rely upon others to maintain the production of our wells and distribution of oil and natural gas, and any failure on their part to maintain the wells and corresponding production could impede the delivery of our oil and natural gas, impose additional costs on us or otherwise cause our results of operations or financial condition to suffer.

Assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.

Our initial growth is due to acquisitions of properties and undeveloped leaseholds. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and gas prices, operating and capital costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties.

As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.

Estimates of oil and natural gas reserves are uncertain and any material inaccuracies in these reserve estimates will materially affect the quantities and the value of our reserves.

This Annual Report contains estimates of our proved oil and natural gas reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir.

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

Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make capital expenditures to develop our reserves. Although we have prepared estimates of these oil and gas reserves and the costs associated with development of these reserves in accordance with SEC regulations, we cannot assure you that the estimated costs or estimated reserves are accurate, that development will occur as scheduled or that the actual results will be as estimated.

Exploration and development drilling efforts and the operation of our wells on our properties may not be profitable or achieve our targeted returns.

We require significant amounts of undeveloped leasehold acreage in order to further our development efforts. Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that all of our prospects will result in viable projects or that we will not abandon our initial investments. Additionally, we cannot guarantee that the leasehold acreage we acquire will be profitably developed, that new wells drilled on the properties will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. We rely to a significant extent on 3D seismic data and other advanced technologies in identifying leasehold acreage prospects and in determining whether or not to participate in a new well. The 3D seismic data and other technologies we use do not allow us to know conclusively prior to acquisition of leasehold acreage or the drilling of a well whether oil or natural gas is present or may be produced economically.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel for the operator of our properties. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. As a result of increasing levels of exploration and production in response to strong prices of oil and natural gas, the demand for oilfield services has risen, and the costs of these services are increasing, while the quality of these services may suffer. If the unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel is particularly severe in Kansas, Texas and Louisiana, we could be materially and adversely affected because our properties are concentrated in those areas.

Title to the properties in which we have an interest may be impaired by title defects.

Our operators generally obtain title opinions on significant properties that we have working interests in. However, there is no assurance that we will not suffer a monetary loss from title defects or failure. Generally, under the terms of the operating agreements affecting our properties, any monetary loss is to be borne by all parties to any such agreement in proportion to their interests in such property. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

The following risks relate principally to our Common Stock and its market value

There is a limited market for our common stock which may make it more difficult for you to dispose of your stock.

Our common stock has been quoted on the OTC Bulletin Board under the symbol “IXOG.OB” since December 16, 2005. There is a limited trading market for our common stock. Furthermore, the trading in our common stock maybe highly volatile, as for example, approximately ninety percent of the trading days in the quarter to March 31, 2009 saw trading in our stock of less than 100,000 shares per day, including all days in the month of March 2009. During that same period, the smallest number of shares traded in one day was zero and the largest number of shares traded in one day was 193,156. Accordingly, there can be no assurance as to the liquidity of any markets that may develop for our common stock, the ability of holders of our common stock to sell our common stock, or the prices at which holders may be able to sell our common stock.

The price of our Common Stock may be volatile.

The trading price of our common stock may be highly volatile and could be subject to fluctuations in response to a number of factors beyond our control. Some of these factors are:

•

our results of operations and the performance of our competitors;

•

the public’s reaction to our press releases, our other public announcements and our filings with the Securities and Exchange Commission;

•

changes in earnings estimates or recommendations by research analysts who follow, or may follow, us or other companies in our industry;

•

changes in general economic conditions;

•

changes in market prices for oil and gas;

•

actions of our historical equity investors, including sales of common stock by our directors and executive officers;

•

actions by institutional investors trading in our stock;

•

disruption of our operations;

•

any major change in our management team;

•

other developments affecting us, our industry or our competitors; and

•

U.S. and international economic, legal and regulatory factors unrelated to our performance.

In recent years the stock market has experienced significant price and volume fluctuations. These fluctuations may be unrelated to the operating performance of particular companies. These broad market fluctuations may cause declines in the market price of our common stock. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company or our performance, and those fluctuations could materially reduce our common stock price.

Our common stock is subject to the “penny stock” rules of the SEC and the trading market in our securities is limited, which makes transactions in our stock cumbersome and may reduce the value of an investment in our stock.

The Securities and Exchange Commission has adopted Rule 15g-9 which establishes the definition of a “penny stock,” for the purposes relevant to us, as any equity security that has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require:

•

that a broker or dealer approve a person’s account for transactions in penny stocks; and

•

the broker or dealer receive from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.

In order to approve a person’s account for transactions in penny stocks, the broker or dealer must:

•

obtain financial information and investment experience objectives of the person; and

•

make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prepared by the Commission relating to the penny stock market, which, in highlight form:

•

sets forth the basis on which the broker or dealer made the suitability determination; and

•

that the broker or dealer received a signed, written agreement from the investor prior to the transaction.

Generally, brokers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors to dispose of our common stock and cause a decline in the market value of our stock.

Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissions payable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks.

The requirements of being a public company, including compliance with the reporting requirements of the exchange act and the requirements of the Sarbanes Oxley act, strains our resources, increases our costs and may distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company, we need to comply with laws, regulations and requirements, including certain corporate governance provisions of the Sarbanes-Oxley Act of 2002 and related regulations of the SEC. Complying with these statutes, regulations and requirements occupies a significant amount of the time of our board of directors and management. We are or may be required to:

•

institute a comprehensive compliance function;

•

establish internal policies, such as those relating to disclosure controls and procedures and insider trading;

•

design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;

•

prepare and distribute periodic reports in compliance with our obligations under the federal securities laws;

•

involve and retain outside counsel and accountants in the above activities; and

•

establish an investor relations function.

In addition, rules adopted by the SEC pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 will require annual assessment of our internal control over financial reporting, and attestation of the assessment by our independent registered public accountants. The requirement for both an annual assessment of our internal control over financial reporting and the attestation of the assessment by our independent registered public accountants, as the rules now stand, will first apply to our annual report for fiscal year ending March 31, 2010. In the future, our ability to continue to comply with our financial reporting requirements and other rules that apply to reporting companies could be impaired, and we may be subject to sanctions or investigation by regulatory authorities. In addition, failure to comply with Section 404 or a report of a material weakness may cause investors to lose confidence in us and may have a material adverse effect on our stock price.

Because of the high cost of compliance, our board of directors may in the near future recommend to deregister from the Securities Exchange Act, if possible, if in its best judgment the costs of the requirements of being a compliant public company outweigh the benefits to shareholders and if we are eligible to deregister. If we deregister, the market for trading in our common stock could become even less liquid, and information regarding our company could be less available.

We do not expect to pay dividends in the future. Any return on investment may be limited to the value of our stock.

We do not anticipate paying cash dividends on our stock in the foreseeable future. The payment of dividends on our stock will depend on our earnings, financial condition and other business and economic factors affecting us at such time as the board of directors may consider relevant. If we do not pay dividends, our stock may be less valuable because a return on your investment will only occur if our stock price appreciates.

The exercise of our outstanding warrants and options may depress our stock price

We currently have 5,853,947 warrants, excluding the Loyalty Warrants associated with our $2.77 million private placement in February 2008 which have contingent exercise requirements, and options to purchase shares of our common stock outstanding, at March 31, 2009. The exercise of warrants and/or options by a substantial number of holders within a relatively short period of time could have the effect of depressing the market price of our common stock and could impair our ability to raise capital through the sale of additional equity securities. See Note #11 “Options and Warrants and Stock-Based Compensation” to the Notes accompanying our audited consolidated financial statements filed herewith.

We may need additional capital that could dilute the ownership interest of investors.

We require substantial working capital to fund our business. If we raise additional funds through the issuance of equity, equity-related or convertible debt securities, these securities may have rights, preferences or privileges senior to those of the rights of holders of our common stock and they may experience additional dilution. We cannot predict whether additional financing will be available to us on favorable terms when required, or at all. Since our inception, we have experienced negative cash flow from operations and expect to experience significant negative cash flow from operations in the future. The issuance of additional common stock by our management may have the effect of further diluting the proportionate equity interest and voting power of holders of our common stock, including investors in this offering.

Item 1B. Unresolved Staff Comments

None

Item 2. Properties.

Principal Executive Offices

We lease our main office comprising of approximately 1,665 square feet which is located at 10000 Memorial Drive, Suite 440, Houston, Texas 77024. Lease payments at fiscal year ended March 31, 2009, were $4,500 per month and are due on a month-to-month basis. We also have two leases related to corporate housing for UK based officers while periodically working at the corporate office, one on a month-to-month basis and one with a remaining 4-month lease respectively, with $1,760 and $1,800 due per month.

We believe that we have satisfactory title to the properties in which we may own an interest and used in our business, subject to liens for taxes not yet paid, liens incident to minor encumbrances and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our business. We believe that our properties are adequate and suitable for us to conduct business in the future.

Oil and Gas Reserves

The March 31, 2009 proved reserve estimates presented in this Annual Report were prepared by Ancell Energy Consulting, Inc. (“Ancell”). The estimates of quantities of proved reserves below were made in accordance with the definitions contained in SEC Regulation S-X, Rule 4-10(a). For additional information regarding estimates of proved reserves, the preparation of such estimates by Ancell and other information about our oil and natural gas reserves, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our reserves are sensitive to commodity prices and their effect on economic production rates. Our estimated proved reserves are based on oil and gas spot market prices in effect for the periods presented in this report on the last trading day of March 2009, 2008 and 2007, respectively. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control, such as commodity pricing. Therefore, the reserve information in this Annual Report represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced.

At March 31, 2009, our estimated total proved oil and natural gas reserves were approximately 87.703 MBoe, consisting of 20.967 thousand barrels of oil (MBbls) and 400.414 million cubic feet (MMcf) of natural gas. Approximately 70.879 MBoe or 80.8% of our proved reserves were classified as proved developed producing. We aim to maintain a portfolio of long-lived, lower risk reserves along with shorter lived, higher margin reserves. We believe that a balanced reserve mix will provide a diversified cash flow foundation to contribute to funding our development and exploration drilling programs.

The following table presents certain information as of March 31, 2009, and for our reserves and properties all located onshore in the United States. Shut-in wells currently not capable of production are excluded from the producing well information.

In MBoe:	Kansas		Louisiana		Texas		Total


Proved Reserves at Year End
Developed		11.046		--		59.833		70.879
Undeveloped		--		--		16.824		16.824

Total		11.046		--		76,657		87.703

Gross Wells (1)		29.000		1.000		8.000		38.000
Net Wells (1)		1.3725		0.1250		1.4688		2.9663

(1)

Gross wells or acreage means the total wells or acreage in which a working interest is owned, and net wells or acreage means the sum of the fractional working interests owned in gross wells or acreage, as the case may be.

The oil reserves shown include crude oil and condensate. Oil volumes are expressed in barrels (Bbl) or thousand barrels (MBbls); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in thousands of standard cubic feet (Mcf) at the contract temperature and pressure bases. The term MBoe which is defined as thousands of barrels of equivalent oil is also used and is calculated by converting gas volumes to oil volumes at the ratio of 6:1.

The estimated reserves and future revenue shown in our reserve report are for proved developed producing, proved behind pipe and proved undeveloped reserves. In accordance with SEC guidelines, our estimates do not include any probable or possible reserves, which may exist for these properties. This report does not include any value, which could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.

This table above is for properties located in Stafford and Barton Counties in Kansas, Calcasieu Parish in Louisiana and Brazoria, Matagorda, Wharton, Nacogdoches, Colorado, Lavaca, and Victoria Counties in Texas.

Future gross revenue to our interest is prior to deducting state production taxes and ad valorem taxes. Future net revenue is calculated after deducting these taxes, future capital costs, and operating expenses but before consideration of federal income taxes; future net revenue for those properties is calculated after deducting net abandonment costs. In accordance with SEC guidelines, the future net revenue has been discounted at an annual rate of 10% to determine its “present worth.” The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

Oil prices used in this report are based on the March 31, 2009 oil price received at various points and averaged $44.63 per barrel. Natural gas prices used in this report are based on a March 31, 2009, NYMEX spot market price and averaged $3.98 per Mcf, adjusted by lease for energy content, transportation fees, and regional price differentials. Oil and natural gas prices are held constant in accordance with SEC guidelines.

Lease and well operating costs are based on operating expense records of Index. For non-operated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with costs estimated to be incurred at and below the district and field levels. As requested, lease and well operating costs for the operated properties include only direct lease and field level costs. For all properties, headquarters general and administrative overhead expenses of Index are not included. Lease and well operating costs are held constant in accordance with SEC guidelines. Capital costs are included as required for workovers, new development wells, and production equipment.

Productive Wells and Acreage

As of March 31, 2009, we had interests in 38 gross productive wells (2.96625 net productive wells). Our oil (only) wells totaled 30 gross productive wells and 1.4975 net productive oil wells, our gas (only) wells totaled 5 gross productive wells and 1.2000 net productive oil wells and our mixed oil and gas wells totaled 3 gross and 0.26875 net mixed oil and gas productive wells.

Acreage

“Gross” represents the total number of acres or wells in which a working interest is owned and in which we own a working interest. “Net” represents our proportionate working interest resulting from our ownership in the gross acres or wells. Productive wells are wells in which we have a working interest and that are capable of producing oil or natural gas. The following table sets forth our interest in undeveloped acreage and developed acreage in which we own a working interest as of March 31, 2009.

	Developed Acreage				Undeveloped Acreage				Total Acreage

State	Gross		Net		Gross		Net		Gross		Net

Kansas		3,654.00		168.14		1,090.30		58.83		4,744.30		226.97
Louisiana		132.00		16.53		—		—		132.00		16.53
Texas		1,917.02		205.52		21,645.13		1,750.26		23,562.15		1,955.78

Total Acreage		5,703.02		390.19		22,735.43		1,809.09		28,438.45		2,199.28

The following is the expiration of the undeveloped acreage by calendar year of expiration:

	2009				2010				2011				Thereafter

	Gross		Net		Gross		Net		Gross		Net		Gross		Net

Undeveloped Acreage		5,823.31		724.17		16,896.54		1,083.21		15.58		1.71		--		--

The majority of our gross undeveloped acreage covers our Alligator Bayou prospect in Texas, with renewal principally due in 2010. A decision to maintain those leases will depend in part on the results of our Armour Runnells well, the first well drilled on the prospect and currently awaiting the start of phase 2 testing operations. Our largest net undeveloped acreage position is on the Supple Jack Creek prospect area, on which the majority of those leases are due to expire later in 2009. A decision on those leases will depend in part on the testing results of the HNH Gas Unit 1 well, currently suspended prior to testing; however it is unlikely these leases will be materially retained. Our operator is currently considering development drilling plans on the Garwood prospect, on which we hold approximately 2,700 gross undeveloped acres and a 5% WI. Our ability to participate in further development in these properties will depend on our ability to acquire sufficient funds to do so or we may be forced to go “non-consent.”

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. All general corporate costs are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The net capitalized costs of evaluated oil and natural gas properties are subject to a full cost ceiling test.

Capitalized costs of our evaluated and unevaluated properties at March 31, 2009, 2008 and 2007 are summarized as follows:

	March 31,

	2009		2008		2007

Capitalized costs:
Proved and evaluated properties	$	4,878,182	$	11,181,430	$	3,254,211
Unproved and unevaluated properties		4,878,940		2,821,271		1,927,776

		9,757,122		14,002,701		5,181,987

Less accumulated depreciation and depletion		3,493,586		1,407,610		315,937

	$	6,263,536	$	12,595,091	$	4,866,050

Production

Our oil and gas production volumes and average sales price for the twelve months ended March 31, 2009, 2008 and 2007, respectively, are as follows:

	Years Ended March 31,

	2009		2008		2007

Gas production (MMcf):		237.381		126.888		8.4900
Oil production (MBbl)		8.216		7.478		6.660
Equivalent production (MBoe)		47.779		28.626		8.075

Average price per unit:
Gas (per Mcf)	$	8.79	$	8.21	$	6.61
Oil (per Bbl)	$	90.31	$	88.69	$	60.20
Equivalent (per Boe)	$	59.20	$	59.58	$	56.60

Drilling Activity

The table below sets forth the results of our drilling activities for the periods indicated:

	Years Ended March 31,

	2009				2008				2007

	Gross		Net		Gross		Net		Gross		Net

Gross Exploratory Wells:
Productive		4.00		0.165		10.00		2.019		5.00		0.2150
Dry		1.00		0.094		3.00		0.150		4.00		0.6825
Total Exploratory		5.00		0.259		13.00		2.169		9.00		0.8975



Gross Development Wells:
Productive		2.00		0.100		1.00		0.075		1.00		0.195
Dry		--		--		--		--		--		--
Total Development		2.00		0.100		1.00		0.075		1.00		0.195


Total Gross Wells:
Productive		6.00		0.265		11.00		2.094		6.00		0.323
Dry		1.00		0.094		3.00		0.150		4.00		0.518
Total		7.00		0.359		14.00		2.244		10.00		0.841

Note:

Gross wells means the total wells in which a working interest is owned, and net wells means the sum of the fractional working interests owned in gross wells.

Present Activities

During the year ended March 31, 2009, we reviewed and revised our original capital expenditure budget and plans based on the liquidity issues discussed in this report. We are currently planning to make continuing capital expenditures on the Armour-Runnells well, with the objective of achieving definitive test results. Our forward plan includes the potential drilling of second wells on the Garwood and Alligator Bayou projects, together with potential 3D seismic acquisition and lease renewals on Alligator Bayou, and potential additional operations on the HNH Gas Unit well. We do not currently have sufficient funds to be able to commit to these expenditures, if proposed by our operators. We may also have some further small expenditures which may be incurred in Kansas. At the start of our current fiscal year commencing on April 1, 2009 we approved a provisional budget for the first quarter of the fiscal year only, recognizing that we need to raise additional funds to be able to participate in new exploration activities. We are currently considering a budget for the second fiscal quarter and beyond, which is dependent on various circumstances and factors, including our ability to raise new funds.

Delivery Commitments

At March 31, 2009, we had no delivery commitments with our purchasers.

Item 3. Legal Proceedings.

From time to time, we may be a defendant and plaintiff in various legal proceedings arising in the normal course of our business. We are currently not a party to any material pending legal proceedings or government actions, including any bankruptcy, receivership, or similar proceedings. In addition, management is not aware of any known litigation or liabilities involving the operators of our properties that could affect our operations. Should any liabilities be incurred in the future, they will be accrued based on management’s best estimate of the potential loss. As such, there is no adverse effect on our consolidated financial position, results of operations or cash flow at this time. Furthermore, management does not believe that there are any proceedings to which any director, officer, or affiliate of the Company, any owner of record of the beneficially or more than five percent of the common stock of the Company, or any associate of any such director, officer, affiliate of the Company, or security holder is a party adverse to the Company or has a material interest adverse to the Company.

For the month of June 2008 and for the first 18 days of July 2008, Eaglwing, L.P. purchased substantially all of the crude oil production of certain properties in Barton and Stafford Counties, Kansas, in which Index has a working interest. Our operator then ceased selling crude oil production to the entity. As publicly reported, on July 22, 2008, SemCrude, L.P. ("SemCrude") and certain of its affiliates, including Eaglwing, L.P. ("Eaglwing"), voluntarily filed for bankruptcy in the United States Bankruptcy Court for the District of Delaware. Index has not received payment for such sales. Recovery on such accounts receivable will depend on, among other things, the bankruptcy process governing SemCrude and Eaglwing, a summary of which follows.

By demand for Reclamation of Goods dated July 25, 2008, our operator demanded the return of all such oil received by Eaglwing for the period from June 7, 2008 through July 21, 2008. The demand was made by our operator for itself and as agent for all interest owners, including Index USA, on whose behalf our operator sold oil to Eaglwing. Subsequently, Index executed a Letter of Authorization to our operator to act as its agent and attorney-in-fact to take certain measures on Index’s behalf in, and in connection with, the bankruptcy proceedings. We have recently been advised of a decision that our secured claim, for 20 days of oil sales immediately preceding the bankruptcy filing by Eaglwing, is not impaired. We are awaiting details of the timing and amount of this potential recovery, and which may be received before the end of 2009 calendar year.

Item 4. Submission of Matters to a Vote of Security Holders.

By proxy statement approved by our Board of Directors, we solicited votes for three proposals during the fourth quarter of our fiscal year ended March 31, 2009. The three proposals presented by the Company to stockholders were approved during the Company's reconvened annual general meeting on January 27, 2009. The annual general meeting was originally held on December 9, 2008, and was adjourned to January 27, 2009 for lack of a quorum.

A quorum of stockholders present in person or by proxy approved the re-election of four directors. Board members re-elected were Daniel L. Murphy, chairman, Lyndon West, Andrew Boetius, and David Jenkins, non-executive director. The Company has no other Board members. Stockholders also ratified the 2008 Stock Incentive Plan and the appointment of RBSM LLP as independent auditors for the fiscal year ending March 31, 2009.

The vote tallies were as follows:

(1) Election of nominees to the Board of Directors of the Company.

	For		Withheld

Daniel L. Murphy		34,384,413		3,533,996
Lyndon West		35,282,239		2,636,170
Andrew Boetius		35,282,239		2,636,170
David Jenkins		35,282,239		2,636,170

(2) Ratification of appointment of RSBM LLP as the Company’s auditors for the fiscal year ending March 31, 2009.

For				Against				Abstain
	36,276,720				41,589				1,600,100

(3) Ratification of the 2008 Stock Incentive Plan.

For				Against				Abstain
	16,912,165				3,925,748				6,267,393

PART II

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

Market Information

Our common stock has been quoted on the OTC Bulletin Board under the symbol IXOG.OB since December 16, 2005.

The following sets forth the high and low bid prices for our common stock for the quarters in the period starting April 1, 2007, through March 31, 2009. Such prices represent inter-dealer quotations, do not represent actual transactions, and do not include retail mark-ups, markdowns or commissions. Such prices were determined from information provided by a majority of the market makers for our common stock.

	High		Low

2008 Fiscal Year
June 30, 2007		1.50		0.78
September 30, 2007		1.07		0.70
December 31, 2007		0.84		0.49
March 31, 2008		0.64		0.47

2009 Fiscal Year
June 30, 2008		0.87		0.54
September 30, 2008		0.64		0.24
December 31, 2008		0.32		0.07
March 31, 2009		0.44		0.07

The shares quoted are subject to the provisions of Section 15(g) and Rule 15g-9 of the Securities Exchange Act of 1934, as amended (the Exchange Act”), commonly referred to as the “penny stock” rule. Section 15(g) sets forth certain requirements for transactions in penny stocks and Rule 15(g)-9(d)(1) incorporates the definition of penny stock as that used in Rule 3a51-1 of the Exchange Act.

The Commission generally defines penny stock to be any equity security that has a market price less than $5.00 per share, subject to certain exceptions. Rule 3a51-1 provides that any equity security is considered to be a penny stock unless that security is: registered and traded on a national securities exchange meeting specified criteria set by the Commission; issued by a registered investment company; excluded from the definition on the basis of price (at least $5.00 per share) or the registrant’s net tangible assets; or exempted from the definition by the Commission. Trading in the shares is subject to additional sales practice requirements on broker-dealers who sell penny stocks to persons other than established customers and accredited investors, generally persons with assets in excess of $1,000,000 or annual income exceeding $200,000, or $300,000 together with their spouse.

For transactions covered by these rules, broker-dealers must make a special suitability determination for the purchase of such securities and must have received the purchaser’s written consent to the transaction prior to the purchase. Additionally, for any transaction involving a penny stock, unless exempt, the rules require the delivery, prior to the first transaction, of a risk disclosure document relating to the penny stock market. A broker-dealer also must disclose the commissions payable to both the broker-dealer and the registered representative, and current quotations for the securities. Finally, the monthly statements must be sent disclosing recent price information for the penny stocks held in the account and information on the limited market in penny stocks. Consequently, these rules may restrict the ability of broker-dealers to trade and/or maintain a market in our common stock and may affect the ability of stockholders to sell their shares.

Holders

As of March 31, 2009, the approximate number of our stockholders of record of our common stock was 194.

Dividends

We have not declared any dividends to date. We have no present intention of paying any cash dividends on our common stock in the foreseeable future, as we intend to use earnings, if any, to generate growth. The payment by us of dividends, if any, in the future, rests within the discretion of our Board of Directors and will depend, among other things, upon our earnings, our capital requirements and our financial condition, as well as other relevant factors. There are no material restrictions in our certificate of incorporation or bylaws that restrict us from declaring dividends.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table shows information with respect to each equity compensation plan under which our common stock is authorized for issuance as of March 31, 2009:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) *
	(a)		(b)		(c)
Equity compensation plans approved by security holders		4,952,526	$	0.37		5,441,037

Equity compensation plans not approved by security holders		-0-	$	-0-		-0-

Total		4,952,526	$	0.37		5,441,037

* Based on 5,500,000 shares of common stock reserved under the shareholder approved 2008 Stock Incentive Plan, less cumulative issuances to date of 58,963 shares, and assuming no shares are carried forward from the 2006 Incentive Stock Option Plan.

58,963 shares in aggregate were awarded as a stock award under the 2008 Stock Incentive Plan to Daniel Murphy, Lyndon West, Andrew Boetius and David Jenkins in lieu of reduced salary for the month of December 2008. Equivalent arrangements for reduced salaries and benefits for these individuals continued for the months of January 2009 through May 2009, with stock awards due following the end of the period. Under a provisional calculation an aggregate of 434,461 shares are issuable for the period January to March 2009, and a further 532,945 for the months of April and May 2009, and assuming the Company does not withhold any shares otherwise distributable in order to satisfy any tax obligations with respect to the issuance of such shares. These awards are subject to approval of the Board of Directors and have not been made as of date of this report. All awards are to be made under the shareholder approved 2008 Stock Incentive Plan. These shares are not included for the purpose of the figures in column (c) in the table above.

Unregistered Sales of Equity Securities and Use of Proceeds

Issuance of Unregistered Securities

None.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers.

None.

Item 6. Selected Financial Data.

Not Applicable.

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

Forward Looking Statements

Please see page ii of this Annual Report for “Information Regarding Forward Looking Statements” appearing throughout this Annual Report.

Business Overview

For this information please see Part 1, Item 1 “Business Overview”.

Results of Operations

Year Ended March 31, 2009 Compared to Year Ended March 31, 2008

We had a net loss of $9.4 million for the fiscal year ended March 31, 2009 compared to a net loss of $1.9 million for the fiscal year ended March 31, 2008. The significant change in our results over the two periods is primarily the result of our approximately $7.0 million impairment charge, which we anticipate taking upon the completion of our audited financial statements and which is the result primarily of the recent severe decrease in commodity prices, together with reserve write downs. Revenue increased by $1.1 million while operating income decreased by $7.3 million, which included general and administrative costs of $2.4 million, which was relatively unchanged, increased depletion of $1.0 million to $2.1 million, and an increased impairment of $7.0 million , and lower interest income on capital previously raised and used in our operations. The following table summarizes key items of comparison and their related increase (decrease) for the fiscal years ended March 31, 2009 and 2008.

	Years Ended March 31,						Increase
	2009			2008			(Decrease)

Oil and gas sales	$	2,828,751		$	1,705,593		$	1,123,158
Production expenses:
Lease operating		520,434			188,521			331,913
Taxes other than income		183,748			114,952			68,796
General and administrative:
General and administrative		2,218,695			2,155,018			63,677
Stock-based compensation		211,748			302,911			(91,163	)
Depletion — Full cost		2,085,976			1,091,673			994,303
Depreciation — Other		8,506			4,556			3,949
Impairment		7,002,472			--			7,002,472
Interest expense (income) and other		(24,207	)		(205,608	)		181,401
Income tax benefit (provision)		--			--			--

Net income (loss)	$	(9,378,621	)	$	(1,946,430	)	$	(7,432,191)


Production:
Natural Gas — MMcf		237.381			126.888			110.493
Crude Oil — MBbl		8.216			7.478			0.738
Equivalent — MBoe		47.779			28.626			19.153

Average price per unit:
Gas price per Mcf	$	8.79		$	8.21		$	0.58
Oil price per Bbl	$	90.31		$	88.69		$	1.62
Equivalent per Boe	$	59.20		$	59.58		$	(0.38)

Average cost per Boe:
Production expenses:
Lease operating	$	10.89		$	6.59		$	4.30
Taxes other than income	$	3.89		$	4.02		$	(0.13	)
General and administrative expense:
General and administrative	$	46.44		$	75.28		$	(28.84	)
Stock-based compensation	$	4.43		$	10.58		$	(6.15	)
Depletion expense	$	43.66		$	38.14		$	5.52

For the year ended March 31, 2009, oil and natural gas sales increased $1.1 million, from the same period in 2008, to $2.8 million. The increase for the year was primarily due to the increase in production volumes of 19.2 MBoe from 28.6 MBoe to 47.8 MBoe or approximately the whole $1.1 million increase. The increase in volumes of 19.2 MBoe was primarily due to additional volumes from Outlar of 9.9 MBoe, Ducroz 4.7 MBoe, Hawkins 3.8 MBoe, and Shadyside of 1.0 MBoe offset by Walker which decreased 1.6 MBoe and Schroeder which decreased by 2.0 MBoe. The Cason wells also contributed 1.0 MBoe. Total oil production was 8.2 MBoe and total natural gas production was 237.4 MMcf. Additionally, our revenue variance related to year-on-year price changes was a slight decrease with our average price per Boe decreasing by $0.38, or 0.6%, in fiscal 2009 to $59.20 per Bbl from $59.58 per Bbl in fiscal 2008 and reflecting an increased proportion of natural gas volumes which had a lower energy equivalent value. This is based on weighted average gas volumes at an increased price of $8.79 per Mcf and weighted average oil volumes at an increased price per barrel of $90.31. We benefited from increased product prices in the year to March 31, 2009, both for oil and natural gas. However, our production and sales mix has switched to become predominantly natural gas comprised, and the year on year price increase on a Boe basis is less significant than the absolute price changes for each product, due to natural gas realizing a lower energy equivalent price compared to crude oil.

Depletion, depreciation and amortization (“DD&A”) expense increased $1.0 million from the same period in 2008 to $2.1 million for the fiscal year ended March 31, 2009. The increase is primarily due to increased production from the following wells; Ducroz, Shadyside, Hawkins, and Outlar, and an increase in the unit depletion cost rate. Depletion for oil and gas properties is calculated using the unit of production method, which essentially depletes the capitalized costs associated with the proved properties based on the ratio of production volume for the current period to total remaining reserve volume for the evaluated properties. On a per unit basis, DD&A expense increased from $6.38 per Mcfe to $7.31 per Mcfe.

Ceiling test impairment expense was recorded for the fiscal year ended March 31, 2009 in the amount of $7.0 million. Quarterly, we assess the value of unamortized capitalized costs within our cost center over the discounted present value of cash flows associated with its reserves. Any excess requires an immediate write-down of our capital costs by this amount. During the fiscal year ended March 31, 2009, the excess of unamortized capitalized costs over the related cost ceiling limitation was $7.0 million due primarily to a full write-down of remaining reserves on Shadyside of approximately 542.8 Mmcfe, Friedrich of approximately 111.6 Mmcfe, Cason (3 wells) of approximately 67.8 Mmcfe, and Schroeder of approximately 47.8 Mmcfe and the effect of these write-downs on the present value ceiling in the ceiling test computation. Reserve reductions were partially offset by additions related to the Cochran well (174.5 Mmcfe). In addition, adjustments to the projected average prices for our oil and natural reserves, and which were used for the purposes of our ceiling tests, lead to a reduction from $11.93/Mcfe at March 31, 2008 to $4.81/Mcfe at March 31, 2009. The impact of this impairment charge is that our net loss for the fiscal year ended March 31, 2009 is substantially higher than any prior equivalent period. In addition the carrying amounts in our balance sheet at March 31, 2009 of oil and natural gas properties, total assets and total stockholders equity are all significantly reduced as a result of this $7.0 million charge.

Our major market risk exposure to inflation is in the pricing of our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control. Based on average daily production for the years ended March 31, 2009 and 2008, our annual income before income taxes would change by approximately $24,000 and $12,000, respectively for each $0.10 per Mcf change in natural gas prices and approximately $8,000 and $7,000, respectively for each $1.00 per Bbl change in crude oil prices, excluding the effects of hedging activities, which we currently do not engage in.

Lease operating expenses increased approximately $0.3 million for the year ended March 31, 2009 as compared to the same period in 2008. The increase was primarily due to production from the following wells; Outlar, Shadyside, Ducroz and Hawkins. On a per unit basis, lease operating expenses increased by $4.30 per Boe to $10.89 per Boe in 2009 from $6.59 per Boe in 2009 due primarily to an increase in production volumes offset by industry-wide service costs associated with the overall increase in commodity prices.

Taxes other than income increased $0.06 million for the year ended March 31, 2009 as compared to the same period in 2008 due to higher oil and gas revenues, but on a per unit basis decreased $0.13 per Boe to $3.89 per Boe. This was due to our increased production in the State of Texas, relative to our Louisiana and Kansas wells. Production taxes are generally assessed as a percentage of gross oil and/or natural gas sales.

General and administrative expenses, excluding stock-based compensation expense, for the year ended March 31, 2009 was relatively unchanged at $2.2 million compared to the same period in 2008.

Stock-based compensation expense, within general and administrative expenses, was $0.2 million for the year ended March 31, 2009 as compared to $0.3 million for the year ended March 31, 2008 for a net decrease of $0.1 million in fiscal 2009. This is primarily due to less stock-based compensation expense in fiscal year 2009. All stock compensation was calculated at fair market value and other required inputs at the date of the grant in accordance with SFAS 123(R).

Interest income and other decreased $0.2 million for the year ended March 31, 2009 compared to the same period 2008. This decrease is primarily due a reduction in interest income through the use of capital in investing activities of approximately $2.7 million from prior year's private placement equity fund raisings.

There was no provision for income taxes for the fiscal years ended 2009 and 2008 due to a valuation allowance of $8.4 million and $5.1 million recorded for the years ended March 31, 2009 and 2008, respectively on the total tax provision as we believed that it is more likely than not that the asset will not be utilized during the next year.

Liquidity and Capital Resources

Operating cash flow fluctuations were substantially driven by commodity prices and changes in our production volumes. Prices for oil and natural gas have historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season for natural gas and summer travel for oil; however, the impact of other risks and uncertainties have influenced prices throughout the recent years.

The recent and ongoing changes in the global economy, including the economic recession in the United States, are adversely affecting the demand for oil and natural gas, and commodity prices for both products have fallen significantly. There is a high probability of continuing low prices for the foreseeable future and possibly further price declines. Our revenues are based on sales of oil and natural gas at prevailing market prices. Cash flows provided by operating activities were positive for the fiscal year ended March 31, 2009, but were based on average prices that were higher than the average from March 31, 2009 to the date of this report.

Working capital was substantially influenced by these factors. See “Results of Operations” for a review of the impact of prices and volumes on sales. In the fiscal year ended March 31, 2009, positive cash flows were generated by operating activities, inclusive of working capital movements, but these did not contribute any material funding to exploration and development expenditures. The ceiling test limitation impairment charge is a non-cash item and had no impact on our cash flows and did not affect our liquidity. See below for additional discussion and analysis of cash flow.

During the second half of fiscal year 2009, we decided to minimize capital expenditures because we did not expect to generate positive cash flows from operations through to March 31, 2009 and in the near term thereafter and also because we had not, and still have not as of the date of this report, secured any new funding. Our total capital expenditures for the fiscal year to March 31, 2009 were less than our original budget, having taken into account cost increases on the Armour-Runnells well.

	Years Ended March 31,

	2009			2008

Cash flows provided by (used in) operating activities	$	492,300		$	(1,194,749	)
Cash flows (used in) investing activities		(2,708,458	)		(8,792,152	)
Cash flows provided by financing activities		--			2,397,752
Effect of exchange rate changes		14,674			(14,674)
Net (decrease) in cash and cash equivalents	$	(2,201,485	)	$	(7,603,823)

Operating Activities

Net cash flow from operating activities during the fiscal year ended March 31, 2009 was $0.5 million which was a positive change in use of cash of $1.7 million from $1.2 million net cash outflow during the fiscal year ended March 31, 2008. The year ended March 31, 2009 generated neutral cash flow at the operations level, together with positive working capital movements, which resulted in small overall positive cash flows from operating activities.

Investing Activities

The primary driver of cash used in investing activities was capital spending.

Cash used in investing activities during the fiscal year ended March 31, 2009 was $2.7 million, which was a decrease of $6.1 million from $8.8 million of cash used in investing activities during the fiscal year ended March 31, 2008. This decrease was primarily due to decreased exploration and development activity in the fiscal year ended March 31, 2009 versus March 31, 2008. Capital spending was primarily on the Armour-Runnells 1 well of $2.2 million and on the Cochran 1 well of $0.5 million. The activity included in prior year capital spending was primarily for drilling operations on the Cason 1, 2, and 3 wells of $1.8 million, the Taffy 1, 2, and 3 wells of $0.2 million, Vieman 1 of $0.2 million, Shadyside 1 of $2.5 million, HNH Gas Unit 1 of $1.8 million, combined Outlar 1 and Stewart 1 of $1.2 million, Alligator Bayou of $0.4 million and an aggregate of spending on other projects and wells of $0.2 million.

Financing Activities

There was no cash used or provided by financing activities during the fiscal year ended March 31, 2009, as no proceeds were received for capital transactions and no financing or debt transactions occurred.

Historically, we have financed our cash needs by private placements of our securities. We intend to finance future cash needs primarily through equity offerings but may fund those needs through debt offerings. There is no assurance that we will be able to obtain financing on terms consistent with our past financings or satisfactory to us.

As of March 31, 2009 and 2008, our common stock is the only class of stock outstanding, and we have no outstanding short or long-term debt financing.

Liquidity Issues and Going Concern Issues

Management is of the view that we will find it very difficult in the current market conditions to raise any new funds through debt or equity offerings, although we continue to seek these opportunities. This has forced us to curtail and reconsider any planned growth strategies in the immediate future and could result in the curtailment of our operations.

The continuation of our company as a going concern is dependent upon our attaining and maintaining profitable operations and raising additional capital. We are actively seeking additional funding through various methods, but due to current market conditions, funding is not readily available. These conditions indicate the existence of a material uncertainty which may cast significant doubt about our ability to continue as a going concern.

Based on our current cash resources and other current assets, and using assumptions that by nature are imprecise, management believes we have available liquidity to fund only limited operations over the immediate future and do not have liquidity to participate in new drilling activities in our current properties. In addition, our current liabilities exceeded our current assets as at March 31, 2009 and at the date of this report.

We have endeavored to reduce general and administrative costs where possible. We have concluded arrangements with certain of our management and Directors under which salaries and fees were reduced by 30% and then 50% and certain benefits would be suspended and for lost salary and benefits to be replaced by stock awards of an equivalent value, to be made under our 2008 Stock Incentive Plan. Such arrangements are effective from December 1, 2008 through to May 31, 2009, at which point prior terms were to be re-applied. The Remuneration Committee of the Board of Directors has recommended that the arrangements be extended through to July 31, 2009. We have also reduced the usage of certain consulting services and have terminated certain consultant agreements. We have reduced our expenditures to a minimum on investor and public relations related activities. We continue to operate month-to-month arrangements for the use of our Houston office.

We are subject to continuing cost overruns on operations on the Armour-Runnells well and are at risk of low and declining product prices for our sales of oil and natural gas. Our priorities are to continue to be able to participate in and fund continuing expenditures on the Armour-Runnells well, if we conclude such expenditures are of potential benefit, and to continue to meet operating cost and other contractual obligations on our existing wells. We may not be able to make future undeveloped lease renewal and lease maintenance expenditures that we may wish to make, and therefore, we may lose rights to certain undeveloped acreage. We currently are not able to make any new financial commitments to participate in new projects and will only be able to consider participation in any discretionary proposed new operations on our existing properties if we conclude we have funds for the expenditure. During 2009 and 2010, we may be presented with proposals for new operations, including new drilling on our Garwood, Alligator Bayou, Supple Jack Creek and Kansas properties, and possibly others. We await recommendations from our operator of the Shadyside well.

We are currently actively considering all potential corporate transactions, which may include full or partial asset disposals or a business combination with another entity in a transaction where Index is not the surviving entity. Because of the current economic conditions affecting oil and natural gas companies and because of our lack of liquidity, there is no assurance that any such transaction would be accretive to our shareholders or result in any profit being realized by our shareholders.

As part of our analysis of ways to reduce costs and in light of the high cost of continuing to be a public reporting company under the Securities Exchange Act of 1934, as amended, and complying with the Sarbanes-Oxley Act of 2002, we are exploring alternative platforms, which may involve deregistering under the Securities Exchange Act of 1934, or “going dark”, and having our common stock quoted on the "pink sheets", which is an automated quotation system under which broker-dealers publish quotes for trading in over-the-counter securities. We anticipate that this move would provide substantial savings from the costs of being registered under the Securities Exchange Act of 1934. We also are evaluating the benefits of continuing to be traded on the OTC-Bulletin Board. Analysis of a move to the “pink sheets” involves not only reducing costs, but also our expected sources of future capital as well as the number of record holders of our outstanding common stock. A move to having our common stock quoted on the “pink sheets” may result in a less liquid market for our shares and less readily available information on us, but will result in continued public trading of our common stock by holders wishing to trade.

We currently are seeking payment in a bankruptcy proceeding related to the former purchaser of our Kansas oil production, Eaglwing L.P., for the recovery of approximately $50,000 in value of oil sales. We dispute that our debt be classified as unsecured on the basis that, under applicable Kansas law, producers have liens in product delivered to debtors and we have recently been advised of a decision that our secured claim, for 20 days of oil sales immediately preceding the bankruptcy filing by Eaglwing, is not impaired. Recovery of the debt is uncertain, and the debt has been fully provided against. In the current economic environment, there is an increased risk that other of our purchasers could similarly file for bankruptcy protection and we continue to assess such risk. See also Part II, Item 1.

Contractual Obligations

We have no material long-term commitments associated with our capital expenditure plans or operating agreements. Consequently, we believe we have a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant. Our level of capital expenditures will vary in future periods depending on the success we experience in our acquisition, developmental and exploration activities, oil and natural gas price conditions and other related economic factors. Currently no sources of liquidity or financing are provided by off-balance sheet arrangements or transactions with unconsolidated, limited-purpose entities.

Amounts related to our asset retirement obligations (ARO) are uncertain regarding the actual timing of such expenditures. Of the total ARO, $125,716 is classified as a current liability at March 31, 2009 while $14,998 and $88,209 are classified as a long-term liability at March 31, 2009 and 2008, respectively. For each of the years ended March 31, 2009 and 2008, we recognized no accretion expense related to our ARO, due to the assumption of a full offset in aggregate of salvage values. In the aggregate, we expect that proceeds from salvage value of tangible well and surface equipment will materially offset and fund the costs of plugging and abandoning our onshore producing wells. We have taken steps to mitigate our plugging and abandoning liabilities by divesting our 3 Cason wellbores subsequent to March 31, 2009 and are currently in discussions to assign our interest in the Shadyside wellbore. Following significant cost overruns we have arranged a payment plan with the operator of our Armour Runnels well for certain costs incurred, and such costs representing the majority of our accounts payable and accrued expenses at March 31, 2009 and the date of this report. This arrangement is not specifically covered in the governing agreements for the project or property, and the operator may seek to rely upon any and all provisions of those agreements.

Off-Balance Sheet Arrangements

For the fiscal year ended as of and at March 31, 2009, we did not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States of America. We also describe the most significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with our Board of Directors. See Results of Operations above and Item 8. Consolidated Financial Statements and Supplementary Data Notes 1 and 2, Organization and Operations of the Company and Summary of Significant Accounting Policies, for a discussion of additional accounting policies and estimates made by management.

Oil and Gas Activities

Accounting for oil and natural gas activities is subject to special, unique rules. Two generally accepted methods of accounting for oil and natural gas activities are available — successful efforts and full cost. The most significant differences between these two methods are the treatment of exploration costs and the manner in which the carrying value of oil and natural gas properties are amortized and evaluated for impairment. The successful efforts method requires exploration costs to be expensed as they are incurred while the full cost method provides for the capitalization of these costs. Both methods generally provide for the periodic amortization of capitalized costs based on proved reserve quantities. Impairment of oil and natural gas properties under the successful efforts method is based on an evaluation of the carrying value of individual oil and natural gas properties against their estimated fair value, while impairment under the full cost method requires an evaluation of the carrying value of oil and natural gas properties included in a cost center against the net present value of future cash flows from the related proved reserves, using period-end prices and costs and a 10% discount rate.

Full Cost Method

We use the full cost method of accounting for our oil and gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized into a cost center (the amortization base). Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. Costs associated with production and general corporate activities are expensed in the period incurred. The capitalized costs of our oil and gas properties, plus an estimate of our future development and abandonment costs are amortized on a unit-of-production method based on our estimate of total proved reserves. Our financial position and results of operations would have been significantly different had we used the successful efforts method of accounting for our oil and gas activities.

Proved Oil and Gas Reserves

Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization expense and the full cost ceiling limitation. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for a given reservoir may change substantially over time as a result of numerous factors including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.

Our estimated proved reserves for the four years ended March 31, 2009 were prepared by Ancell Energy Consulting, Inc., an independent petroleum engineering firm. For more information regarding reserve estimation, including historical reserve revisions refer to Item 8. Consolidated Financial Statements and Supplementary Data, Supplemental Oil and Gas Disclosure.

Depreciation, Depletion and Amortization

The quantities of estimated proved oil and natural gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves are revised upward, earnings would increase due to lower depletion expense. Likewise, if reserves are revised downward, earnings would decrease due to higher depletion expense or due to a ceiling test write-down.

Full Cost Ceiling Limitation

Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and natural gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and natural gas properties exceed the cost center ceiling, we are subject to a ceiling test write-down to the extent of such excess. If required, it would reduce earnings and impact stockholders’ equity in the period of occurrence and result in lower amortization expense in future periods. The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that prices and costs in effect as of the last day of the quarter are held constant. However, we may not be subject to a write-down if prices increase subsequent to the end of a quarter in which a write-down might otherwise be required. If oil and natural gas prices decline, even if for only a short period of time, or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of our oil and natural gas properties could occur in the future.

Future Development and Abandonment Costs

Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems and related structures and restoration costs of land and seabed. Our operators develop estimates of these costs for each of our properties based upon their geographic location, type of production structure, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and future abandonment costs on an annual basis.

The accounting for future abandonment costs changed on January 1, 2003 with the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations. This standard requires that a liability for the discounted fair value of an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Holding all other factors constant, if our estimate of future abandonment and development costs is revised upward, earnings would decrease due to higher depreciation, depletion and amortization (DD&A) expense. Likewise, if these estimates are revised downward, earnings would increase due to lower DD&A expense. Of the total ARO, $125,716 is classified as a current liability at March 31, 2009 while $14,998 and $88,209 are classified as a long-term liability at March 31, 2009 and 2008, respectively. For each of the years ended March 31, 2009 and 2008, the Company recognized no accretion expense related to its ARO, due to the assumption of a full offset in aggregate of salvage values.

Allocation of Purchase Price in Business Combinations

As part of our business strategy, we actively pursue the acquisition of oil and natural gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. Our most significant estimates in our allocation typically relate to the value assigned to future recoverable oil and natural gas reserves and unproved properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.

Effective January 1, 2002, we adopted SFAS No. 142, Goodwill and Other Intangible Assets, under which goodwill is no longer subject to amortization. Rather, goodwill of each reporting unit is tested for impairment on an annual basis, or more frequently if an event occurs or circumstances change that would reduce the fair value of the reporting unit below its carrying amount. In making this assessment, we rely on a number of factors including operating results, economic projections and anticipated cash flows. As there are inherent uncertainties related to these factors and our judgment in applying them to the analysis of goodwill impairment, there is risk that the carrying value of our goodwill may be overstated. If it is overstated, such impairment would reduce earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill.

Revenue Recognition

We recognize revenue when crude oil and natural gas quantities are delivered to or collected by the respective purchaser or operator (collectively "purchasers"). We sold our crude oil and natural gas production to several purchasers as of March 31, 2009. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil and natural gas purchases within forty-five days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. All transportation costs are accounted for as a reduction of oil and natural gas sales revenue.

Recent Accounting Developments

Business Combinations . In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”), which replaces SFAS No. 141. SFAS No. 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquired and the goodwill acquired. The Statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for fiscal years beginning after December 15, 2008. The adoption of SFAS 141(R) will have an impact on accounting for business combinations once adopted, but the effect is dependent upon acquisitions after that time.

Noncontrolling Interests . In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of Accounting Research Bulletin No. 51” (“SFAS 160”), which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. The Statement also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. SFAS 160 is effective for fiscal years beginning after December 15, 2008. The Company does not currently have any noncontrolling interests in subsidiaries, but once adopted, the effects will be dependent upon acquisitions after that time.

Oil and Gas Reporting Requirements . In December 2008, the SEC released Release No. 33-8995, “Modernization of Oil and Gas Reporting” (the “Release”). The disclosure requirements under this Release will permit reporting of oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices and the use of new technologies to determine proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies will also be allowed to disclose probable and possible reserves in SEC filings. In addition, companies will be required to report the independence and qualifications of its reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. The new disclosure requirements become effective for the Company beginning with our annual report on Form 10-K for the year ended March 31, 2010. We are currently evaluating the impact of this Release on our oil and gas accounting disclosures.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Not applicable.

Item 8. Financial Statements and Supplementary Data.

Our consolidated financial statements, together with the independent registered public accounting firm's report of RBSM LLP, begin on page F-1, immediately after the signature page.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Not Applicable.

Item 9A. (T). Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (“Exchange Act”), as of March 31, 2009. Disclosure controls and procedures are those controls and procedures designed to provide reasonable assurance that the information required to be disclosed in our Exchange Act filings is (1) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission’s rules and forms, and (2) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2009, our disclosure controls and procedures were effective.

Management’s Annual Report on Internal Control Over Financial Reporting

Management, including our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a – 15(f). Management conducted an assessment as of March 31, 2009 of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of March 31, 2009, based on criteria in Internal Control – Integrated Framework issued by the COSO.

Our assessment identified that an adequate standard had been met in compliance with our internal controls framework. Our assessment was an internal review by management, based on an evaluation of individual controls and did not involve any independent review or testing. In addition our controls framework was not enhanced over the year to March 31, 2009 due to a lack of resources, although there was no material change to our business or operations that necessitated such. There are certain sections of our internal controls matrix against which there has been no or minimal relevant business activity. Should such activity arise in the future there is a risk that we will have insufficient resources to ensure effectiveness with the existing controls.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements should they occur. Also, 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 control procedure may deteriorate.

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

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended March 31, 2009 that has materially affected, or is 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.

The information required to be contained in this Item is incorporated by reference from Part I of this report and by reference either to our definitive proxy statement to be filed with respect to our 2009 annual meeting or via the filing of an amendment to this Annual Report on Form 10-K.

Item 11. Executive Compensation.

The information required to be contained in this Item is incorporated either by reference to our definitive proxy statement to be filed with respect to our 2009 annual meeting under the heading “Executive Compensation” or via the filing of an amendment to this Annual Report on Form 10-K.

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

This information required to be contained in this Item is incorporated either by reference to our definitive proxy statement to be filed with respect to our 2009 annual meeting under the heading “Principal Stockholders and Security Ownership of Management” or via the filing of an amendment to this Annual Report on Form 10-K.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

The information required to be contained in this Item is incorporated either by reference to our definitive proxy statement to be filed with respect to our 2009 annual meeting under the heading “Certain Transactions” or via the filing of an amendment to this Annual Report on Form 10-K.

Item 14. Principal Accountant Fees and Services.

The information required to be contained in this Item is incorporated either by reference to our definitive proxy statement to be filed with respect to our 2009 annual meeting or via the filing of an amendment to this Annual Report on Form 10-K.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

The following documents are filed as a part of this report or incorporated herein by reference:

(1) Our Consolidated Financial Statements are listed on page F-1 of this Annual Report.

(2) Financial Statement Schedules:

None

(3) Exhibits:

The following documents are included as exhibits to this Annual Report:

Exhibit Number		Description
3.1		Restated Articles of Incorporation of Index Oil and Gas Inc., Inc. (1)

3.2		Bylaws of Index Oil and Gas Inc. (2)

10.1		Acquisition Agreement between Index Oil and Gas Inc., certain stockholders of Index Oil & Gas Ltd, and Briner Group Inc. dated January 20, 2006. (3)

10.2		Form of Share and Warrant Exchange Agreement entered into by and between Index Oil and Gas Inc., Inc. and certain Index Oil & Gas Ltd stockholders. (3)

10.3+		Employment Agreement entered into by and between Index Oil & Gas Ltd and Lyndon West, dated January 20, 2006. (3)

10.4+		Employment Agreement entered into by and between Index Oil & Gas Ltd and Andy Boetius, dated January 20, 2006. (3)

10.5+		Employment Agreement entered into by and between Index Oil & Gas Ltd and Daniel Murphy, dated January 20, 2006. (3)

10.6+		Letter Agreement entered into by and between Index Oil & Gas Ltd and David Jenkins, dated January 20, 2006. (3)

10.7+		Letter Agreement entered into by and between Index Oil & Gas Ltd and Michael Scrutton, dated January 20, 2006. (3)

10.8+		Employment Agreement entered into by and between Index Oil and Gas Inc. and John G. Williams, dated August 29, 2006. (4)

10.9		Form of Subscription Agreement dated as of January 20, 2006. (3)

10.10		Form of Subscription Agreement dated as of August 29 and October 4, 2006. (5)

10.11		Form of Registration Rights Agreement dated as of August 29, 2006. (5)

10.12+		Index Oil and Gas Inc. 2006 Incentive Stock Option Plan. (6)

10.13		Securities Purchase Agreement dated as of November 5, 2007. (7)

10.14		Form of Warrant to Purchase Common Stock. (7)

10.15+		Agreement for Exploration, Production and Strategic Services dated February 1, 2008 between the Company and ConRon Consulting Inc., as amended by Addendum #1 dated June 1, 2008 and Addendum #2 dated July 1, 2008. (8)

10.16+		Amended and Restated Agreement for Exploration, Production and Strategic Services between Index Oil and Gas Inc. and ConRon Consulting Inc. dated December 8, 2008. (9)

10.17+		Amended Employment Agreement of Daniel Murphy, dated March 4, 2009. (10)

10.18+		Amended Employment Agreement of Lyndon West, dated March 4, 2009. (10)

10.19+		Amended Employment Agreement of Andrew Boetius, dated March 4, 2009. (10)

14.1		Code of Ethics and Business Conduct for officers, directors and employees of Index Oil and Gas Inc. adopted by the Company’s Board of Directors on March 31, 2006. (11)

21.1		List of subsidiaries of the Company. *

23.1		Consent of RBSM LLP. *

23.2		Consent of Ancell Energy Consulting, Inc. *

31.1		Certification by Chief Executive Officer required by Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act. *

31.2		Certification by Chief Financial Officer required by Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act. *

32.1		Certification by Chief Executive Officer required by Rule 13a-14(b) or Rule 15d-14(b) of the Exchange Act and Section 1350 of Chapter 63 of Title 18 of the United States Code. *

32.2		Certification by Chief Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) of the Exchange Act and Section 1350 of Chapter 63 of Title 18 of the United States Code. *

* Filed Herewith

+ Compensatory plan or arrangement

(1) Incorporated by reference to the Company’s Current Report filed on Form 8-K with the SEC on September 5, 2008.

(2) Incorporated by reference to the Company’s Current Report filed on Form 8-K with the SEC on October 9, 2008.

(3) Incorporated by reference to the Company’s Amended Current Report filed on Form 8-K/A with the SEC on March 15, 2006.

(4) Incorporated by reference to the Company’s Current Report filed on Form 8-K with the SEC on September 8, 2006.

(5) Incorporated by reference to the Company’s Current Report filed on Form 8-K with the SEC on September 11, 2006.

(6) Incorporated by reference to the Company’s Registration Statement filed on Form S-8 with the SEC on October 3, 2007.

(7) Incorporated by reference to the Company’s Current Report filed on Form 8-K with the SEC on February 29, 2008.

(8) Incorporated by reference to the Company’s Current Report filed on Form 8-K with the SEC on July 8, 2008.

(9) Incorporated by reference to the Company’s Current Report filed on Form 8-K with the SEC on December 12, 2008.

(10) Incorporated by reference to the Company’s Current Report filed on Form 8-K with the SEC on March 6, 2009.

(11) Incorporated by reference to the Company’s Annual Report filed on Form 10-KSB with the SEC on April 10, 2006.

SIGNATURES

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

	INDEX OIL AND GAS INC.

Date: July 10, 2009	By:	/s/ Lyndon West
		Lyndon West
		President and Chief Executive Officer

	INDEX OIL AND GAS INC.

Date: July 10, 2009	By:	/s/ Andrew Boetius
		Andrew Boetius
		Chief Financial Officer, (Principal Accounting Officer and Principal Financial Officer)

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

Signature	Title	Date

/s/ Daniel Murphy	Chairman of the Board	July 10, 2009
Daniel Murphy

/s/ Lyndon West	Chief Executive Officer and Director	July 10, 2009
Lyndon West

/s/ Andrew Boetius	Chief Financial Officer, (Principal Accounting Officer),	July 10, 2009
Andrew Boetius	(Principal Financial Officer) and Director

/s/ David Jenkins	Director	July 10, 2009
David Jenkins

Index to Consolidated Financial Statements


			Page
Report of Independent Registered Public Accounting Firm			F-2
Consolidated Balance Sheets at March 31, 2009 and 2008			F-3
Consolidated Statements of Losses for the Years Ended March 31, 2009 and 2008			F-4
Consolidated Statement of Stockholders’ Equity for the Two Years Ended March 31, 2009 and 2008			F-5
Consolidated Statements of Cash Flows for the Years Ended March 31, 2009 and 2008			F-6
Notes to the Consolidated Financial Statements			F-7
Supplemental Oil and Gas Information (Unaudited)			F-25

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

Index Oil and Gas Inc.

Houston, USA

We have audited the accompanying consolidated balance sheets of Index Oil and Gas Inc. and subsidiaries (the “Company”) as of March 31, 2009 and 2008 and the related consolidated statements of losses, stockholders’ equity, and cash flows for each of the two years in the period ended March 31, 2009. These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on the financial statements based upon our audits.

We have conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe 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 financial position of Index Oil and Gas Inc. at March 31, 2009 and 2008 and the results of its operations and its cash flows for each of the two years in the period ended March 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in the Note 1, the Company has suffered recurring losses from operations and also, its current liabilities exceeded current assets as of March 31, 2009, which raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to this matter are described in Note 1. The accompanying statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ RBSM LLP

New York, New York

July 10, 2009

F-2

INDEX OIL AND GAS INC.

CONSOLIDATED BALANCE SHEETS

MARCH 31, 2009 AND 2008

	2009			2008
ASSETS
Current Assets:
Cash and cash equivalents (Note 2)	$	335,817		$	2,537,302
Trade receivables (Note 3 and Note 13)		326,737			970,794
Other receivables (Note 2)		5,144			5,402
Other current assets (Note 2)		41,157			43,460
Total Current Assets		708,855			3,556,958

Oil & Gas Properties, full cost, net of accumulated depletion (Notes 2, 4, 7 and 9)		6,263,537			12,595,091
Property and Equipment, net of accumulated depreciation (Notes 2 and 4)		21,595			26,031
Total Oil & Gas Properties and Property and Equipment		6,285,132			12,621,122

Total Assets	$	6,993,987		$	16,178,080

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued expenses	$	978,856		$	1,025,894
Asset Retirement Obligation (Notes 2 and 7)		125,716			-
Total Current Liabilities		1,104,572			1,025,894

Long-Term Liabilities:
Asset Retirement Obligation (Notes 2 and 7)		14,998			88,209
Total Liabilities		1,119,570			1,114,103

Commitments and Contingencies (Note 9)		-			-

Stockholders Equity: (Notes 10, 11 and 12)
Preferred stock, par value $0.001, 10 million shares authorized, no shares issued and outstanding at March 31, 2009 and 2008 (see Note 10)		-			-

Common stock, par value $0.001, 500 million shares authorized, 71,636,019 and 71,369,880 issued and outstanding at March 31, 2009 and 2008, respectively (see Note 10)		71,636			71,370
Additional paid in capital		21,950,246			21,738,764
Accumulated deficit		(16,126,289	)		(6,747,667	)
Other comprehensive income (Note 2)		(21,176)			1,510
Total Stockholders’ Equity		5,874,417			15,063,977

Total Liabilities and Stockholders’ Equity	$	6,993,987		$	16,178,080

See accompanying notes to consolidated financial statements

F-3

INDEX OIL AND GAS INC.

CONSOLIDATED STATEMENT OF LOSSES

FOR THE YEARS ENDED MARCH 31, 2009 AND 2008

	2009			2008
Revenue:
Oil & gas sales (Note 2 and Note 13)	$	2,828,751		$	1,705,593

Operating Expenses:
Operating costs		704,183			303,474
Depletion, depreciation and amortization (Note 4)		2,094,481			1,096,229
Impairment charges (Note 4)		7,002,472			-
General and administrative expenses		2,430,443			2,457,929
Total Operating Expenses		12,231,579			3,857,632

Loss from Operations		(9,402,828	)		(2,152,039	)

Other Income:
Interest income		24,207			205,609
Total Other Income		24,207			205,609

Loss before Income Taxes		(9,378,621	)		(1,946,430	)

Income Taxes Benefit (Note 8)		-			-

Net Loss	$	(9,378,621	)	$	(1,946,430	)


Loss per share (Note 12):
Basic and assuming dilution	$	(0.13	)	$	(0.03	)
Weighted average shares outstanding:
Basic and assuming dilution		71,477,513			66,288,104

See accompanying notes to consolidated financial statements

F-4

INDEX OIL AND GAS INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

FOR THE TWO YEARS ENDED MARCH 31, 2009

	Common Stock				Additional Paid in			(Accumulated			Other Comprehensive			Total Stockholders’
	Shares		Amount		Capital			Deficit)			Income/(Loss)			Equity
Balance at March 31, 2007		65,737,036	$	65,737	$	19,043,734		$	(4,801,237	)	$	15,399		$	14,323,633
Issuance of common stock on private offerings		5,541,182		5,541		2,765,049			-			-			2,770,590
Stock issue costs		-		-		(382,171	)		-			-			(382,171	)
Stock compensation, net of tax of $0		-		-		302,911			-			-			302,911
Issuance of stock upon vesting of stock award		25,000		25		(25	)		-			-			-
Issuance of stock upon exercise of warrants		66,662		67		9,266			-			-			9,333
Other comprehensive income foreign currency translation adjustment		-		-		-			-			(13,889	)		(13,889	)
Net loss		-		-		-			(1,946,430	)		-			(1,946,430	)
Balance at March 31, 2008		71,369,880	$	71,370	$	21,738,764		$	(6,747,667	)	$	1,510		$	15,063,977
Stock compensation, net of tax of $0		-		-		211,748			-			-			211,748
Stock Awards		266,139		266		(266	)		-			-			-
Other comprehensive income foreign currency translation adjustment		-		-		-			-			(22,687	)		(22,687	)
Net loss		-		-		-			(9,378,621	)		-			(9,378,621	)
Balance at March 31, 2009		71,636,019	$	71,636	$	21,950,246		$	(16,126,288	)	$	(21,177)		$	5,874,417

See accompanying notes to consolidated financial statements

F-5

INDEX OIL AND GAS INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

FOR THE YEARS ENDED MARCH 31, 2009 AND 2008

	2009			2008
Cash Flows From Operating Activities:
Net loss	$	(9,378,621	)	$	(1,946,430	)
Adjustments to reconcile net loss to net cash (used in) operating activities:
Non cash stock based compensation cost		211,748			302,911
Depreciation, amortization and impairment		9,096,953			1,096,229
Allowance for doubtful accounts		49,320			-
Decrease (Increase) in receivables		597,034			(859,427	)
(Decrease) Increase in accounts payable and accrued expenses		(84,134	)		211,968
Net Cash Provided By (Used In) Operating Activities		492,300			(1,194,749	)

Cash Flows From Investing Activities:
Payments for property and equipment		(4,070	)		(18,094	)
Payments for oil and gas properties		(2,704,388	)		(8,774,058	)
Net Cash (Used In) Investing Activities		(2,708,458	)		(8,792,152	)

Cash Flows From Financing Activities:
Proceeds from issuance of shares		-			2,779,923
Payment for share issue costs		-			(382,171	)
Net Cash Provided by Financing Activities		-			2,397,752

Effect of exchange rate changes on cash and cash equivalents		14,674			(14,674)

Net (Decrease) in Cash And Cash Equivalents		(2,201,485	)		(7,603,823)

Cash and cash equivalents at beginning of year	$	2,537,302		$	10,141,125
Cash and cash equivalents at the end of year	$	335,817		$	2,537,302

Supplemental Disclosures of Cash Flow Information:
Cash received during the year for interest	$	24,207		$	205,608
Cash paid during the year for taxes	$	-		$	-

Non-cash Financing and Investing Transactions:
Non-cash stock based compensation cost	$	211,747		$	302,911

See accompanying notes to consolidated financial statements

F-6

INDEX OIL AND GAS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2009 AND 2008

NOTE 1 - ORGANIZATION AND OPERATIONS OF THE COMPANY

Organization

We are an independent oil and natural gas company engaged in the acquisition, exploration, development production and sale of oil and natural gas properties in North America. We have interests in properties in Kansas, Louisiana and Texas.

Index Oil and Gas Inc. (“Index”, Index Inc.”, “the Company” or “we”, “us”, or “our”) was incorporated in March 2004 under the laws of the State of Nevada and is the parent company with four group subsidiaries: Index Oil & Gas Limited (“Index Ltd”), a United Kingdom holding company, which provides management services to the Company, and United States operating subsidiaries; Index Oil & Gas (USA) LLC (“Index USA”), an operating company; Index Investments North America Inc. (“Index Investments”); and Index Offshore LLC (“Index Offshore”), a wholly owned subsidiary of Index Investments and also an operating company. Index Inc., through its subsidiaries, is engaged in exploration, appraisal, development, production and sale of oil and natural gas. The Company does not currently operate any of its properties and sells its oil and gas production to domestic purchasers.

Overview

For the fiscal year ended March 31, 2009, Index had year-on-year increases in production and revenues but a decrease in reserves. The Company holds an interest in the Alligator Bayou and Garwood prospect areas, and in the first wells drilled on each, Armour Runnells 1 ST and Cochran 1, respectively, which represent the most significant potential in the Company’s portfolio. Index remains free of borrowings.

Reserves decreased approximately 60% from 219.469 MBoe (thousand barrels of oil equivalent) proven reserves at March 31, 2008 to 87.702 MBoe at March 31, 2009. Production rose approximately 67% from 28.6 MBoe for the fiscal year ended March 31, 2008 to 47.8 MBoe for the fiscal year ended March 31, 2009. Correspondingly, revenues increased approximately 65% from $1.7 million for the fiscal year ended March 31, 2009 to $2.8 million for the year ended March 31, 2009.

These consolidated financial statements have been prepared assuming that the Company will continue as a going concern. We have suffered recurring losses from operations. The continuation of our company as a going concern is dependent upon our company attaining and maintaining profitable operations and raising additional capital. We are actively and currently seeking additional funding through various methods, but due to current market conditions funding may not be readily available. In addition our current liabilities exceeded our current assets as at March 31, 2009 and at the date of this report. These conditions indicate the existence of a material uncertainty which may cast significant doubt about our ability to continue as a going concern. These consolidated financial statements do not include the adjustments that would result if the Company was unable to continue as a going concern. Management is currently considering plans should current efforts to secure new funding not be successful. These could include the establishment of a form of liquidating trust to hold the assets of the Company for the benefit of shareholders or the sale of the Company’s assets as part of a liquidation and, after discharging obligations, distributing the remaining proceeds, if any, to shareholders. Our Board of Directors is also actively considering deregistering from the Securities Exchange Act, if possible, if in its best judgment the costs of the requirements of being a compliant public company outweigh the benefits to shareholders and if we are eligible to deregister.

Operations

We own producing and non-producing oil and natural gas properties in Kansas, Louisiana, and Texas.

Our Kansas properties represent a very low risk, low cost, low working interest, and limited upside project and which is not expected to be a significant contributor to future growth. Our working interest in the Kansas wells is either 5% for wells drilled in Stafford County or 3.25% for wells drilled in Barton County, and the net revenue interest is either approximately 4.155% or 2.64%, respectively. The operating economics of our Kansas wells are very sensitive to the relationship of oil price and operating costs and as at March 31, 2009 a number of wells were shut in or were producing marginally.

The Company’s onshore drilling program in Louisiana comprises its interest in the Walker 1 well (WI 12.5%, approximate NRI 9.36%) and the Shadyside 1 well (30% WI, 22.5% NRI). Future production from the Walker well, if any, is expected to be marginally economic. The Shadyside 1 well has experienced production issues and had workover operations performed which were unsuccessful in restoring production. The Company has fully written off its proved reserves on the well and is in receipt of a recommendation to plug and abandon the well from the operator.

As at March 31, 2009 we carried proved reserves against the following Texas wells:

F-7

Outlar 1; Wharton County; WI 10.9% (9.38% after prospect payout), NRI 8.2% (7.0% after prospect payout).

Ducroz 1; Brazoria County; WI 7.5%, NRI 5.25%.

Hawkins 1; Matagorda County; WI 12.5%, NRI 10.01%.

Cochran 1; Colorado County; WI 5%, NRI 3.75%.

The Company also holds an interest in the following exploration projects in Texas:

Alligator Bayou prospect:

The Alligator Bayou prospect is a deep Wilcox trend high impact exploration prospect, located in Matagorda County, Texas, of approximately 10,000 acres defined by 2D seismic. The Armour-Runnells #1 ST exploratory well has been drilled to a total depth of 23,830 feet, has encountered multiple sands with logged pay and is currently awaiting the commencement of phase 2 testing operations. Index holds a 5% WI and a 3.5% NRI in the well and leases over the prospect.

Garwood field:

The Garwood field is upthrown to a major Wilcox expansion fault, located in Colorado County, Texas. The Cochran #1 well tested zones at approximately 16,600 feet and 13,800 feet, and is currently producing from the upper zone. The well has proved up further development and probable locations. Index holds a 5% WI and a 3.75% NRI in the Cochran #1 well and leases over the prospect.

We also hold leases in Texas in: i) the Supple Jack Creek lease area, at a 20% WI, in which a first well, HNH Gas Unit 1, was drilled and is currently suspended pending further evaluation of potential logged pay intervals; ii) the West Wharton prospect area, on which the Outlar 1 well was drilled. The second well, Stewart 1, including a sidetrack in which Index did not participate, was a dry hole and the overall project is now under review.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows:

Principles of Consolidation

The consolidated financial statements as of March 31, 2009 and 2008 and for the years ended March 31, 2009 and 2008 include the accounts of the Company and its wholly owned subsidiaries after eliminating all significant intercompany accounts and transactions.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes, dismantlement and abandonment costs, estimates to certain oil and gas revenues and expenses and estimates of proved oil and natural gas reserve quantities used to calculate depletion, depreciation and impairment of proved oil and natural gas properties and equipment.

Correction of Errors

The Company adopted SFAS 154, “Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3 (“SFAS 154”)” in April 1, 2007, in which it changed the requirements for the accounting for and the reporting of a change in accounting principle. The Company requires that a new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment is made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the balance sheet) for that period rather than being reported in the statement of operations. When it is impracticable to determine the cumulative effect of applying a change in accounting principle to all prior periods, The Company applies the new accounting principle as if it were adopted prospectively from the earliest date practicable. The Company will also revise previously issued financial statements to reflect the correction of an error, should one occur, and limit the application to the direct effects of the change. Indirect effects of a change in accounting principle will be recognized in the period of the accounting change. The Company will continue to account for a change in accounting estimate in accordance with APB 20. The adoption of this pronouncement had no impact to the Company’s consolidated financial position or results of operations.

F-8

Cash and Cash Equivalents, and Concentrations of Credit Risk

Cash and cash equivalents represent cash in banks. The Company considers any highly liquid debt instruments purchased with a maturity date of three months or less to be cash equivalents. The Company’s accounts receivable are concentrated among entities engaged in the energy industry, within the United States. Financial instruments and related items, which potentially subject the Company to concentrations of credit risk, consist primarily of cash, cash equivalents and related party receivables. The Company places its cash and temporary cash investments with credit quality institutions. At times, such investments may be in excess of the FDIC insurance limit.

Accounting for Bad Debts and Allowances

Bad debts and allowances are provided based on historical experience and management's evaluation of outstanding accounts receivable. Management periodically evaluates past due or delinquency of accounts receivable in evaluating its allowance for doubtful accounts. For oil and gas sales receivables we generally only consider booking an allowance if and when a specific instance of non payment occurs. Allowance for doubtful accounts at was $49,320 at March 31, 2009 and $nil at March 31, 2008.

Other Current Assets

Other receivables at March 31, 2009 and 2008, of $5,144 and $5,402, respectively consist primarily of value added tax recoverable in the United Kingdom by the Company. Other current assets of $41,157 and $43,460 at March 31, 2009 and 2008 consist of prepaid expenses.

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development of properties within a relatively large geopolitical cost center are capitalized when incurred and are amortized as mineral reserves in the cost center are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. In some cases, however, certain significant costs, such as those associated with offshore U.S. operations, are deferred separately without amortization until the specific property to which they relate is found to be either productive or nonproductive, at which time those deferred costs and any reserves attributable to the property are included in the computation of amortization in the cost center. All costs incurred in oil and gas producing activities are regarded as integral to the acquisition, discovery, and development of whatever reserves ultimately result from the efforts as a whole, and are thus associated with the Company’s reserves. The Company capitalizes internal costs directly identified with performing or managing acquisition, exploration and development activities. The Company has not capitalized any internal costs or interest at March 31, 2009 and 2008. Unevaluated costs are excluded from the full cost pool and are periodically evaluated for impairment rather than amortized. Upon evaluation, costs associated with productive properties are transferred to the full cost pool and amortized. Gains or losses on the sale of oil and natural gas properties are generally included in the full cost pool unless the entire pool is sold.

Capitalized costs and estimated future development costs are amortized on a unit-of-production method based on proved reserves associated with the applicable cost center. The Company has assessed the impairment for oil and natural gas properties for the full cost pool at March 31, 2009 and 2008 and will assess quarterly thereafter using a ceiling test to determine if impairment is necessary. Specifically, the net unamortized costs for each full cost pool less related deferred income taxes should not exceed the following: (a) the present value, discounted at 10%, of future net cash flows from estimated production of proved oil and gas reserves plus (b) all costs being excluded from the amortization base plus (c) the lower of cost or estimated fair value of unproved properties included in the amortization base less (d) the income tax effects related to differences between the book and tax basis of the properties involved. The present value of future net revenues should be based on current prices, with consideration of price changes only to the extent provided by contractual arrangements, as of the latest balance sheet presented. The full cost ceiling test must take into account the prices of qualifying cash flow hedges in calculating the current price of the quantities of the future production of oil and gas reserves covered by the hedges as of the balance sheet date. In addition, the use of the hedge-adjusted price should be consistently applied in all reporting periods and the effects of using cash flow hedges in calculating the ceiling test, the portion of future oil and gas production being hedged, and the dollar amount that would have been charged to income had the effects of the cash flow hedges not been considered in calculating the ceiling limitation should be disclosed. Any excess is charged to expense during the period that the excess occurs. The Company did not have any hedging activities during the two year period ended March 31, 2009. Application of the ceiling test is required for quarterly reporting purposes, and any write-downs cannot be reinstated even if the cost ceiling subsequently increases by year-end. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income. Abandonment of properties is accounted for as adjustments of capitalized costs with no loss recognized.

Other Property, Plant and Equipment

Other property, plant and equipment primarily includes computer equipment, which is recorded at cost and depreciated on a straight-line basis over useful lives of five years. Repair and maintenance costs are charged to expense as incurred while acquisitions are capitalized as additions to the related assets in the period incurred. Gains or losses from the disposal of property, plant and equipment are recorded in the period incurred. The net book value of the property, plant and equipment that is retired or sold is charged to accumulated depreciation and amortization, and the difference is recognized as a gain or loss in the results of operations in the period the retirement or sale transpires.

F-9

Comprehensive Income

Statement of Financial Accounting Standards No. 130 (“SFAS 130”), “Reporting Comprehensive Income,” establishes standards for reporting and displaying of comprehensive income, its components and accumulated balances. Comprehensive income is defined to include all changes in equity except those resulting from investments by owners and distributions to owners. Among other disclosures, SFAS 130 requires that all items that are required to be recognized under current accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements. The Company reports foreign currency translation adjustments within other comprehensive income in the periods presented.

Net Earnings (Losses) Per Common Share

The Company computes earnings (losses) per share under Statement of Financial Accounting Standards No. 128, "Earnings Per Share" (“SFAS 128”). Net earnings (losses) per common share is computed by dividing net income (loss) by the weighted average number of shares of common stock and dilutive common stock equivalents outstanding during the year. Dilutive common stock equivalents consist of shares issuable upon conversion of convertible notes payable and the exercise of the Company's stock options and warrants (calculated using the treasury stock method). During the year ended March 31, 2009 and 2008, common stock equivalents are not considered in the calculation of the weighted average number of common shares outstanding because they would be anti-dilutive, thereby decreasing the net loss per common share.

Revenue Recognition

The Company uses the sales method of accounting for the recognition of natural gas and oil revenues. The Company has an agreement with the operators of its properties to sell, on its behalf, production from the properties for which it has working interest ownership. Since there is a ready market for natural gas, crude oil and natural gas liquids (“NGLs”), production is sold at various locations at which time title and risk of loss pass to the buyer. Revenue is recorded when title passes based on the Company’s net interest or nominated deliveries of production volumes. The Company records its share of revenues based on sales volumes and contracted sales prices. The sales price for natural gas, natural gas liquids and crude oil are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents once received by the Company. Historically, these adjustments have been insignificant. In addition, natural gas and crude oil volumes sold are not significantly different from the Company’s share of production.

The Company receives its share of revenue after all calculated royalties are paid on natural gas, crude oil and NGLs in accordance with the particular contractual provisions of the lease, license or concession agreements and the laws and regulations applicable to those agreements. Therefore, there is no Royalties payable on the Company’s Consolidated Balance Sheet.

Imbalances. When actual natural gas sales volumes exceed delivered share of sales volumes, an over-produced imbalance could occur. To the extent an over-produced imbalance exceeds the remaining estimated proved natural gas reserves for a given property; the Company would record a liability. At and during the years ended March 31, 2009 and 2008, the Company had no imbalances.

Derivative and Hedging

The Company has also not entered into any derivative contracts for any purpose from the period of inception through March 31, 2009.

Foreign Currency Translation

The Company translates the foreign currency financial statements in accordance with the requirements of Statement of Financial Accounting Standards No. 52, “Foreign Currency Translation.” Assets and liabilities of non-U.S. subsidiaries whose functional currency is not the U.S. dollar are translated into U.S. dollars at fiscal year-end exchange rates. Revenue and expense items are translated at average exchange rates prevailing during the fiscal year. Translation adjustments are included in accumulated other comprehensive loss in the equity section of the Consolidated Balance Sheet and totaled $(22,687) and $(13,889) for the years ended March 31, 2009 and 2008, respectively, and foreign currency transaction (losses)/gains are included in the Consolidated Statement of Operations

Income Taxes

Deferred income taxes are provided using the asset and liability method for financial reporting purposes in accordance with the provisions of Statements of Financial Standards No. 109, “Accounting for Income Taxes”. Under this method, deferred tax assets and liabilities are recognized for temporary differences between the tax bases of assets and liabilities and their carrying values for financial reporting purposes and for operating loss and tax credit carry forwards. 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 removed or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the Consolidated Statements of Operations in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

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Segment Information

Statement of Financial Accounting Standards No. 131, “Disclosures about Segments of an Enterprise and Related Information” (“SFAS 131”) establishes standards for reporting information regarding operating segments in annual financial statements and requires selected information for those segments to be presented in interim financial reports issued to stockholders. SFAS 131 also establishes standards for related disclosures about products and services and geographic areas. Operating segments are identified as components of an enterprise about which separate discrete financial information is available for evaluation by the chief operating decision maker, or decision-making group, in making decisions how to allocate resources and assess performance. The information disclosed herein materially represents all of the financial information related to the Company’s principal operating segment.

Stock Based Compensation

In December 16, 2004, the Financial Accounting Standards Board ("FASB") published Statement of Financial Accounting Standards No. 123 (Revised 2004), Share-Based Payment ("SFAS 123-R"). SFAS 123-R requires that compensation cost related to share-based payment transactions be recognized in the financial statements. Share-based payment transactions within the scope of SFAS 123-R include stock warrants, restricted stock plans, performance-based awards, stock appreciation rights, and employee share purchase plans.

On April 14, 2005, the SEC amended the effective date of the provisions of SFAS 123-R. Accordingly, the Company adopted the revised standard on January 1, 2006. Since there were no outstanding options at March 31, 2005 and the Company had no stock forfeitures since date of inception to March 31, 2005, there was no impact upon adoption of SFAS 123-R to the company’s financial position, results of operations or cash flows. See Notes 10 and 13 for further discussion of these transactions.

Asset Retirement Obligations

Our financial statements reflect the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. SFAS No.143 provides that, if the fair value for an asset retirement obligation can be reasonably estimated, the liability should be recognized in the period when it is incurred. Oil and gas producing companies incur this liability upon acquiring or drilling a well. Under the method prescribed by SFAS No.143, the retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to producing properties on the Consolidated Balance Sheet. Periodic accretion of discount of the estimated liability is recorded, as appropriate, as an expense in the Consolidated Statement of Operations. The Company’s asset retirement obligations relate to the abandonment of oil producing wells. The Company has recognized an asset retirement liability of $140,714 and $88,209 at March 31, 2009 and 2008, respectively. It is estimated that salvage values of well equipment will be equal, in aggregate, to the cost of plugging and abandoning these wells at that point, and this estimate has been taken into account in the calculation of accretion expense.

Long-Lived Assets

The Company has adopted Statement of Financial Accounting Standards No. 144 (SFAS 144). The Statement requires that long-lived assets and certain identifiable intangibles held and used by the Company be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Events relating to recoverability may include significant unfavorable changes in business conditions, recurring losses, or a forecasted inability to achieve break-even operating results over an extended period. The Company evaluates the recoverability of long-lived assets based upon forecasted undiscounted cash flows. Should any impairment in value be indicated, the carrying value of intangible assets will be adjusted, based on estimates of future discounted cash flows resulting from the use and ultimate disposition of the asset. SFAS No. 144 also requires assets to be disposed of be reported at the lower of the carrying amount or the fair value less costs to sell.

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Conditional Asset Retirement Obligations

In March 2005, the FASB issued FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143”, which requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability's fair value can be reasonably estimated. There was no impact of this Interpretation on the Company’s consolidated financial position, results of operations or cash flows since it currently does not have any conditional asset retirement obligations outstanding at March 31, 2009 and 2008.

Employers’ Defined Benefit Pension and Other Postretirement Plans

In September 2006, the FASB issued SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other postretirement Plans”, which improves financial reporting by requiring an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity or changes in unrestricted net asset of a net-for-profit organization. This Statement also improves financial reporting by requiring an employer to measure the funded status of a plan as of the date of its year-end statement of financial position with limited exceptions. The required date of adoption of the recognition and disclosure provisions of this Statement is as of the end of the fiscal year ending after December 15, 2006. The adoption of this statement on April 1, 2007 had no impact to the Company’s consolidated financial position, results of operations or cash flows as the Company does not currently have a defined benefit pension plan.

Certain Hybrid Instrument s . On February 16, 2006 the FASB issued SFAS 155, “Accounting for Certain Hybrid Instruments,” which amends SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” and SFAS 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS 155 allows financial instruments that have embedded derivatives to be accounted for as a whole (eliminating the need to bifurcate the derivative from its host) if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also clarifies and amends certain other provisions of SFAS 133 and SFAS 140. This statement is effective for all financial instruments acquired or issued in fiscal years beginning after September 15, 2006. The Company had no impact from the adoption of this new standard on its consolidated financial position, results of operations or cash flows as it currently does not have any hybrid instruments outstanding at March 31, 2009.

Accounting for Servicing of Financial Assets . In March 2006, the FASB issued SFAS No. 156, “ Accounting for Servicing of Financial Assets—an amendment of FASB Statement No. 140”(“ SFAS No. 156”), which amends FASB Statement No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, with respect to the accounting for separately recognized servicing assets and servicing liabilities.

This Statement:

Requires an entity to recognize a servicing asset or servicing liability each time it undertakes an obligation to service a financial asset by entering into a servicing contract in any of the following situations:

	a.	A transfer of the servicer’s financial assets that meets the requirements for sale accounting

	b.	A transfer of the servicer’s financial assets to a qualifying special-purpose entity in a guaranteed mortgage securitization in which the transferor retains all of the resulting securities and classifies them as either available-for-sale securities or trading securities in accordance with FASB Statement No. 115, Accounting for Certain Investments in Debt and Equity Securities

An acquisition or assumption of an obligation to service a financial asset that does not relate to financial assets of the servicer or its consolidated affiliates.

Requires all separately recognized servicing assets and servicing liabilities to be initially measured at fair value, if practicable.

Permits an entity to choose either of the following subsequent measurement methods for each class of separately recognized servicing assets and servicing liabilities:

Amortization method —Amortize servicing assets or servicing liabilities in proportion to and over the period of estimated net servicing income or net servicing loss and assess servicing assets or servicing liabilities for impairment or increased obligation based on fair value at each reporting date.

Fair value measurement method —Measure servicing assets or servicing liabilities at fair value at each reporting date and report changes in fair value in earnings in the period in which the changes occur.

At its initial adoption, permits a one-time reclassification of available-for-sale securities to trading securities by entities with recognized servicing rights, without calling into question the treatment of other available-for-sale securities under Statement 115, provided that the available-for-sale securities are identified in some manner as offsetting the entity’s exposure to changes in fair value of servicing assets or servicing liabilities that a servicer elects to subsequently measure at fair value.

Requires separate presentation of servicing assets and servicing liabilities subsequently measured at fair value in the statement of financial position and additional disclosures for all separately recognized servicing assets and servicing liabilities.

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This Statement requires that all separately recognized servicing assets and servicing liabilities be initially measured at fair value, if practicable. The Board concluded that fair value is the most relevant measurement attribute for the initial recognition of all servicing assets and servicing liabilities, because it represents the best measure of future cash flows. This Statement permits, but does not require, the subsequent measurement of servicing assets and servicing liabilities at fair value. An entity that uses derivative instruments to mitigate the risks inherent in servicing assets and servicing liabilities is required to account for those derivative instruments at fair value. Under this Statement, an entity can elect subsequent fair value measurement of its servicing assets and servicing liabilities by class, thus simplifying its accounting and providing for income statement recognition of the potential offsetting changes in fair value of the servicing assets, servicing liabilities, and related derivative instruments. An entity that elects to subsequently measure servicing assets and servicing liabilities at fair value is expected to recognize declines in fair value of the servicing assets and servicing liabilities more consistently than by reporting other-than-temporary impairments.

The Board decided to require additional disclosures and separate presentation in the statement of financial position of the carrying amounts of servicing assets and servicing liabilities that an entity elects to subsequently measure at fair value to address concerns about comparability that may result from the use of elective measurement methods. The Company adopted this Statement on April 1, 2007 with no impact on its consolidated financial position, results of operations or cash flows.

Income Taxes . In June 2006, the FASB issued FASB Interpretation No 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109”, which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB 109. The Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company’s adoption of this Interpretation on April 1, 2007 did not have any impact on the Company’s consolidated financial position, results of operations or cash flows.

In December 2006, the FASB issued FSP EITF 00-19-2, Accounting for Registration Payment Arrangements ("FSP 00-19-2") which addresses accounting for registration payment arrangements. FSP 00-19-2 specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB Statement No. 5, Accounting for Contingencies. FSP 00-19-2 further clarifies that a financial instrument subject to a registration payment arrangement should be accounted for in accordance with other applicable generally accepted accounting principles without regard to the contingent obligation to transfer consideration pursuant to the registration payment arrangement. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to the issuance of EITF 00-19-2, this guidance shall be effective for financial statements issued for fiscal years beginning after December 15, 2006 and interim periods within those fiscal years. The Company adopted the guidance of this FSP on April 1, 2007 and did not have any impact on its consolidated financial position, results of operations or cash flows.

F-13

Fair Value Measurements . In September 2006, the FASB issued SFAS 157, “Fair Value Measurements”, which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”), and expands disclosures about fair value measurements (“SFAS 157”). Prior to this SFAS 157, there were different definitions of fair value and limited guidance for applying those definitions in GAAP. SFAS 157 provides the definition to increase consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement. SFAS 157 clarifies that market participant assumptions include assumptions about risk, i.e. the risk inherent in a particular valuation technique used to measure fair value and/or the risk inherent in the inputs to the valuation technique. SFAS 157 expands disclosures about the use of fair value to measure assets and liabilities in interim and annual periods subsequent to initial recognition. The disclosures focus on the inputs used to measure fair value and for recurring fair value measurements using significant unobservable inputs, the effect of the measurements on earnings for the period. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including the financial statements for an interim period within that fiscal year. In November 2007, the FASB deferred the implementation of SFAS 157 for non-financial assets and liabilities until October 2008. The Company partially adopted this standard on April 1, 2008, as to financial assets and liabilities and has chosen to defer the implementation of nonfinancial assets and liabilities in accordance with the FASB deferral in Staff Position FAS 157-2. The adoption of this standard did not have an impact on its consolidated financial position results of operations or cash flows as the Company has not engaged in any financial activities to which this standard would apply. In October 2008, the FASB issued Staff Position FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active, to clarify the application of FASB Statement No. 157, Fair Value Measurements, in a market that is not active and to provide an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. The adoption of this standard and related staff positions do not have an impact on our consolidated financial position, results of operations or cash flows as the Company has not engaged in any financial activities to which this standard would apply.

In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FASB Statement No. 115” (“SFAS 159”), permitting entities to choose to measure many financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting measurement. SFAS 159 applies to all entities, including not-for profit organizations. Most of the provisions of SFAS 159 apply only to entities that elect the fair value option. However, the amendment to FASB Statement No. 115, “Accounting for Certain Investments in Debt and Equity Securities”, applies to all entities with available-for-sale and trading securities. The Company also elected to adopt this standard on April 1, 2008, but has not elected to present assets and liabilities at fair value that were not required to be measured at fair value prior to adoption of SFAS 159.

Recent Accounting Developments and New Accounting Pronouncements Not Yet Adopted

The Hierarchy of Generally Accepted Accounting Principles. In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States (the GAAP hierarchy). SFAS 162 is effective following the SEC’s approval of the Public Company Accounting Oversight Board (PCAOB) amendments to AU Section 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles , and is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. An entity that has and continues to follow an accounting treatment in category (c) or category (d) as of March 15, 1992, need not change to an accounting treatment in a higher category ((b) or (c)) if its effective date was before March 15, 1992. For pronouncements whose effective date is after March 15, 1992, and for entities initially applying an accounting principle after March 15, 1992 (except for EITF consensus positions issued before March 16, 1992, which become effective in the hierarchy for initial application of an accounting principle after March 15, 1993), an entity shall follow this Statement. Any effect of applying the provisions of SFAS 162 shall be reported as a change in accounting principle in accordance with FASB Statement No. 154,

F-14

Accounting Changes and Error Corrections (“SFAS 154”). An entity shall follow the disclosure requirements of SFAS 154, and additionally, disclose the accounting principles that were used before and after the application of the provisions of SFAS 154 and the reason why applying SFAS 154 resulted in a change in accounting principle. The Company does not expect the adoption of SFAS 162 to have a material impact on its consolidated financial position, results of operations or cash flows.

Business Combinations . In December 2007, the FASB issued SFAS No. 141(R), "Business Combinations" ("SFAS 141(R)"), which replaces SFAS No. 141. SFAS No. 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquired and the goodwill acquired. The Statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for fiscal years beginning after December 15, 2008. The adoption of SFAS 141(R) will have an impact on accounting for business combinations once adopted, but the effect will be dependent upon acquisitions after that time.

Noncontrolling Interests . In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements - an amendment of Accounting Research Bulletin No. 51" ("SFAS 160"), which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent's ownership interest and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. The Statement also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. SFAS 160 is effective for fiscal years beginning after December 15, 2008. The Company does not currently have any noncontrolling interests in subsidiaries, but once adopted, the effects will be dependent upon acquisitions after that time.

Disclosures about Derivative Instruments and Hedging Activities . In May 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an Amendment to FASB Statement No. 133” (“SFAS 161”). Statement No. 133, Accounting for Derivative Instruments and Hedging Activities , establishes, among other things, the disclosure requirements for derivative instruments and for hedging activities (“Statement 133”). SFAS 161 amends and expands the disclosure requirements of Statement 133 with the intent to provide users of financial statements with an enhanced understanding of:

	a.	How and why an entity uses derivative instruments.
	b.	How derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations.
	c.	How derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows.

To meet those objectives, SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS 161 shall be effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. Early application is encouraged. SFAS 161 encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption. In years after initial adoption, this Statement requires comparative disclosures only for periods subsequent to initial adoption In September 2008, the FASB issued Staff Position 133-1 and FASB Interpretation No. 45-4, “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161”, which addressed various issues related to FASB No. 133 and FIN 45, but also clarified the effective date of SFAS 161 to be any period, annual or interim beginning after November 15, 2008. The Company is adopting SFAS 161 for its next interim period. The adoption of SFAS 161 is not expected to have an impact on the Company’s consolidated financial position, results of operations or cash flows as the Company has not engaged in any derivative instruments or hedging activities.

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In June 2009 the FASB issued SFAS 166, “Accounting for Transfers of financial Assets — an amendment of FASB Statement No. 140” (SFAS 166). SFAS 166 eliminates the concept of a qualifying special-purpose entity, creates more stringent conditions for reporting a transfer of a portion of a financial asset as a sale, clarifies other sale-accounting criteria, and changes the initial measurement of a transferor’s interest in transferred financial assets. SFAS No. 166 is applicable for annual periods after November 15, 2009 and interim periods therein and thereafter. The adoption of SFAS 166 is not expected to have an impact on the Company’s consolidated financial position, results of operations or cash flows.

In June 2009 the FASB issued SFAS 167, “Amendments to FASB Interpretation No. 46(R)” (SFAS 167). SFAS 167 eliminates Interpretation 46(R)’s exceptions to consolidating qualifying special-purpose entities, contains new criteria for determining the primary beneficiary, and increases the frequency of required reassessments to determine whether a company is the primary beneficiary of a variable interest entity. SFAS 167 also contains a new requirement that any term, transaction, or arrangement that does not have a substantive effect on an entity’s status as a variable interest entity, a company’s power over a variable interest entity, or a company’s obligation to absorb losses or its right to receive benefits of an entity must be disregarded in applying Interpretation 46(R)’s provisions. SFAS No. 167 is applicable for annual periods after November 15, 2009 and interim periods thereafter. The adoption of SFAS 167 is not expected to have an impact on the Company’s consolidated financial position, results of operations or cash flows as the Company does not have any ownership of or arrangements with any variable interest entity or special-purpose entity.

NOTE 3 - TRADE RECEIVABLES

Historically, through March 31, 2009, all of the Company’s trade receivables related to its net revenue interest share of oil and gas sales have been collected, with the exception of an allowance for doubtful accounts which was recorded for $49,320 at March 31, 2009 for amounts owing that are subject to bankruptcy proceedings for SemCrude, L.P. No allowance for doubtful accounts had been recorded at March 31, 2008.

NOTE 4 - PROPERTY, PLANT AND EQUIPMENT, PROPERTY ACQUISITIONS AND DISPOSITIONS AND CAPITALIZED INTEREST

Oil and Gas Properties

Major classes of oil and gas properties under the full cost method of accounting at March 31, 2009 and 2008 consist of the following:

	March 31,
	2009		2008
Proved properties, net of cumulative impairment charges	$	4,878,182	$	11,181,430
Unevaluated and unproved properties		4,878,940		2,821,271
Gross oil and gas properties-onshore		9,757,122		14,002,701
Less: accumulated depletion		3,493,585		1,407,610
Net oil and gas properties-onshore	$	6,263,537	$	12,595,091

Included in the Company's oil and gas properties are asset retirement obligations of $140,714, comprising both current and long term items, and $88,209 as of March 31, 2009 and 2008, respectively.

Quarterly, the Company assesses the value of unamortized capitalized costs within its cost center over the discounted present value of cash flows associated with its reserves. Any excess requires an immediate write-down of its capital costs by this amount, under the full cost ceiling test.

Impairment Charges

In the year to March 31, 2009 total impairment charges under the full cost ceiling test were $7,002,472, including a charge of $792,657 in the three months to March 31, 2009, and is reported within the expense category “Depreciation, depletion, amortization and impairment”. The most significant factor causing the full year charge was the write off during the year of reserves on the Shadyside well, which represented approximately 41% of reserves at March 31, 2008, together with earlier than expected depletion on a number of other wells, leading to other reserve reductions. Also natural gas prices continued to fall in the quarter to March 31, 2009. Weighted average product prices in our March 31, 2009 reserves report, and used for the ceiling test at that date, were $4.81/mcfe or $28.85/boe .

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Proved properties are reported net of cumulative impairment charges of $7,090,020 at March 31, 2009, inclusive of the current period impairment charge, and $87,548 at March 31, 2008, respectively.

Depletion expense was $2,085,976 and $1,091,673 or $54.87 and $38.14 per barrel of production for the years ended March 31, 2009 and 2008, respectively.

At March 31, 2009 and 2008, the Company excluded the following capitalized costs from depletion, depreciation and amortization:

	March 31, 2009		March 31, 2008
Not subject to depletion-onshore:
Exploration costs	$	3,989,014	$	1,960,886
Cost of undeveloped acreage		889,926		860,385
Total not subject to depletion	$	4,878,940	$	2,821,271

It is anticipated that the cost of undeveloped acreage of $889,926 and exploration costs of $3,989,014 will be included in depreciation, depletion and amortization when the initial drilling projects are concluded. Included in exploration cost and undeveloped acreage are costs of approximately $0.4 million and $0.3 million related to undeveloped leasehold for the Supple Jack Creek and Alligator Bayou prospects, respectively, on which initial drilling and completion operations are expected to conclude in fiscal year 2010 and approximately $0.1 million related to the West Wharton Project. Exploration costs include approximately $1.7 million on the HNH Gas Unit #1 wells, drilled on the Supple Jack Creek prospect and $2.3 million on the Armour Runnells #1 ST, drilled on the Alligator Bayou prospect. Completion operations on the HNH Gas Unit #1 well were suspended in May 2008, and following a change in operator, a recommendation on the project is pending.

Acquisitions and Dispositions

There were no acquisitions or dispositions in the fiscal year ended March 31, 2009.

Other Property and Equipment

Property and equipment are stated at cost. When retired or otherwise disposed, the related carrying value and accumulated depreciation are removed from the respective accounts and the net difference less any amount realized from disposition, is reflected in earnings. For financial statement purposes, property and equipment are depreciated using the straight-line method over their estimated useful lives of the assets. Maintenance, repairs, and minor renewals are charged against earnings when incurred. Additions and major renewals are capitalized. Major assets at March 31, 2009 and 2008 were as follows:

	March 31,
	2009			2008
Computer Costs and Furniture and Fixtures, including foreign translation		$	43,649		$	42,069
Less: accumulated depreciation			22,053			16,038
Total other property and equipment		$	21,596		$	26,031

Depreciation expenses from continuing operations amounted to $8,505 and $4,556 for the years ended March 31, 2009 and 2008, respectively.

Capitalized Interest

There was no interest capitalized in property, plant and equipment at March 31, 2009 and 2008.

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NOTE 5 - COMPREHESIVE LOSS

For the years ended March 31, 2009 and 2008, comprehensive income consisted of the amounts listed below.

	Years Ended March 31,
	2009			2009			2008			2008

Accumulated other comprehensive income beginning of period				$	1,510					$	15,399
Net (loss)	$	(9,378,621	)				$	(1,946,430	)

Foreign currency translation (loss)		(22,687	)					(13,889	)
Total other comprehensive (loss)		(22,687	)		(22,687	)		(13,889	)		(13,889	)

Comprehensive (loss)	$	(9,401,308	)				$	(1,960,319	)
Accumulated other comprehensive income (loss) end of period				$	(21,177	)				$	1,510

Comprehensive loss for the years to March 31, 2009 and 2008 is stated inclusive of impairment expense of $7,002,472 and $nil, respectively, and which is a component of net loss within the measure of comprehensive loss.

NOTE 6 - NOTES PAYABLE

At March 31, 2009 and 2008, there was no outstanding debt. The Company has not entered into any term or other debt in fiscal year ended March 31, 2009 or 2008.

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NOTE 7 - ASSET RETIREMENT OBLIGATION

Activity related to the Company’s ARO during the years ended March 31, 2009 and 2008 is as follows:

	March 31,
	2009		2008
ARO as of beginning of period	$	88,209	$	41,552
Liabilities incurred during period		52,505		46,657
Liabilities settled during period		-		-
Accretion expense		-		-
Balance of ARO as of end of period	$	140,714	$	88,209

Of the total ARO, $125,716 is classified as a current liability at March 31, 2009 while $14,998 and $88,209 are classified as a long-term liability at March 31, 2009 and 2008, respectively. For each of the years ended March 31, 2009 and 2008, the Company recognized no accretion expense related to its ARO, due to the assumption of a full offset in aggregate of salvage values.

NOTE 8 - INCOME TAXES

Financial Accounting Standard No. 109 requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statement or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between financial statements and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.

At March 31, 2009 and 2007, the Company generated for federal income tax purposes a net operating loss carry forward of approximately $23.4 million and $13.8 million respectively, both inclusive of basis differences for net intangible drilling costs which are deductible for tax purposes but capitalized and depreciated for book purposes. The latest expiry date within the net operating loss carry forward at March 31, 2009 is in 2029, and this loss can be used to offset future taxable income. However, a valuation allowance of $8.4 million and $5.1 million was recorded for the years ended March 31, 2009 and 2008, respectively on the total tax provision as the Company believes it is more likely than not that the asset will not be utilized during the next year. Of the total net operating loss carryforward, the United Kingdom (“UK”) total net operating loss of approximately $1.0 million and $1.0 million for the years ended March 31, 2009 and 2008, respectively, are not expected to be utilized. The United States federal and state net operating loss carryforwards are generally subject to limitations on their annual usage. Realization of the deferred tax assets and net operating loss carryforwards is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards. The amount of the deferred tax asset considered realizable, however, might be adjusted if estimates of future taxable income during a future period are expected.

The Company’s income tax expense (benefit) from continuing operations consists of the following:

	March 31,
	2009			2008
Current
UK	$	-		$	-
US		-			-
State		-			-
Total current tax expense (benefit)		-			-

Deferred
UK		(302,465	)		(289,526	)
US		(7,026,879	)		(4,143,281	)
State		(1,054,032	)		(621,492	)
Total deferred tax expense (benefit)		(8,383,375	)		(5,054,299	)
Less valuation allowance		8,383,375			5,054,299
Total deferred tax expense (benefit)	$	-		$	-

Total tax provision-continuing operations	$	-		$	-

F-19

The following tax rates have been used in the calculation of income taxes: US federal taxation 30%, US state taxation 4.5% and UK taxation 30%.

Components of deferred tax amounts are as follows:

Deferred Tax Components	March 31,
	2009			2008
Deferred tax assets
Restricted stock compensation accrual	$	-		$	-
Share issue basis difference		-			-
Other		-			-
Oil & Gas basis differences		3,722,521			3,529,359
Depreciation		1,169,112			512,673
Net operating loss carryforward		5,518,200			2,284,516
Total gross deferred tax assets		10,409,833			6,326,548

Deferred tax liabilities
Amortization of share issue costs		-			-
Other		3,969			3,139
Foreign currency translation		-			-
Oil & Gas basis differences		-			-
Depreciation		1,241,024			521,363
Stock Compensation		781,464			747,747
Total gross deferred tax liabilities		2,026,457			1,272,249

Less valuation allowance		(8,383,375	)		(5,054,299	)
Net deferred tax assets	$	-		$	-

NOTE 9 - COMMITMENTS AND CONTINGENCIES

The Company has various commitments to oil and gas exploration and production capital expenditures related to its’ properties and projects in Kansas, Texas and Louisiana, arising out of the normal course of business. The Company is currently not involved in any material litigation matters arising from our oil and gas exploration and production activities and as such has accrued no liability with respect to litigation.

F-20

Lease Commitments

The Company does not have any capital lease commitments. The Company rents its main operating office in Houston on a month-to-month basis for which payments began in November 2005. The Company also has two leases related to corporate housing in Houston for UK based officers while periodically working at the corporate office, on a month-to-month basis and a remaining 4-month lease respectively.

Consulting Agreements

The Company has held consulting agreements with outside contractors, certain of whom are also Company stockholders. The Agreements are generally for a fixed term from inception and renewable from time to time unless either the Company or Consultant terminates such engagement by written notice.

Stockholder Matters

During the fiscal year ended March 31, 2009 at an annual general meeting stockholders approved resolutions to: re-elect Daniel L. Murphy, chairman, Lyndon West, Andrew Boetius, and David Jenkins, non-executive director, as Directors; ratify the 2008 Stock Incentive Plan; and ratify the appointment of RBSM LLP as independent auditors for the fiscal year ending March 31, 2009.

Litigation

The Company is subject to various legal proceedings and claims, which arise in the ordinary course of its business. Although occasional adverse decisions or settlements may occur, the Company believes that the final disposition of such matters will not have material adverse effect on its financial position, results of operations or liquidity. Consequently, the Company has not recorded any reserve for legal matters.

NOTE 10 - CAPITAL STOCK

During the year ended March 31, 2009, the following is a summary of the stock transactions as follows:

Balance at March 31, 2008			71,369,880

Stock awards for services			266,139

Balance at March 31, 2009			71,636,019

During the year ended March 31, 2009, a total of 266,139 shares of the Company’s common stock were issued, or recognized as issued, as follows:

-	164,319 shares in aggregate issued to a consulting company under an agreement, as amended, pursuant to which Ronald A. Bain Ph.D., the Chief Operating Officer of the Company, provides certain business services to the Company. Dr. Bain is the sole owner of that corporation.

-	42,857 shares contractually issuable to a consulting company for services provided.

During the year ended March 31, 2008, the following is a summary of the stock transactions as follows:

Balance at March 31, 2007			65,737,036

Issuance of stock related to private placement			5,541,182
Issuance of restricted stock related to stock bonus award			25,000
Exercise of warrants			66,662
Balance at March 31, 2008			71,369,880

On February 26, 2008, the Company closed on a private placement offering in which it sold an aggregate 5,541,182 units of its securities at a price of $0.50 per Unit, each Unit consisting of 1 share of common stock, $0.001 par value, and one loyalty warrant to purchase 0.50 share of Common Stock, at a purchase price of $0.50 per unit of the Company (the “Loyalty Warrant”), for aggregate gross proceeds of approximately $2.77 million. The Loyalty Warrant shall not be exercisable until February 28, 2010, and only those investors who meet the requirements set forth in the Loyalty Warrant shall exercise the Loyalty Warrant at that time. The Units were sold pursuant to a Securities Purchase Agreement entered into by and between the Company and the purchasers named on the signature page thereto.

In February 2008, the Company issued 75,000 shares of common stock each to Dr. Ron Bain, a manager and consultant to the Company, and to a consulting firm for professional services. Both awards were subsequently modified , with a combined total of 85,714 shares of stock vesting on June 1, 2008.

F-21

During the year ended March 31, 2008, an executive officer and board member acquired, on the open market, 56,947 shares of our common stock, $0.001 par value, at an average price of $0.70 per share. In addition, another executive officer and board member, acquired on the open market, 10,000 shares of our common stock, $0.001 par value, at a price of $0.70 per share.

In August, 2007, Mr. John G. Williams informed the Company that he was resigning from his position as Executive Vice President Exploration and Production effective as of November 1, 2007. As such, 25,000 unvested shares of restricted stock previously awarded to Mr. Williams in March 2007 were forfeited.

During the year ended March 31, 2008, the Company issued a stock award of 25,000 shares of common stock to an employee contingent on 183 days of continuous service. Upon satisfaction of the terms of the award, the employee was issued 25,000 shares of restricted common stock of the Company.

During the year ended March 31, 2008, a total of 66,662 warrants were exercised at a price of $0.14 for a total of $9,333 and a total of 66,662 shares of common stock, $0.001 par value, were issued to an executive officer and director.

NOTE 11 - OPTIONS AND WARRANTS AND STOCK-BASED COMPENSATION

Warrants

The following tables summarize the changes in warrants outstanding and exercised, excluding the Loyalty Warrants associated with the $2.77 million private placement which have contingent exercise requirements, and the related exercise prices for the shares of the Company's common stock issued as follows (See also Note 10):

	Number of Shares			Weighted Average Exercise Price Per Share
Outstanding and Exercisable at March 31, 2007		968,083		$	0.13
Granted		-			-
Exchanged		-			-
Exercised		(66,662	)		0.14
Canceled or expired		-			-
Outstanding and Exercisable at March 31, 2008		901,421		$	0.13
Granted		-			-
Exchanged		-			-
Exercised		-			-
Canceled or expired		-			-
Outstanding and Exercisable at March 31, 2009		901,421		$	0.13

Warrants Outstanding								Warrants Exercisable

Exercise Prices		Number Outstanding		Weighted Average Remaining Contractual Life (Years)		Weighted Average Exercise Price		Number Exercisable		Weighted Average Exercise Price Exercise Price
$	0.07		138,655		1.50	$	0.07		138,655	$	0.07
$	0.14		762,766		1.50	$	0.14		762,766	$	0.14
			901,421		2.50	$	0.13		901,421	$	0.13

F-22

In February 2008 the Company issued 5,541,182 shares of common stock in a private placement, and one “Loyalty Warrant” to purchase 0.50 share of common stock, at a purchase price of $0.50 per share. The Loyalty Warrants cannot be exercised until the second anniversary of the closing date and only if the purchaser of the Loyalty Warrant has not sold or disposed of all of the related shares of common stock prior to the second anniversary of the closing. If the holder of the Loyalty Warrant has sold or disposed of some of the shares of common stock purchased under the private placement, then the Loyalty Warrant shall only be exercisable for the number of unsold shares held on the second anniversary of the closing. If all of the shares of common stock have been sold at the second anniversary of closing, then the Loyalty Warrant shall be non-exercisable and shall be rendered null and void.

The maximum number of shares of common stock that may be purchased from February 26, 2010 under the Loyalty Warrants is 2,770,591 and will be a lesser amount to the extent that some or all of the shares of common stock purchased under the 2008 placement are not held by the original purchaser on that date.

Stock Options

The following tables summarize the changes in options outstanding and exercised and the related exercise prices for the shares of the Company's common stock issued to certain directors and stockholders at March 31, 2009 and 2008: (See Note 10).

	Number of Shares			Weighted Average Exercise Price Per Share
Outstanding at March 31, 2007		5,077,526		$	0.46
Granted		375,000		$	0.64
Exercised		-			-
Canceled or expired		(250,000)		$	(1.42	)
Outstanding at March 31, 2008		5,202,526		$	0.42
Granted		-			-
Exercised		-			-
Canceled or expired		(250,000	)	$	(1.42	)
Outstanding at March 31, 2009		4,952,526		$	0.37

Options Outstanding								Options Exercisable
Exercise Price		Number Outstanding		Weighted Average Remaining Contractual Life (Years)		Weighted Average Exercise Price		Number Exercisable		Weighted Average Exercise Price
$	0.35		4,577,526		1.81	$	0.35		4,577,526	$	0.35
$	0.83		125,000		3.47	$	0.83		93,750	$	0.83
$	0.60		100,000		3.76	$	0.60		50,000	$	0.60
$	0.51		150,000		3.82	$	0.51		75,000	$	0.51
			4,952,526		1.95	$	0.37		4,796,276	$	0.37

During the year ended March 31, 2009 the Company did not issue any stock options to purchase common stock. During this year Stockholders approved the Index Oil and Gas Inc. 2008 Stock Incentive Plan, which has become the sole plan for providing equity-based incentive compensation to the Company’s employees, non-employee directors and other service providers. Initially 5,500,000 shares of Common Stock have been reserved for issuance under the 2008 Stock Incentive Plan.

During the year ended March 31, 2008, the Company issued stock options to purchase 175,000 shares of common stock to two employees and stock options to purchase 200,000 shares of common stock for professional services. All options issued in fiscal year ended March 31, 2008, vest 50% on award, 25% one year after grant and 25% two years after grant. In March 2007, stock options to purchase 500,000 shares of common stock were awarded to John Williams, of which 250,000 options vested on date of grant.

During the year to March 31, 2008 250,000 unvested options previously awarded to Mr. John G. Williams, a former director of the Company, were forfeited following his resignation and in the year to March 31, 2009 the term of exercise for Mr. Williams’ 250,000 vested options expired with the stock options unexercised.

Prior to the reverse merger with Index Inc. in 2006, Index Ltd. adopted a Stock Option Plan to grant options to various officers, directors and others. Following the completion of the acquisition the Board of Directors of Index Inc. agreed to and ratified the adoption of the plan as the 2006 Incentive Stock Option Plan, providing for the issuance of up to 5,225,000 shares of Common Stock of Index Inc. to officers, directors, employees and consultants of Index Inc. and/or its subsidiaries. Pursuant to the 2006 Incentive Stock Option Plan stock options to purchase 4,577,526 shares of Common Stock at $0.35 per share to newly appointed directors and officers of Index Inc. and that had held options to purchase ordinary shares of Index Ltd. prior to the completion of the acquisition. All these stock options are currently 100% vested. Other principal terms are: the share options are non-transferable other than to a legal or beneficial holder of the options upon the option holder’s death. The rights to vested but unexercised options cease to be effective: (1) 18 months after death of the stock options holder; (2) 6 months after Change of Control of Index Inc.; (3) 12 months after loss of office due to health related incapacity or redundancy; or (4) 12 months after the retirement of the options holder from a position with Index Inc. All options have a 5 years expiring term.

Total stock based compensation expense was $211,747 and $302,911 for the years ended March 31, 2009 and 2008, respectively. Total stock based compensation expense on unvested stock options remaining at March 31, 2009 is $9,611.

F-23

NOTE 12 - EARNINGS PER SHARE

Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if contracts to issue common stock and related stock options were exercised at the end of the period. For the year ended March 31, 2009 138,655 warrants to acquire common stock were excluded from the computation of diluted earnings per share, and exclusive of 762,766 warrants and 4,952,526 options that were out of the money. For the year ended March 31, 2008, excluded from the computation of diluted earnings per share are 901,421 of warrants to acquire common stock and 4,827,526 of options to acquire the common stock, and exclusive of 375,000 of out of the money options.

The following is a calculation of basic and diluted weighted average shares outstanding:

	For the year ended March 31,
	2009		2008
Shares—basic		71,477,513		66,288,104
Dilution effect of stock option and awards at end of period		-		-
Shares—diluted		71,477,513		66,288,104
Stock awards and shares excluded from diluted earnings per share due to anti-dilutive effect		138,655		5,728,947

NOTE 13 - MAJOR CUSTOMERS

In the fiscal year ended March 31, 2009, approximately 36%, 22% and 13% of revenues from the Company’s share of production were sold to three independent crude oil and gas purchasers or operators, as allowed by our joint operating agreements and for the fiscal year ended March 31, 2008, approximately 28%, 25% and 17% of revenues were equivalently sold to the top three purchasers.

NOTE 14 - RELATED PARTY TRANSACTIONS

In the fiscal year ended March 31, 2009, there were no related party transactions.

F-24

INDEX OIL AND GAS INC.

SUPPLEMENTAL INFORMATION (UNAUDITED)

FOR THE YEARS ENDED MARCH 31, 2009, 2008 AND 2007

Oil and Natural gas Producing Activities

The following disclosures for the Company are made in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 69, “Disclosures About Oil and Natural gas Producing Activities (an amendment of FASB Statements 19, 25, 33 and 39)” (“SFAS No. 69”). Users of this information should be aware that the process of estimating quantities of proved, proved developed and proved undeveloped crude oil and natural gas 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. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

Proved reserves represent estimated quantities of natural gas and crude oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.

Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made.

Proved 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 for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed 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 tests in the area and in the same reservoir.

Estimates of proved developed and proved undeveloped reserves as of March 31, 2009, 2008 and 2007 were based on estimates made by Ancell Energy Consulting, Inc, independent petroleum engineers. Our independent petroleum engineers, Ancell Energy Consulting, Inc. are engaged by and provide their reports to our senior management team. We make representations to the independent petroleum engineers that we have provided all relevant operating data and documents, and in turn, we review these reserve reports provided by the independent petroleum engineers to ensure completeness and accuracy. Our Chief Operating Officer, and Chief Executive Officer make the final decision on booked proved reserves by incorporating the proved reserves from the independent petroleum engineers’ reports.

Our relevant management controls over proved reserve attribution, estimation and evaluation include:

•

controls over and processes for the collection and processing of all pertinent operating data and documents needed by our independent petroleum engineers to estimate our proved reserves;

•

engagement of well qualified and independent petroleum engineers for review of our operating data and documents and preparation of reserve reports annually in accordance with all SEC reserve estimation guidelines; and

•

review by our Chief Operating Officer, of the independent petroleum engineers’ reserves reports for completion and accuracy.

Market prices as of each year-end were used for future sales of natural gas, crude oil and natural gas liquids. Future operating costs, production and ad valorem taxes and capital costs were based on current costs as of each year-end, with no escalation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. Reserve data represent estimates only and should not be construed as being exact. Moreover, the standardized measure should not be construed as the current market value of the proved oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risk.

F-25

Capitalized Costs Relating to Oil and Gas Producing Activities

The following table sets forth the capitalized costs relating to the Company’s natural gas and crude oil producing activities at March 31, 2009, 2008 and 2007:

	March 31,		March 31,		March 31,
	2009		2008		2007
Proved properties	$	4,878,182	$	11,181,430	$	3,254,211
Unevaluated & unproved properties		4,878,940		2,821,271		1,927,776
Total		9,757,122		14,002,701		5,181,987
Less: accumulated depreciation, depletion, amortization		3,493,585		1,407,610		315,937
Net capitalized costs	$	6,263,537	$	12,595,091	$	4,866,050

F-26

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the twelve months ended March 31, 2009, 2008 and 2007:

	Continuing Operations			Discontinued Operations
Year Ended March 31, 2007:
Acquisition costs of properties
Proved	$	-		$	-
Unproved		355,641			-
Subtotal		355,641			-
Exploration and development costs		3,731,308			-
Total	$	4,086,949		$	-


Year Ended March 31, 2008:
Acquisition costs of properties
Proved	$	985,605		$	-
Unproved		292,382
Subtotal		1,277,987
Exploration and development costs		7,496,071
Total	$	8,774,058		$	-


Year Ended March 31, 2009:
Acquisition costs of properties
Proved	$	72,078		$	-
Unproved		(32,316	)
Subtotal		39,762
Exploration and development costs		2,664,626
Total	$	2,704,388		$	-

Results of Operations for Oil and Natural Gas Producing Activities

	Year Ended March 31, 2009			Year Ended March 31, 2008			Year Ended March 31, 2007
Oil and natural gas production revenues
Third-party	$	2,828,751		$	1,705,593		$	457,046
Affiliate		-			-			-

Total revenues		2,828,751			1,705,593			457,046
Exploration expenses, including dry hole		-			-			-
Production costs		(704,183	)		(303,474	)		(114,735	)
Depreciation, depletion, amortization and impairment		(9,096,953	)		(1,091,673	)		(188,351	)

Income (loss) before income taxes		(6,972,385	)		310,446			153,960
Income tax provision (benefit)		-			-			-

Results of continuing operations	$	(6,972,385	)	$	310,446		$	153,960

Results of discontinued operations	$	-		$	-		$	-

The results of operations for oil and natural gas producing activities excludes interest charges and general and administrative expenses. Sales are based on market prices.

F-27

Net Proved and Proved Developed Reserve Summary

The following estimates of proved and proved developed reserve quantities are estimates only. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment, and operating methods.

The following table sets forth the Company’s net proved and proved developed reserves (all within the United States) at March 31, 2009, 2008 and 2007, and the changes in the net proved reserves for each of the three years in the periods then ended as estimated by the independent petroleum consultants.

	Continuing Operations			Discontinued Operations
Natural gas (Bcf)(1):
Net proved reserves at March 31, 2006		0.144			-
Revisions of previous estimates		0.157			-
Purchases in place		0.008			-
Extensions, discoveries and other additions		0.240			-
Sales in place		-			-
Production		(0.008)			-
Net proved reserves at March 31, 2007		0.541			-
Revisions of previous estimates		(0.245)			-
Purchases in place		0.084			-
Extensions, discoveries and other additions		0.836			-
Sales in place		-			-
Production		(0.127)			-
Net proved reserves at March 31, 2008		1.090			-
Revisions of previous estimates		(0.628)			-
Purchases in place		-			-
Extensions, discoveries and other additions		0.176			-
Sales in place		-			-
Production		(0.237	)		-
Net proved reserves at March 31, 2009		0.400			-

Natural gas liquids and crude oil (MBbls)(2)(3):
Net proved reserves at March 31, 2006		35.401			-
Revisions of previous estimates		(5.349)			-
Purchases in place		0.066			-
Extensions, discoveries and other additions		0.875			-
Sales in place		-			-
Production		(6.660	)		-
Net proved reserves at March 31, 2007		24.333			-
Revisions of previous estimates		(6.591)			-
Purchases in place		0.005			-
Extensions, discoveries and other additions		27.497			-
Sales in place		-			-
Production		(7.477	)		-
Net proved reserves at March 31, 2008		37.767			-
Revisions of previous estimates		(11.490	)		-
Purchases in place		-			-
Extensions, discoveries and other additions		2.906			-
Sales in place		-			-
Production		(8.217	)		-
Net proved reserves at March 31, 2009		20.966			-

F-28

(MBO)(2) equivalents(4):
Net proved reserves at March 31, 2006	59.471	-
Revisions of previous estimates	20.748	-
Purchases in place	1.478	-
Extensions, discoveries and other additions	40.956	-
Sales in place	-	-
Production	(8.075)	-
Net proved reserves at March 31, 2007	114.578	-
Revisions of previous estimates	(47.393)	-
Purchases in place	14.050	-
Extensions, discoveries and other additions	166.859	-
Sales in place	-	-
Production	(28.625)	-
Net proved reserves at March 31, 2008	219.469	-
Revisions of previous estimates	(116.194)	-
Purchases in place	-	-
Extensions, discoveries and other additions	32.207	-
Sales in place	-	-
Production	(47.781)	-
Net proved reserves at March 31, 2009	87.702	-

Net proved developed reserves:
Natural gas (Bcf)(1)
March 31, 2007	0.541	-
March 31, 2008	1.090	-
March 31, 2009	0.305	-

Natural gas liquids and crude oil (MBbls)(2)(3)
March 31, 2007	22.953	-
March 31, 2008	36.677	-
March 31, 2009	20.015	-

MBO(2) equivalents(4)
March 31, 2007	113.198	-
March 31, 2008	218.379	-
March 31, 2009	70.878	-

(1)	Billion cubic feet or billion cubic feet equivalent, as applicable.

(2)	Thousand barrels.

(3)	Includes crude oil, condensate and natural gas liquids.

(4)	Natural gas volumes have been converted to equivalent natural gas liquids and crude oil volumes using a conversion factor of six thousand cubic feet of natural gas to one barrel of natural gas liquids or crude oil.

F-29

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

The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on natural gas and crude oil reserve and production volumes estimated by the independent petroleum engineers. This information may be useful for certain comparison purposes but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company’s oil and natural gas assets.

The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of natural gas and crude oil reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and natural gas producing activities.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company’s natural gas and crude oil reserves for the years ended March 31, 2009, 2008 and 2007:

	Continuing Operations			Discontinued Operations
	(in $’000)
March 31, 2007:
Future cash inflows	$	5,049.821		$	-
Future production costs		(1,055.600	)		-
Future development costs		(53.403	)		-
Future income taxes		-			-

Future net cash flows		3,940.818			-
Discount to present value at 10% annual rate		(841.922	)		-

Standardized measure of discounted future net cash flows relating to proved natural gas, natural gas liquids and crude oil reserves	$	3,098.896		$	-

March 31, 2008:
Future cash inflows	$	14,799.617		$	-
Future production costs		(2,733.919	)		-
Future development costs		(86.499	)		-
Future income taxes		-			-

Future net cash flows		11,979.199			-
Discount to present value at 10% annual rate		(2,007.956	)		-

Standardized measure of discounted future net cash flows relating to proved natural gas, natural gas liquids and crude oil reserves	$	9,971.243		$	-

F-30

	Continuing			Discontinued
	Operations			Operations
March 31, 2009:
Future cash inflows	$	2,530.215		$	-
Future production costs		(599.346	)		-
Future development costs		(375.000	)		-
Future income taxes		-			-

Future net cash flows		1,555.869			-
Discount to present value at 10% annual rate		(313.933	)		-

Standardized measure of discounted future net cash flows relating to proved natural gas, natural gas liquids and crude oil reserves	$	1,241.936		$	-

Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the changes in the standardized measure of discounted future net cash flows at March 31, 2009, 2008 and 2007:

	Continuing			Discontinued
	Operations			Operations
	(in $’000)
Balance, April 1, 2006	$	1,347.233		$	-

Sales and transfers of natural gas, natural gas liquids and crude oil produced, net of production costs		(342.311	)		-
Net changes in prices and production costs		(46.758)			-
Extensions, discoveries, additions and improved recovery, net of related costs		1,180.549			-
Development costs incurred		1,320.745			-
Revisions of previous quantity estimates and development costs		(820.626	)		-
Accretion of discount		134.723			-
Net change in income taxes		-			-
Purchases of reserves in place		486.467			-
Sales of reserves in place		-			-
Changes in timing and other		(161.126	)		-
Balance, March 31, 2007	$	3,098.896		$	-

Sales and transfers of natural gas, natural gas liquids and crude oil produced, net of production costs	$	(1,402.119	)	$	-
Net changes in prices and production costs		1,138.995			-
Extensions, discoveries, additions and improved recovery, net of related costs		8,082.075			-
Development costs incurred		-			-
Revisions of previous quantity estimates and development costs		(1,910.908	)		-
Accretion of discount		309.890			-
Net change in income taxes		-			-
Purchases of reserves in place		592.974			-
Sales of reserves in place		-			-
Changes in timing and other		61.440			-
Balance, March 31, 2008	$	9,971.243		$	-

Sales and transfers of natural gas, natural gas liquids and crude oil produced, net of production costs	$	(2,124.568	)	$	-
Net changes in prices and production costs		(5,377.604	)		-
Extensions, discoveries, additions and improved recovery, net of related costs		194.356			-
Development costs incurred		30.881			-
Revisions of previous quantity estimates and development costs		(2,165.565	)		-
Accretion of discount		997.124			-
Net change in income taxes		-			-
Purchases of reserves in place		-			-
Sales of reserves in place		-			-
Changes in timing and other		(283.931	)		-
Balance, March 31, 2009	$	1,241.936		$	-

F-31

Exhibit Index

Exhibit Number		Description
3.1		Restated Articles of Incorporation of Index Oil and Gas Inc., Inc. (1)

3.2		Bylaws of Index Oil and Gas Inc. (2)

10.1		Acquisition Agreement between Index Oil and Gas Inc., certain stockholders of Index Oil & Gas Ltd, and Briner Group Inc. dated January 20, 2006. (3)

10.2		Form of Share and Warrant Exchange Agreement entered into by and between Index Oil and Gas Inc., Inc. and certain Index Oil & Gas Ltd stockholders. (3)

10.3+		Employment Agreement entered into by and between Index Oil & Gas Ltd and Lyndon West, dated January 20, 2006. (3)

10.4+		Employment Agreement entered into by and between Index Oil & Gas Ltd and Andy Boetius, dated January 20, 2006. (3)

10.5+		Employment Agreement entered into by and between Index Oil & Gas Ltd and Daniel Murphy, dated January 20, 2006. (3)

10.6+		Letter Agreement entered into by and between Index Oil & Gas Ltd and David Jenkins, dated January 20, 2006. (3)

10.7+		Letter Agreement entered into by and between Index Oil & Gas Ltd and Michael Scrutton, dated January 20, 2006. (3)

10.8+		Employment Agreement entered into by and between Index Oil and Gas Inc. and John G. Williams, dated August 29, 2006. (4)

10.9		Form of Subscription Agreement dated as of January 20, 2006. (3)

10.10		Form of Subscription Agreement dated as of August 29 and October 4, 2006. (5)

10.11		Form of Registration Rights Agreement dated as of August 29, 2006. (5)

10.12+		Index Oil and Gas Inc. 2006 Incentive Stock Option Plan. (6)

10.13		Securities Purchase Agreement dated as of November 5, 2007. (7)

10.14		Form of Warrant to Purchase Common Stock. (7)

10.15+		Agreement for Exploration, Production and Strategic Services dated February 1, 2008 between the Company and ConRon Consulting Inc., as amended by Addendum #1 dated June 1, 2008 and Addendum #2 dated July 1, 2008. (8)

10.16+		Amended and Restated Agreement for Exploration, Production and Strategic Services between Index Oil and Gas Inc. and ConRon Consulting Inc. dated December 8, 2008. (9)

10.17+		Amended Employment Agreement of Daniel Murphy, dated March 4, 2009. (10)

10.18+		Amended Employment Agreement of Lyndon West, dated March 4, 2009. (10)

10.19+		Amended Employment Agreement of Andrew Boetius, dated March 4, 2009. (10)

14.1		Code of Ethics and Business Conduct for officers, directors and employees of Index Oil and Gas Inc. adopted by the Company’s Board of Directors on March 31, 2006. (11)

21.1		List of subsidiaries of the Company. *

23.1		Consent of RBSM LLP. *

23.2		Consent of Ancell Energy Consulting, Inc. *

31.1		Certification by Chief Executive Officer required by Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act. *

31.2		Certification by Chief Financial Officer required by Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act. *

32.1		Certification by Chief Executive Officer required by Rule 13a-14(b) or Rule 15d-14(b) of the Exchange Act and Section 1350 of Chapter 63 of Title 18 of the United States Code. *

32.2		Certification by Chief Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) of the Exchange Act and Section 1350 of Chapter 63 of Title 18 of the United States Code. *