Index Oil and Gas (IXOG) 10-K 2008 FY Annual report

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, 2008
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 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.  R

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 Small 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 reported on the OTC Bulletin Board on September 28, 2007 was $46,365,872.

As of June 15, 2008, there were outstanding 71,455,594 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	1
Item 1.  Business	1
Item 1A.  Risk Factors	8
Item 1B.  Unresolved Staff Comments	16
Item 2.  Properties.	16
Item 3.  Legal Proceedings.	20
Item 4.  Submission of Matters to a Vote of Security Holders.	20
PART II	21
Item 5.  Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.	21
Item 6.  Selected Financial Data.	22
Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.	22
Item 7A.  Quantitative and Qualitative Disclosures About Market Risk.	31
Item 8.  Financial Statements and Supplementary Data.	31
Item 9.  Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.	31
Item 9A. Controls and Procedures.	31
Item 9A(T).  Controls and Procedures.	32
Item 9B.  Other Information.	32
PART III	32
Item 10. Directors, Executive Officers, and Corporate Governance.	32
Item 11. Executive Compensation.	33
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	33
Item 13.  Certain Relationships and Related Transactions, and Director Independence.	33
Item 14.  Principal Accountant Fees and Services.	33
PART IV	33
Item 15. Exhibits and Financial Statement Schedules.	33
SIGNATURES	36

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”) 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 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. 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, 2008, Index had year-on-year increases in reserves, production and revenue.  We have sustained a history of drilling success rates, while pursuing higher-impact prospects, all while remaining debt free (excluding ordinary course trade debt).  The Company, as described more fully in “Recent Financing”, raised $2.77 million in gross proceeds in a private equity fund raise in a very challenging fiscal environment.  The Company also recruited highly experienced senior staff members in exploration and production, land and operations and in accounting to the Index team.

Reserves increased approximately 92% from 114.6 MBoe (thousand barrels of oil equivalent) of proven reserves as of March 31, 2007 to 219.469 MBoe of proven reserves as of March 31, 2008. Production rose approximately 253% from 8.1 MBoe for the fiscal year ended March 31, 2007 to 28.6 MBoe for the fiscal year ended of March 31, 2008. Total production in the fourth quarter of fiscal year 2008 was 18.8 MBoe.  Correspondingly, oil and natural gas revenues increased approximately 273% from $457.0 thousand for the fiscal year ended March 31, 2007 to $1.7 million for the fiscal year ended March 31, 2008.

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 geophysical 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.

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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, 2008, we believe that we have achieved this level of production with our existing interests in producing properties.

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 higher risk, higher reward properties, (3) completing acquisitions and selective divestitures, (4) maintaining technical expertise, (5) focusing on cost control, and (6) maintaining financial flexibility.  We have 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 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, 2008, we participated in 14.0 gross and 2.2 net wells, for which principal drilling and, where applicable, completion operations were concluded in the year.  Of these wells, 11 gross and 2.1 net wells became productive and with a gross completion rate of 79%.  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, 2008, we owned approximately 271 net acres in Kansas.  Our production is concentrated in Stafford and Barton Counties.  Total net production for the fiscal year ended March 31, 2008, 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 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. We have committed to a current program of 14 wells for low-risk prospects in Stafford and Barton Counties. To-date, in this program, we have participated in eight wells, of which in June 2008, four are now on production (including one Stafford County well which was drilled under farm-in arrangements and in which we have a 2.5% WI), one is being completed and three have been plugged and abandoned. The two most recent wells, with a 3.25% WI and a 2.64% NRI, are the Salem #1-8 well, which was completed in April 2008 and the Miller-McReynolds Unit 1-17 which was spudded in April 2008, completed and began production in June 2008.  Further activity is expected at approximately two wells per month dependent on commodity pricing and evaluation of the program to date.

Louisiana

Properties Summary.  At March 31, 2008, we owned approximately 199 net acres in Louisiana.  Our production is concentrated in Calcasieu and St. Mary Parishes.  Total net production for the fiscal year ended March 31, 2008, for all Louisiana wells was approximately 51.1 MMcfe (approximately 10.5 MMcfe for Walker 1 and 40.6 MMcfe for Shadyside 1).

Operations Summary.  Our onshore drilling program in Louisiana includes our interest in the Walker 1 discovery well (WI 12.5%, approximate NRI 9.36%) which was recently recompleted; however, current production is minimal and is under engineering evaluation.  In April 2007, we signed agreements to participate in the Shadyside prospect, located in St. Mary Parish, Louisiana.  Our initial working interest is 15% and our initial net revenue interest is approximately 10.7% in the prospect, reducing to 13.5% WI and approximately 9.6% NRI after prospect payout, defined as the day after which net proceeds from the sale of the oil, gas and other hydrocarbons produced, saved and marketed or taken from all wells drilled in the prospect, equals the total of certain costs, including, but not limited to, drilling, testing, completing and equipping all wells into the tanks or gas gathering lines, the cost of operating all wells up to the date of payout, severance, production and/or mineral ad valorum taxes measured by production and assessed on production from all wells, royalty payments and other fees and land costs.  The Shadyside 1 well was drilled to a total depth of approximately 16,294 feet and due to non-participation by the former operator, we now have a 30% WI and 22.5% NRI in the well. The well has been hooked up and began flowing to sales in January 2008.  Although we are considering the potential of both deeper and shallower prospects on current leases, Shadyside is considered to be a single well project.

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Texas

Properties Summary. At March 31, 2008, we owned approximately 2,192 net acres in Texas.  Our production is in Brazoria, Matagorda, Victoria, Goliad, Wharton, and Nacogdoches counties.    Total net production for the fiscal year ended March 31, 2008, for all Texas wells was approximately 105.7 MMcfe or 17.6 Mboe.  The table below shows our production from the various Texas wells during the fiscal year ended March 31, 2008:

Texas Production
Year ending March 31, 2008
Well name	Gas, MMcf	Oil, MBbl	Equivalent, MBoe	Equivalent, MMcfe
Vieman 1	3.181	0.010	0.540	3.241
Hawkins 1	4.477	0.000	0.746	4.477
Freidrich Gas Unit 1	28.994	0.000	4.832	28.994
Schroeder Gas Unit 1	13.123	0.000	2.187	13.123
Cason wells *	8.647	0.054	1.496	8.971
Outlar 1	27.551	1.744	6.336	38.015
Ducroz 1	8.837	0.005	1.478	8.867
Total	94.810	1.813	17.615	105.688

*   Cason 1, Cason 2 and Cason 3

Operations Summary.  Our onshore drilling program in Texas includes its interest in Vieman 1 (19.5% WI, approximate NRI 14.56%) in Brazoria County Texas which began production in February 2007 and has been recompleted but is currently shut-in and undergoing engineering evaluation. The Hawkins 1 well (WI 12.5%, approximate NRI 10.01%), in Matagorda County, began production into the local pipeline grid in January 2008.  In addition, we drilled two successful wells in South Texas, the Friedrich Gas Unit 1 (WI 37.5%, approximate NRI 28.125%) in Victoria County and the Schroeder Gas Unit 1 (WI 37.5%, approximate NRI 28.125%) in Goliad County, which began producing in August 2007 and was worked over in March 2008.  The operator is preparing to remediate the Shroeder Gas Unit 1 in order to restore production levels.

The Ilse 1 well (WI 10% Before Project Payout and WI 8% After Project Payout, approximate NRI 6%), drilled in the New Taiton Project area in Wharton County, Texas, has been drilled to total depth of approximately 17,000 feet and logged. Analysis of the logs revealed two zones of interest in the Wilcox C and Wilcox A, respectively. The lowest zone, the Wilcox C, has been perforated and stimulated by a reservoir “fracture” process. Gas flow from the formation to surface has not been achieved. The preliminary decision from the operator was that this interval would not be productive and would not have any proved reserves. The well was suspended, pending a possible test to attempt to achieve gas flows from the upper zone of interest, the Wilcox A.

The George Cason 1 well, drilled on the Fern Lake prospect in Nacogdoches County, Texas and spudded in June 2007, began sales in December 2007. The Cason 2 well began production in January 2008. The Cason 3 well spudded in early February 2008 and began producing at the end of March 2008. We currently have a 25.0% WI and an approximate 18.7% NRI in all three Cason wells. We are currently participating, with other partners, in geological analyses on other formations encountered in the wells.  The Cason wells are proving to be challenging in terms of volumes and maintaining production. The operator is currently conducting a series of workover procedures in the wells in an effort to increase production levels.

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We are participating in an exploration agreement at 20% WI in the Supple Jack Creek lease area. The first well, HNH Gas Unit 1, targeted gas in the Edwards Limestone in Lavaca County, Texas. The well reached a total depth of approximately 15,000 feet, was sidetracked laterally to approximately 16,000 feet and is currently suspended pending further evaluation of potential logged pay intervals. Subject to results, the Company will evaluate additional drilling, particularly in a success case. The gas unit designated for the well covers 566.59 acres. However, the contract Area of Mutual Interest ("AMI") for the overall prospect extends over a much larger area, of which approximately 5,000 gross and net acres are currently under lease.

In June 2007, we announced that we had entered into Participation and Joint Operating Agreements for the drilling of the Cow Trap project ("Cow Trap") to be located in Brazoria County, Texas. The Cow Trap well, named Ducroz 1 (WI 7.5%, approximate NRI 5.25%), targets gas in stacked Miocene objectives at depths ranging from 4,900 feet to 6,400 feet. The well had a total depth of approximately 6,500 feet. Ducroz 1 has been drilled, completed and began production in February 2008. Ducroz 1 is considered by the Company to be a single well project.

In April 2007, we announced that we had signed a Participation Agreement to explore for gas in the West Wharton prospect. This project could consist of up to four exploration wells within the AMI in Wharton County, Texas. We have a 10.9% WI in the project that will reduce to 9.38% WI after prospect payout, 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 valorum 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.  The first well, Outlar 1 (approximate NRI 8.2% before payout and 7.0% after payout), spudded in August 2007 and sales began in December 2007.  We view the West Wharton project as potentially significant for us as it has existing leases on up to five well-defined prospects. The second well in this prospect, Stewart 1 was spudded in May 2008. We have also participated in additional leasing opportunities with the operator.

In July 2007, we announced that we had signed a Purchase and Sale Agreement to acquire a 5% WI and approximate 3.5% NRI in the Alligator Bayou exploration prospect located beneath onshore portions of Brazoria and Matagorda Counties, Texas. The prospect covers up to several thousand acres. The first well, Armour-Runnells 1, was spudded in April 2008, is currently being drilled and targets gas in the deep, high pressure, high temperature Wilcox formation.  We anticipate this well to be the highest potential impact and highest risk well in our portfolio.

Recent Financing

On February 26, 2008, we closed on a private placement offering in which we sold an aggregate 5,541,182 units of our 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 share of the Company (the “Loyalty Warrant”), for aggregate gross proceeds of approximately $2.77 million. The Loyalty Warrant shall not be exercisable until February 26, 2010, and only those investors who meet the requirements set forth in the Loyalty Warrant shall be able to exercise the Loyalty Warrant at that time or thereafter.  The net proceeds of the offering were used as working capital and for general corporate purposes.

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. We believe that because exploration has developed offshore, the onshore is lagging in exploitation of the latest offshore ideas.  We hope to capitalize on this oversight.

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.

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Customers

Through contracts negotiated by our operators, we sell our crude oil and natural gas production to independent purchasers (collectively, “purchaser”), 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, 2008, approximately 28%, 25% and 17% of revenues from our share of oil production were sold to three independent crude oil and gas purchasers, together with low levels of gas sales, and for the 2007 fiscal year ended March 31, 2007, approximately 53% and 47% of oil sales were sold to two 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 gas it produces. 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.

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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.

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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, 2008, we had full time employment agreements with the following officers: Mr. Lyndon West, CEO, Mr. Andrew Boetius, CFO, and Mr. Dan Murphy, Chairman and secretary (who is to change to three days per week from July 1, 2008) and  Mr. Gregory Mendez, Controller. In addition, we had consulting agreements with Dr. Ronald Bain, Senior Vice President Exploration and Production, and Mr. Samuel Culpepper, Vice President Land and Operations. 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 at March 31, 2008 we had 5 total and 5 full time employees, excluding the above consulting positions.

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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;

•           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.

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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, 2008, we incurred a financial loss after taxation of approximately $1.9 million. We 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 resource 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 (Capex) 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 resource 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.

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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 trading volumes in our shares on a daily basis.

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 Senior Vice President Exploration and Production, 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.

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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, and  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 minimal employees as of March 31, 2008. 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.

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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 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.

Our profit margins may be adversely affected by fluctuations in the selling price and production cost of gasoline.

Oil prices are significantly influenced by the supply of and demand for gasoline. Our results of operations may be materially harmed if the demand for or the price of gasoline decreases. Conversely, a prolonged increase in the price of or demand for gasoline could lead the U.S. government to take actions that maybe adverse to us, such easing the import of foreign oil and gas into the U.S.

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 preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties.

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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 are 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.

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We are subject to compliance with securities law, which exposes us to potential liabilities, including potential rescission rights.

We have periodically offered and sold our common stock to investors pursuant to certain exemptions from the registration requirements of the Securities Act of 1933, as well as those of various state securities laws. The basis for relying on such exemptions is factual; that is, the applicability of such exemptions depends upon our conduct and that of those persons contacting prospective investors and making the offering. We have not received a legal opinion to the effect that any of our prior offerings were exempt from registration under any federal or state law. Instead, we have relied upon the operative facts as the basis for such exemptions, including information provided by investors themselves.

If any prior offering did not qualify for such exemption, an investor would have the right to rescind its purchase of the securities if it so desired. It is possible that if an investor should seek rescission, such investor would succeed. A similar situation prevails under state law in those states where the securities may be offered without registration in reliance on the partial preemption from the registration or qualification provisions of such state statutes under the National Securities Markets Improvement Act of 1996. If investors were successful in seeking rescission, we would face severe financial demands that could adversely affect our business and operations. Additionally, if we did not in fact qualify for the exemptions upon which we have relied, we may become subject to significant fines and penalties imposed by the SEC and state securities agencies.

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 more than two-thirds of the trading days during February of 2008 saw trading in our stock of less than 100,000 shares per day. During that same period, the smallest number of shares trade in one day was zero and the largest number of shares traded in one day was 412,526. 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.

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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.

15

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 of 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, 2009. 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.

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 6,103,947 outstanding options and warrants, excluding the Loyalty Warrants associated with our $2.77 million private placement which have contingent exercise requirements, and options to purchase shares of our common stock outstanding, at March 31, 2008. 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 #10 “Options and Warrants and Stock-Based Compensation” to the Notes accompanying our audited 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 hold an arrangement to rent our main office comprising of approximately 300 square feet which is located at 10,000 Memorial Drive, Suite 440, Houston, Texas 77024. Lease payments at fiscal year ended March 31, 2008, were $4,500 per month and are due on a month-to-month basis. We also have a month-to-month lease, related to corporate housing for UK based officers while periodically working at the corporate office.  This lease is currently operating on a rolling monthly basis with $1,760 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, 2008 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 producing 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 2008, 2007 and 2006, 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.

16

At March 31, 2008, our estimated total proved oil and natural gas reserves were approximately 219.469 MBoe, consisting of 37.767 thousand barrels of oil (MBbls) and 1,090.213 million cubic feet (MMcf) of natural gas. Approximately 218.379 MBoe or 99.5% of our proved reserves were classified as proved developed producing and proved behind pipe. 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, 2008, 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		13.942		90.465		113.972		218.379
Undeveloped		1.090		--		--		1.090
Total		15.032		90.465		113,972		219.469
Gross Wells (1)		24.000		1.000		7.000		32.000
Net Wells (1)		1.123		0.300		2.268		3.691

(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 thousands barrels (MBbl); 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 thousand 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 and St. Mary Parish in Louisiana and Brazoria, Goliad, Matagorda, Wharton, Nacogdoches 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.

17

Oil prices used in this report are based on the March 31, 2008, oil price received at various points and averaged $100.13 per barrel. Natural gas prices used in this report are based on a March 31, 2008, NYMEX spot market price and averaged of $10.11 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, 2008, we had interests in 32 gross productive wells (3.477 net productive wells).  Our oil (only) wells totaled 21 gross productive wells and 1.033 net productive oil wells, our gas (only) wells totaled 5 gross productive wells and 1.375 net productive oil wells and our mixed oil and gas wells totaled 6 gross and 1.069 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, 2008.  

	Developed Acreage				Undeveloped Acreage				Total Acreage
State	Gross		Net		Gross		Net		Gross		Net
Kansas		3,519.00		163.55		2,408.50		107.48		5,927.50		271.03
Louisiana		1,066.41		156.69		2,84.20		42.63		1,350.61		199.32
Texas		1,702.92		249.35		21,568.24		1,942.54		23,271.16		2,191.89
Total Acreage		6,288.33		569.59		24,260.94		2,092.65		30,549.27		2,662.24

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

	2008				2009				2010				Thereafter
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Undeveloped Acreage		4,015.49		370.27		5,293.82		715.34		14,951.63		1,007.04		--		--

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.

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Capitalized costs of our evaluated and unevaluated properties at March 31, 2008, 2007 and 2006 are summarized as follows:

	March 31,
	2008		2007		2006
Capitalized costs:
Proved and evaluated properties	$	11,181,430	$	3,254,211	$	722,056
Unproved and unevaluated properties		2,821,271		1,927,776		356,729
		14,002,701		5,181,987		1,078,785
Less accumulated depreciation and depletion		1,407,610		315,937		127,586
	$	12,595,091	$	4,866,050	$	951,199

Production

Our oil and gas production volumes and average sales price for the twelve months ended March 31, 2008, 2007 and 2006, respectively, are as follows:

	Years Ended March 31,
	2008		2007		2006
Gas production (MMcf):		126.888		8.490		--
Oil production (MBbl)		7.478		6.660		3.42
Equivalent production (MBoe)		28.626		8.075		3.42
Average price per unit:
Gas (per Mcf)	$	8.21	$	6.61	$	--
Oil (per Bbl)	$	88.69	$	60.20	$	55.89
Equivalent (per Boe)	$	59.58	$	56.60	$	55.89

Drilling Activity

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

	Years Ended March 31,
	2008				2007				2006
	Gross		Net		Gross		Net		Gross		Net
Gross Exploratory Wells:
Productive (1)		10.00		2.019		5.00		0.2150		6.00		0.3750
Dry		3.00		0.150		4.00		0.6825		1.00		0.0500
Total Exploratory		13.00		2.169		9.00		0.8975		7.00		0.4250
Gross Development Wells:
Productive(1)		1.00		0.075		1.00		0.195		--		--
Dry		--		--		--		--		--		--
Total Development		1.00		0.075		1.00		0.195		--		--
Total Gross Wells:
Productive(1)		11.00		2.094		6.00		0.323		19.00		0.75
Dry		3.00		0.150		4.00		0.518		1.00		--
Total		14.00		2.244		10.00		0.841		20.00		0.75

(1) 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.

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Present Activities

At the start of our fiscal year commencing on April 1, 2008 we approved an annual capital expenditure budget for programs on certain of our oil and natural gas properties, consistent with an assessment of our available financial resources. This capital budget was set at approximately $3.2 million, predominantly for exploration activities. We budgeted to participate in five wells in Texas and in a continuing well program in Kansas. Our budget may be revised through the fiscal year, dependent on various circumstances and factors.

Delivery Commitments

At March 31, 2008, 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, other than as disclosed below regarding the Ilse well. 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.

With respect to the Ilse well, all non-operator members of the joint venture (“non-operators”), including us, agreed to a successor operator and requested an audit of the accounting records of the original operator be performed in accordance with the Joint Operating Agreement.  The original operator, however, refused to sign a change in operator form to be filed with the Texas Railroad Commission.  The non-operators filed a Temporary Restraining Order and a Temporary Injunction against the original operator.  This was denied by the court, and the parties ordered to mediate.  Mediation was held in October 2007 with no agreement reached.  An injunction hearing was held in late 2007 and was placed in continuance status. Contemporaneously with these proceedings, non-operators submitted a single-signature P4 (Change of Operator) Form to the Texas Railroad Commission and filed for binding arbitration under the Joint Operating Agreement.

Since July 26, 2007, we, as a joint interest owner, have received various Texas Property Code Notices of Intent to File Lien Against Property with regard to materials/equipment sold and/or leased and amounts owed to third parties by the operator of the Ilse property. Under Texas case law, the operator is deemed to be responsible for these unpaid amounts owed to third parties.  We were billed for these services by the operator on their operating statements received to March 2008, and these costs have been accrued in our consolidated financial statements as costs related to the Ilse well. We believe that no other contingency accrual is currently required.

In April 2008, an agreement in principle was reached between the operator and the non-operators which encompasses (among others) full, mutual releases of all claims against all parties, except one, including any claims of the operator against non-operators for monies allegedly owed under the joint interest billing, and the assignment of non-operators’ interest in the well to the operator.  No monies are due by non-operators in the proposed settlement. A total of $0.3 million in costs at March 31, 2008 that have not been paid to the operator would be discharged.  Upon completion and final execution of the documents, the capital costs which have been discharged by the operator will be reversed out of capital costs and would have a corresponding reduction in current depletion of approximately $1.18 per boe produced

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

No matters were submitted to a vote of our security holders during the fourth quarter of fiscal year 2008 ended March 31, 2008.

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PART II

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

Market Information

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

The following sets forth the range of the closing bid prices for our common stock for the quaters in the period starting April 1, 2006, through March 31, 2008. 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 the Company’s common stock.

	High Close		Low Close
2007 Fiscal Year
June 30, 2006		1.65		1.32
September 30, 2006		1.54		1.15
December 31, 2006		1.70		1.36
March 31, 2007		1.65		1.18
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

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 the company’s common stock and may affect the ability of stockholders to sell their shares.

Holders

As of March 31, 2008, the approximate number of stockholders of record of the Common Stock of the Company was 215.

21

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, 2008:

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		5,202,526	$	0.42		22,474
Equity compensation plans not approved by security holders		-0-	$	-0-		-0-
Total		5,202,526	$	0.42		22,474

Unregistered Sales of Equity Securities and Use of Proceeds

Other then set forth below, the information regarding our sales of our unregistered securities for the fiscal year ended March 31, 2008, has been previously furnished in our Annual Reports on Form 10-K or 10-KSB, Quarterly Reports on Form 10-Q or 10-QSB and/or our Current Reports on Form 8-K.

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 i of this Annual Report for “Information Regarding Forward Looking Statements” appearing throughout this Annual Report.

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Business Overview

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

Results of Operations

Year Ended March 31, 2008 Compared to Year Ended March 31, 2007

We had a net loss of $1.9 million for the fiscal year ended March 31, 2008 compared to a net loss of $2.2 million for the fiscal year ended March 31, 2007.  Revenue and operating income increased by $1.2 million and $0.4 million, respectively, but were offset by general and administrative costs of $2.5 million, which decreased by $0.3 million, increased depletion of $0.9 million to $1.1 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, 2008 and 2007.

	Years Ended March 31,						Increase
	2008			2007			(Decrease)
Oil and gas sales	$	1,705,593		$	457,046		$	1,248,547
Production expenses:
Lease operating		188,521			80,186			108,335
Taxes other than income		114,952			34,549			80,403
General and administrative:
General and administrative		2,155,018			1,848,142			306,876
Stock-based compensation		302,911			875,092			(572,181	)
Depletion — Full cost		1,091,673			188,351			903,322
Depreciation — Other		4,556			1,028			3,528
Impairment		--			--			--
Interest expense (income) and other		(205,608	)		(344,646	)		139,038
Income tax benefit (provision)		--			--			--
Net income (loss)	$	(1,946,430	)	$	(2,225,656	)	$	279,226
Production:
Natural Gas — MMcf		126.888			8.490			118.398
Crude Oil — MBbl		7.478			6.660			0.818
Equivalent — MBoe		28.626			8.075			20.551
Average price per unit:
Gas price per Mcf	$	8.21		$	6.61		$	1.60
Oil price per Bbl	$	88.69		$	60.20		$	28.49
Equivalent per Boe	$	59.58		$	56.60		$	2.98
Average cost per Boe:
Production expenses:
Lease operating	$	6.59		$	9.93		$	(3.34	)
Taxes other than income	$	4.02		$	4.28		$	(0.26	)
General and administrative expense:
General and administrative	$	75.28		$	228.87		$	(153.59	)
Stock-based compensation	$	10.58		$	108.37		$	(97.79	)
Depletion expense	$	38.14		$	23.32		$	14.82

For the year ended March 31, 2008, oil and natural gas sales increased $1.2 million, from the same period in 2007, to $1.7 million. The increase for the year was primarily due to the increase in production volumes of 20.6 MBoe from 8.1 MBoe to 28.6 MBoe or approximately the whole $1.2 million increase. The increase in volumes of 20.6 MBoe was primarily due to new volumes from Outlar of 6.3 MBoe, Shadyside of 6.8 MBoe Friedrich of 4.8 MBoe and Schroeder of 2.2 MBoe, offset by Walker which decreased 2.0 MBoe and our Kansas wells which decreased, in total, by 1.0 MBoe. The Cason wells also contributed 1.5 MBoe along with Hawkins which contributed 0.7 MBoe.  Total oil production was 7.5 MBoe and total natural gas production was 126.9 MMcf.  Additionally, our revenue variance related to year on year price changes was a slight increase with our average price per Boe increasing by $2.98, or 5.0%, in fiscal 2008 to $59.58 per Bbl from $56.60 per Bbl in fiscal 2007 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 $8.21 per Mcf and weighted average oil volumes at an increased price per barrel of $88.69. We benefited from increased product prices in the year to March 31, 2008, 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.

23

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, 2008 and 2007, our annual income before income taxes would change by approximately $12,000 and $1,000, respectively��for each $0.10 per Mcf change in natural gas prices and approximately $7,000 and $6,000, 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 $0.1 million for the year ended March 31, 2008 as compared to the same period in 2007. The increase was primarily due to production from the new wells in fiscal year 2008 of Outlar, Shadyside, the three Cason wells, Ducroz and Hawkins.  This also included a full year of production for the Friedrich and Schroeder wells that were drilled in fiscal year 2007 and completed in fiscal year 2008.  On a per unit basis, lease operating expenses decreased significantly by $3.34 per Boe to $6.59 per Boe in 2008 from $9.93 per Boe in 2007 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 $0.1 million for the year ended March 31, 2008 as compared to the same period in 2007 due to higher oil and gas revenues, but on a per unit basis decreased $0.26 per Boe to $4.02 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, 2008 increased $0.3 million to $2.2 million compared to the same period in 2007.  The increase in general and administrative expenses was 17% for the fiscal year ended March 31, 2008 versus 163% and 59% for the same period in 2007 and 2006, respectively. We recruited senior management staff in the exploration and production, land and operations and accounting areas and therefore, associated expenses related to salaries, fees, benefits and business expenses for employee/directors increased approximately $0.1 million.   Consulting fees and public company costs increased by approximately $0.2 million with the implementation of Sarbanes Oxley 404 compliance efforts, continued SEC filing fees, investor relations costs and other professional fees as the Company pursues growth strategies.

Stock-based compensation expense, within general and administrative expenses, was $0.3 million for the year ended March 31, 2008 as compared to $0.9 million for the year ended March 31, 2007 for a net decrease of $0.6 million in fiscal 2008. This is primarily due to more stock-based compensation expense in fiscal year 2007 related to a larger stock-based award in 2006 granted to all officers and directors, at the effective date of the reverse merger with Index Ltd., which was largely expensed in fiscal years 2006 and 2007 and not in fiscal year 2008.  This stock-based compensation expense was greater than the stock-based compensation expense generated from new stock awards granted in fiscal year 2008.  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).

Depletion expense increased $0.9 million from the same period in 2007 to $1.1 million for the year ended March 31, 2008. This increase is primarily due to increased volumes as detailed above. 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 proven properties. On a per unit basis, average depletion expense increased 63% from $23.32 to $38.14 per Boe.

Interest income and other decreased $0.1 million for the year ended March 31, 2008 compared to the same period 2007. This decrease is primarily due a reduction in interest income through the use of capital in investing activities of approximately $8.8 million raised from prior year's private placement equity fund raisings.

There was no provision for income taxes for the fiscal years ended 2008 and 2007 due to a valuation allowance of $5.1 million and $2.0  million recorded for the years ended March 31, 2008 and 2007, 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.

24

Liquidity and Capital Resources

Our primary sources of cash in fiscal year 2008 were from financing and equity transactions. Proceeds from private placement equity fund raising was offset by cash used in operating and investing activities for our properties. 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. Working capital was substantially influenced by these variables. Fluctuation in cash flow may result in an increase or decrease in our capital and exploration expenditures. See Results of Operations for a review of the impact of prices and volumes on sales. Cash flows continued to be used in operating activities and did not contribute to funding exploration and development expenditures. See below for additional discussion and analysis of cash flow.

	Years Ended March 31,
	2008			2007
Cash flows (used in) operating activities	$	(1,194,749	)	$	(1,041,751	)
Cash flows (used in) investing activities		(8,792,152	)		(4,098,743	)
Cash flows provided by financing activities		2,397,752			9,740,729
Effect of exchange rate changes		(14,674	)		4,884
Net increase (decrease) in cash and cash equivalents	$	(7,603,823	)	$	4,605,119

Operating Activities

Net cash outflow from operating activities during fiscal year ended March 31, 2008 was $1.2 million which was an increase in use of cash of $0.2 million from $1.0 million net cash outflow during the fiscal year ended March 31, 2007. This increased outflow was primarily due to the increase in receivables associated with higher production and sales, offset by a lower net loss, and adjusted for non-cash items.

Net cash outflow from operating activities during fiscal year ended March 31, 2007 was $1.0 million which was an increase in use of cash of $0.8 million from $0.2 million net cash outflow during the fiscal year ended March 31, 2006. This decrease was primarily due to higher commodity prices and an increase in sales volumes offset by increased general and administrative costs related to a full year of public company expense with increased costs of SEC filing fees, investor relations costs and other professional fees, as well as, an increase in salaries, benefits and business expenses for employees/directors.

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, 2008 was $8.8 million, which was an increase of $4.7 million from $4.1 million of cash used in investing activities during the fiscal year ended March 31, 2007. This increase was primarily due to increased exploration and development activity This activity was primarily for the Shadyside well of approximately $2.5 million, Cason wells of $2.3 million, HNH Gas Unit and the Supple Jack Creek prospect of $2.0 million and Outlar 1 of $0.7 million, with the balance incurred across the remainder of activity on our prospect and drilling portfolio.

Cash used in investing activities during the fiscal year ended March 31, 2007 was $4.1 million, which was an increase of $3.5 million from $0.6 million of cash used in investing activities during the fiscal year ended March 31, 2006. This increase was primarily due to increased exploration and development activity.  This activity was primarily for the Walker well of approximately $0.3 million, the Ilse well of approximately $1.2 million, the Viemanwell of approximately $1.4 million, the Supple Jack Creek (formerly West) well of $0.2 million, Friedrich 1 well of $0.2 million, and Schroeder 1 well of $0.2 million, and the Taffy wells of $0.5 million.

Financing Activities

Net cash provided by financing activities decreased $7.3 million during the fiscal year ended March 31, 2008 to $2.4 million as compared to $9.7 million during the fiscal year ended March 31, 2007, due to private placement transactions providing more capital in fiscal year 2007 than that generated in fiscal year 2008. At March 31, 2008 and 2007, we had no long-term debt outstanding. Management believes that, although we can provide no assurances, we may have the ability to finance through new debt or equity offerings, if necessary, our capital requirements, including acquisitions for the next 12 months.

25

On February 26, 2008, we 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 to purchase 0.50 share of Common Stock, at a purchase price of $0.50 per share, 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 be able to exercise the Loyalty Warrant at that time and thereafter. The net proceeds of the offering were used as working capital and for general corporate purposes of the Company.

Net cash provided by financing activities increased $3.4 million during the fiscal year ended March 31, 2007 to $9.7 million as compared to $6.4 million during the fiscal year ended March 31, 2006. At March 31, 2007 and 2006, we had no long-term debt outstanding. Management believes that we may have the ability to finance through new debt or equity offerings, if necessary, our capital requirements, including acquisitions.

Historically, we have financed our cash needs by private placements of our securities.  We have registered the privately issued securities for resale.  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, 2008 and 2007, our common stock is the only class of stock outstanding and we have no outstanding long-term debt financing.

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.

The following table summarizes our contractual obligations and commitments by payment periods (in thousands).

	Payments Due by Period
Contractual Obligations	Total		Less Than One Year		1-3 Years		3-5 Years		More Than 5 Years
Operating leases (1)	$	6,260	$	6,260	$	--	$	--	$	--
Total contractual obligations	$	6,260	$	6,260	$	--	$	--	$	--

(1) The Company holds an arrangement to rent its main office in Houston with rentals due on a month-to-month basis of $4,500 and an apartment in Houston (for use by UK Executives) with a month-to-month lease of $1,760 per month.

Amounts related to our asset retirement obligations are not included in the table above given the uncertainty regarding the actual timing of such expenditures. Of the total ARO, $88,209 and $41,552 are classified as a long-term liability at March 31, 2008 and 2007, respectively. For each of the years ended March 31, 2008 and 2007, the Company recognized no accretion expense related to its ARO, due to the assumption of a full offset in aggregate of salvage values.

Off-Balance Sheet Arrangements

For the fiscal year ended as of and at March 31, 2008, we did not have any off-balance sheet arrangements.

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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 audit committee. See Results of Operations above and Item 8. Consolidated Financial Statements and Supplementary Data Note 1, Organization and Summary of Significant Events and 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, 2008 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.

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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 new 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, $88,209 and $41,552 are classified as a long-term liability at March 31, 2008 and 2007, respectively. For each of the years ended March 31, 2008 and 2007, the Company recognized no depreciation expense related to its ARO, due to the assumption of a full offset 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.

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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, 2008. 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.

Recently Issued Accounting Standards

Certain Hybrid Instruments. 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 adopted this new standard, effective April 1, 2007, with no impact on its consolidated financial position, results of operations or cash flows as it currently does not have any hybrid instruments outstanding at December 31, 2007 and March 31, 2007, respectively.

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 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 Company adopted this new standard effective April 1, 2007, with no impact on the Company’s consolidated financial position, results of operations or cash flows as the Company does not have any derivative or hedging instruments.

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 adopted the new standard effective April 1, 2007 with no material 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 new pronouncement effective April 1, 2007 with no impact the Company’s consolidated financial position, results of operations or cash flows.

29

New Accounting Pronouncements Not Yet Adopted

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. This Statement 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, this Statement 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.  This Statement shall be effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. Early application is encouraged.  This Statement 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.  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.

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”).  This Statement 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).  This Statement shall be effective 60 days 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.  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 this Statement shall be reported as a change in accounting principle in accordance with FASB Statement No. 154, Accounting Changes and Error Corrections. An entity shall follow the disclosure requirements of that Statement, and additionally, disclose the accounting principles that were used before and after the application of the provisions of this Statement and the reason why applying this Statement resulted in a change in accounting principle. The Company has not yet assesed the impact of this Statement 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 acquiree 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.

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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.

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. Prior to this Statement, there were different definitions of fair value and limited guidance for applying those definitions in GAAP. This Statement provides the definition to increase consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The Statement emphasizes that fair value is a market-based measurement, not an entity-specific measurement. The Statement 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. The Statement expands disclosures about the use of fair vale 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. The Statement 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 November207, the FASB deferred the implementation of SFAS 157 for non-financial assets and liabilities until October 2008.  The Company does not expect adoption of this standard will have a material impact on its consolidated financial position, results of operations or cash flows.

The Fair Value Option for Financial Assets and Financial Liabilities. 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”, 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. The statement applies to all entities, including not-for profit organizations. Most of the provisions of this Statement 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 does not expect adoption of this standard will have a material impact on its consolidated financial position, results of operations or cash flows.

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.

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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, 2008. 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, 2008, 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, 2008 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, 2008, based on criteria in Internal Control – Integrated Framework issued by the COSO.

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, 2008 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 2008 annual meeting or via the filing of an amendment to this Annual Report on Form 10-K.

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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 2008 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 2008 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 2008 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 2008 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(i)(1)1	Articles of Incorporation of Index Oil and Gas Inc., Inc. (4)
3(i)(2)	Certificate of Amendment to the Articles of Incorporation of Index Oil and Gas Inc. (the “Company”), filed with the Secretary of the State of Nevada on November 30, 2005, changing the name of the Company from Thai One On Inc. to Index Oil and Gas Inc., Inc., and increasing the number of authorized shares from 25,000,000 to 75,000,000. (1)
3(i)(2)	Certificate of Amendment to the Articles of Incorporation of Index Oil and Gas Inc. (the “Company”), filed with the Secretary of the State of Nevada on September 21, 2006, increasing the number of authorized shares from 75,000,000 to 500,000,000, and creating a class of preferred stock, authorizing the issuance of 10,000,000 shares, $0.001 par value per share, of preferred stock. (7)
3(ii)	Bylaws of Index Oil and Gas Inc. (4)
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. (1)

33

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. (1)
10.3+	Employment Agreement entered into by and between Index Oil & Gas Ltd and Lyndon West, dated January 20, 2006. (1)
10.4+	Employment Agreement entered into by and between Index Oil & Gas Ltd and Andy Boetius, dated January 20, 2006. (1)
10.5+	Employment Agreement entered into by and between Index Oil & Gas Ltd and Daniel Murphy, dated January 20, 2006. (1)
10.6+	Letter Agreement entered into by and between Index Oil & Gas Ltd and David Jenkins, dated January 20, 2006. (1)
10.7+	Letter Agreement entered into by and between Index Oil & Gas Ltd and Michael Scrutton, dated January 20, 2006. (1)
10.8+	Employment Agreement entered into by and between Index Oil and Gas Inc. and John G. Williams, dated August 29, 2006. (5)
10.9	Form of Subscription Agreement dated as of January 20, 2006. (1)
10.10	Form of Subscription Agreement dated as of August 29 and October 4, 2006. (6)
10.11	Form of Registration Rights Agreement dated as of August 29, 2006. (6)
10.12+	Index Oil and Gas Inc. 2006 Incentive Stock Option Plan. (9)
10.13	Securities Purchase Agreement dated as of November 5, 2007. (10)
10.14	Form of Warrant to Purchase Common Stock. (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. (3)

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. *

34

* Filed Herewith

+ Compensatory plan or arrangement

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

(2) Incorporated by reference to the Company’s Annual Report filed on Form 10-K with the SEC on July 17, 2006.

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

(4) Incorporated by reference to the Company’s Registration Statement filed on Form SB-2 with the SEC on May 24, 2004.

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

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

(7) Incorporated by reference to the Company’s Current Report filed on Form 8-K with the SEC on September 28, 2006.

(8) Incorporated by reference to the Company’s Registration Statement filed on Form SB-2 with the SEC on October 11, 2006.

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

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

35

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: June 30, 2008	By:	/s/ Lyndon West
		Lyndon West
		President and Chief Executive Officer

	INDEX OIL AND GAS INC.
Date: June 30, 2008	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	June 30, 2008
Daniel Murphy
/s/ Lyndon West	Chief Executive Officer and Director	June 30, 2008
Lyndon West
/s/ Andrew Boetius	Chief Financial Officer, (Principal Accounting Officer),	June 30, 2008
Andrew Boetius	(Principal Financial Officer) and Director
/s/ David Jenkins	Director	June 30, 2008
David Jenkins

36

Index to Consolidated Financial Statements

	Page
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets at March 31, 2008 and 2007		F-3
Consolidated Statements of Losses for the Years Ended March 31, 2008 and 2007		F-4
Consolidated Statement of Stockholders’ Equity for the Two Years Ended March 31, 2008 and 2007		F-5
Consolidated Statements of Cash Flows for the Years Ended March 31, 2008 and 2007		F-6
Notes to the Consolidated Financial Statements		F-7 - F-25
Supplemental Oil and Gas Information (Unaudited)		F-26

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, 2008 and 2007 and the related consolidated statements of losses, stockholders’ equity, and cash flows for each of the two years in the period ended March 31, 2008. 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, 2008 and 2007 and the results of its operations and its cash flows for each of the two years in the period ended March 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

/s/ RBSM LLP

New York, New York                                                               

June 30, 2008

F-2

INDEX OIL AND GAS INC.

CONSOLIDATED BALANCE SHEETS

MARCH 31, 2008 AND 2007

	2008			2007
ASSETS
Current Assets:
Cash and cash equivalents (Note 2)	$	2,537,302		$	10,141,125
Trade receivables (Note 3 and Note 12)		970,794			80,342
Other receivables (Note 2)		5,402			6,688
Other current assets (Note 2)		43,460			72,936
Total Current Assets		3,556,958			10,301,091
Oil & Gas Properties, full cost, net of accumulated depletion (Notes 2, 4, 6 and 8)		12,595,091			4,866,050
Property and Equipment, net of accumulated depreciation (Note 2 and 4)		26,031			12,493
Total Oil & Gas  Properties and Property and Equipment		12,621,122			4,878,543
Total Assets	$	16,178,080		$	15,179,634
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued expenses	$	1,025,894		$	814,449
Bank loan (Note 6)		-			-
Other current liability (Note 14 )		-			-
Total Current Liabilities		1,025,894			814,449
Long-Term Liabilities:
Asset Retirement Obligation (Notes 2 and 6)		88,209			41,552
Total Liabilities		1,114,103			856,001
Commitments and Contingencies (Note 8)		-			-
Stockholders Equity: (Notes 9, 10 and 11)
Preferred stock, par value $0.001, 10 million shares authorized, no shares issued and outstanding at March 31, 2008 and 2007 (see Note 9)		-			-
Common stock, par value $0.001, 500 million shares authorized, 71,369,880 and 65,737,036 issued and outstanding at March 31, 2008 and 2007, respectively (see Note 9)		71,370			65,737
Additional paid in capital		21,738,764			19,043,734
Accumulated deficit		(6,747,667	)		(4,801,237	)
Other comprehensive income (Note 2)		1,510			15,399
Total Stockholders’ Equity		15,063,977			14,323,633
Total Liabilities and Stockholders’ Equity	$	16,178,080		$	15,179,634

See accompanying notes to consolidated financial statements

F-3

INDEX OIL AND GAS INC.

CONSOLIDATED STATEMENT OF LOSSES

FOR THE YEARS ENDED MARCH 31, 2008 AND 2007

	2008			2007
Revenue:
Oil & gas sales (Note 2 and Note 12)	$	1,705,593		$	457,046
Operating Expenses:
Operating costs		303,474			114,735
Depreciation and amortization (Note 4)		1,096,229			189,379
General and administrative expenses		2,457,929			2,723,235
Total Operating Expenses		3,857,632			3,027,349
Loss from Operations		(2,152,039	)		(2,570,303	)
Other Income
Interest income		205,609			344,646
Total Other Income		205,609			344,646
Loss before Income Taxes		(1,946,430	)		(2,225,656	)
Income Taxes Benefit (Note 7)		-			-
Net Loss	$	(1,946,430	)	$	(2,225,656	)
Loss per share (Note 11):
Basic and assuming dilution	$	(0.03	)	$	(0.03	)
Weighted average shares outstanding:
Basic and assuming dilution		66,288,104			65,623,189

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, 2008

	Common Stock				Additional Paid in			(Accumulated			Other Comprehensive			Total Stockholders’
	Shares		Amount		Capital			Deficit)			Income/(Loss)			Equity
Balance at March 31, 2006		54,544,345	$	54,544	$	8,387,306		$	(2,575,581	)	$	19,690		$	5,885,959
Issuance of common stock on private offerings		10,965,598		10,966		10,954,632			-			-			10,965,598
Stock issue costs		-		-		(1,190,512	)		-			-			(1,190,512	)
Stock compensation, net of tax of $0		-		-		792,342			-			-			792,342
Issuance of stock upon vesting of stock award		50,000		50		(50	)		-			-			-
Issuance of stock for services, net of tax of $0		40,000		40		63,960			-			-			64,000
Issuance of stock upon exercise of warrants		124,593		125		17,318			-			-			17,443
Issuance of stock for performance bonuses		12,500		12		18,738			-			-			18,750
Other comprehensive income foreign currency translation adjustment		-		-		-			-			(4,291	)		(4,291	)
Net loss		-		-		-			(2,225,656	)		-			(2,225,656	)
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

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, 2008 AND 2007

	2008			2007
Cash Flows From Operating Activities:
Net loss	$	(1,946,430	)	$	(2,225,656	)
Adjustments to reconcile net loss to net cash (used in) operating activities:
Non cash stock based compensation cost		302,911			875,092
Depreciation and amortization		1,096,229			189,379
(Increase) in receivables		(859,427	)		(131,908	)
Increase in accounts payable and accrued expenses		211,968			251,342
Net Cash (Used In) Operating Activities		(1,194,749	)		(1,041,751	)
Cash Flows From Investing Activities:
Payments for property and equipment		(18,094	)		(11,794	)
Payments for oil and gas properties		(8,774,058	)		(4,086,949	)
Net Cash (Used In) Investing Activities		(8,792,152	)		(4,098,743	)
Cash Flows From Financing Activities:
Proceeds from issuance of shares		2,779,923			10,983,039
Payments for bank term debt		-			(51,797	)
Payment for share issue costs		(382,171	)		(1,190,513	)
Net Cash Provided by Financing Activities		2,397,752			9,740,729
Effect of exchange rate changes on cash and cash equivalents		(14,674	)		4,884
Net (Decrease) Increase in Cash And Cash Equivalents		(7,603,823	)		4,605,119
Cash and cash equivalents at beginning of year	$	10,141,125		$	5,536,006
Cash and cash equivalents at the end of year	$	2,537,302		$	10,141,125
Supplemental Disclosures of Cash Flow Information:
Cash received during the year for interest	$	205,608		$	344,646
Cash paid during the year for taxes	$	-		$	-
Non-cash Financing and Investing Transactions:
Non-cash stock based compensation cost	$	302,911		$	875,092

See accompanying notes to consolidated financial statements

F-6

INDEX OIL AND GAS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2008 AND 2007

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, 2008, Index had year-on-year increases in reserves, production and revenue.  The Company sustained its history of drilling success rates, while pursuing higher-impact prospects, all while remaining debt free.  The Company, as described more fully in “Recent Financing”, raised $2.77 million in gross proceeds in a private equity fund raise in a very challenging fiscal environment.  The Company also recruited highly experienced senior staff members in exploration and production, land and operations and in accounting to the Index team.

Reserves increased approximately 92% from 114.6 MBoe (thousand barrels of oil equivalent) proven reserves at March 31, 2007 to 219.469 MBoe at March 31, 2008. Production rose approximately 253% from 8.1 MBoe for the fiscal year ended March 31, 2007 to 28.6 MBoe for the fiscal year ended March 31, 2008.  Correspondingly, revenues increased approximately 273% from $457.0 thousand for the fiscal year ended March 31, 2007 to $1.7 million for the year ended March 31, 2008.

Operations

The Company’s initial exploration project is located in Kansas, and is 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 (“WI”) in the Kansas Area of Mutual Interest ("AMI") wells is either 5% for wells drilled in Stafford County or 3.25% for wells drilled in Barton County and the net revenue interest (“NRI”) is either approximately 4.155% or 2.64%, respectively. The Company has committed to a current program of 14 wells for low-risk prospects in Stafford and Barton Counties. To-date, in this program, the Company has participated in eight wells, of which in June 2008, four are now on production (including one Stafford County well which was drilled under farm in arrangements and in which Index has a 2.5% WI), one is being completed and three have been plugged and abandoned. The two most recent wells with a 3.25% working interest and a 2.64% net revenue interest are the Salem #1-8 well which was completed in April 2008 and the Miller-McReynolds Unit 1-17 which was spudded in April 2008, completed and began production in June 2008.  Further activity is expected at approximately two wells per month dependent on commodity pricing and evaluation of the program to date.  Total net production for the fiscal year ended March 31, 2008 for all Kansas wells was 2,500 Bbls or 15.0 MMcfe (thousand Mcf of natural gas equivalent).

F-7

The Company’s onshore drilling program in Louisiana includes with its interest in the Walker 1 discovery well (WI 12.5%, approximate NRI 9.36%) which was recently recompleted. The Walker 1 well had net production of 10.5 MMcfe in fiscal year 2008, but current production is minimal and is under engineering evaluation.  In April 2007, the Company signed agreements to participate in the Shadyside prospect, located in St. Mary Parish, Louisiana. Index had an initial 15% WI in the prospect, reducing to 13.5% after prospect payout. The Shadyside 1 well was drilled to a total depth of approximately 16,294 feet and due to non-participation by the former operator, Index now has a 30% working interest in the well.  The well has been hooked up and began flowing to sales in January 2008 and net production was approximately 40.6 MMcfe for the fiscal year ended March 31, 2008.  Although the Company is considering the potential of both deeper and shallower prospects on current leases, Shadyside is considered to be a single well project.

The Company’s onshore drilling program in Texas includes its interest in Vieman 1 (19.5% WI, approximate NRI 14.56%) in Brazoria County Texas which began production in February 2007 and has been recompleted.   The Vieman well is shut-in and is under engineering evaluation, but had net production of 3.2 MMcfe in fiscal year 2008.  The Hawkins 1 well (WI 12.5%, approximate NRI 10.01%), also in Texas, in Matagorda County, began production into the local pipeline grid in January 2008 and had net production of 4.5 MMcfe in fiscal year 2008.  In addition, the Company drilled two successful wells in South Texas.  One well, the Friedrich Gas Unit 1 (WI 37.5%, approximate NRI 28.125%), in Victoria County, had net production of approximately 29.0 MMcfe in fiscal year ended 2008.  The second well, the Schroeder Gas Unit 1 (WI 37.5%, approximate NRI 28.125%), in Goliad County, began producing in August 2007, was worked over in March 2008 and had net production of  13.1 MMcfe in fiscal year 2008. The operator is preparing to remediate the Sheroeder Gas Unit 1 in ordert to restore production levels.

The Ilse 1 well (WI 10% Before Project Payout and WI 8% After Project Payout, approximate NRI 6%), drilled in the New Taiton Project area in Wharton County, Texas, has been drilled to total depth of approximately 17,000 feet and logged. Analysis of the logs revealed two zones of interest in the Wilcox C and Wilcox A, respectively. The lowest zone, the Wilcox C, has been perforated and stimulated by a reservoir “fracture” process. Gas flow from the formation to surface has not been achieved. The preliminary decision from the operator was that this interval would not be productive and would not have any proved reserves. The well was suspended, pending a possible test to attempt to achieve gas flows from the upper zone of interest, the Wilcox A.

All non-operator members of the joint venture (“non-operators”), including Index, agreed to a successor operator and requested an audit of the accounting records of the original operator be performed in accordance with the Joint Operating Agreement.  The original operator, however, refused to sign a change in operator form to be filed with the Texas Railroad Commission.  The non-operators filed a Temporary Restraining Order and a Temporary Injunction against the original operator.  This was denied by the Court with parties ordered to mediate.  Mediation was held in October 2007 with no agreement reached.  An Injunction Hearing was held in late 2007 and was placed in continuance status..  Contemporaneous with these Hearing proceedings, non-operators submitted a single-signature P4 (Change of Operator) Form to the Texas Railroad Commission and filed for binding arbitration under the Joint Operating Agreement.

Since July 26, 2007, the Company, as a joint interest owner, has received various Texas Property Code Notices of Intent to File Lien Against Property with regard to materials/equipment sold and/or leased and amounts owed to third parties by the operator of the Ilse property. Under Texas case law, the operator is deemed to be responsible for these unpaid amounts owed to third parties. The Company was billed for these services by the operator on their operating statements received to March 2008 and these costs have been accrued in our consolidated financial statements as costs related to the Ilse well. It is the Company’s position that no other contingency accrual is currently required.

In April 2008, an agreement in principle has been reached between the operator and the non-operators which encompasses (among others) full, mutual releases of all claims against all parties, except one, including any claims of the operator against non-operators for monies allegedly owed under the joint interest billing, and the assignment of non-operators’ interest in the well to the operator.  No monies are due by non-operators in the proposed settlement. A total of $0.3 million in costs at March 31, 2008 that have not been paid to the operator would be discharged.  Upon completion and final execution of the documents, the capital costs which have been discharged by the operator will be reversed out of capital costs and would have a corresponding reduction in current depletion of approximately $1.18 per boe produced.

The George Cason 1 well, drilled on the Fern Lake prospect in Nacogdoches County, Texas and spudded in June 2007, began sales in December 2007 and had net production of approximately 4.6 MMcfe for the fiscal year ended March 31, 2008. The Company has drilled the Cason 2 well which began production in January 2008 and had net production of approximately 4.2 MMcfe for the fiscal year ended March 31, 2008. The Cason 3 well spudded in early February 2008 and began producing at the end of March 2008 for a total net production of 0.2 MMcfe. Index currently has a 25.0% WI and an approximate 18.7% NRI in all three Cason wells. The Company is currently participating, with other partners, in geological analyses on other formations encountered in the wells.  The Cason wells are proving to be challenging in terms of volumes and maintaining production. The operator is currently conducting a series of workover procedures in the wells in an effort to increase production levels.

F-8

The Company is participating in an exploration agreement at 20% WI in the Supple Jack Creek lease area. The first well, HNH Gas Unit 1, targeted gas in the Edwards Limestone in Lavaca County, Texas. The well reached a total depth of approximately 15,000 feet, was sidetracked laterally to approximately 16,000 feet and is currently suspended pending further evaluation of potential logged pay intervals. Subject to results, the Company will evaluate additional drilling, particularly in a success case. The gas unit designated for the well covers 566.59 acres. However, the contract AMI for the overall prospect extends over a much larger area, of which approximately 5,000 gross and net acres are currently under lease.

In June 2007, the Company announced that it had entered into Participation and Joint Operating Agreements for the drilling of the Cow Trap project ("Cow Trap") to be located in Brazoria County, Texas. The Cow Trap well, named Ducroz 1 (WI 7.5%, approximate NRI 5.25%), targets gas in stacked Miocene objectives at depths ranging from 4,900 feet to 6,400 feet. The well had a total depth of approximately 6,500 feet. Ducroz 1 has been drilled, completed and began production in February 2008 for total net production of 9.0 MMcfe for the fiscal year ended March 31, 2008.  Ducroz 1 is considered by the Company to be a single well project.

The Company announced in April 2007 that it has signed a Participation Agreement to explore for gas in the West Wharton prospect. This project could consist of up to four exploration wells within the AMI in Wharton County, Texas. Index has a 10.9% working interest in the project that will reduce to 9.38% after prospect payout. The first well, Outlar 1 (approximate NRI 8.2% before payout, 7.0% after payout), spudded in August 2007 and sales began in December 2007 for a total net production of 38.0 MMcfe net for the fiscal year ended March 31, 2008.  The Company views the West Wharton project as potentially significant for the Company as it has existing leases on up to five well-defined prospects. The second well in this prospect, Stewart 1 was spudded in May 2008.  The Company has also participated in additional leasing opportunities with the operator.

In July 2007, the Company announced that it has signed a Purchase and Sale Agreement to acquire a 5% WI and approximate 3.5% NRI in the Alligator Bayou exploration prospect located beneath onshore portions of Brazoria and Matagorda Counties, Texas. The prospect covers up to several thousand acres. The first well, Armour-Runnells 1, was spudded in April 2008, is currently being drilled and targets gas in the deep, high pressure, high temperature Wilcox formation.  The Company anticipates this well to be the highest potential impact and highest risk well in its portfolio.

Recent Financing:

On February 26, 2008 (the “Closing Date”), the Company closed on a private placement offering (the “Offering”) in which it sold an aggregate 5,541,182 units (the "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 (the “Common Stock”), and one loyalty warrant to purchase 0.50 share of Common Stock, at a purchase price of $0.50, per share 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 be able to exercise the Loyalty Warrant at that time or thereafter.  The Units were sold pursuant to a Securities Purchase Agreement (the “Agreement”) entered into by and between the Company and the purchasers named on the signature page thereto (the “Purchasers”). The net proceeds of the Offering are expected to be used as working capital and for general corporate purposes of the Company.

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:

F-9

Principles of Consolidation

The consolidated financial statements as of March 31, 2008 and 2007 and for the years ended March 31, 2008 and 2007 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.

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. The management periodically evaluates past due or delinquency of accounts receivable in evaluating its allowance for doubtful accounts. There was no allowance for doubtful accounts at March 31, 2008 and 2007.

Other Current Assets

Other receivables at March 31, 2008 and 2007, of $5,402 and $6,688, respectively consist primarily of value added tax recoverable in the United Kingdom by the Company. Other current assets of $43,460 and $72,936 at March 31, 2008 and 2007 consist of prepaid expenses.

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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, 2008 and 2007. 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, 2008 and 2007 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, 2008. 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.

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.

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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, 2008 and 2007, 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, 2008 and 2007, 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, 2008.

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 $(13,889) and $(4,292) for the years ended March 31, 2008 and 2007, 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 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 $88,209 and $41,552 at March 31, 2008 and 2007, 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, 2008 and 2007.

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 consoliated financial position, results of operations or cash flows as the Company does not currently have a defined benefit pension plan.

Certain Hybrid Instruments. 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 to 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, 2008.

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:

1. 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 

c. 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.

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

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

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a. 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.

b. 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.

4. 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.

5. 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.

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-15

New Accounting Pronouncements Not Yet Adopted

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. This Statement 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, this Statement 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.  This Statement shall be effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. Early application is encouraged.  This Statement 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.  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.

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”).  This Statement 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).  This Statement shall be effective 60 days 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.  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 this Statement shall be reported as a change in accounting principle in accordance with FASB Statement No. 154, Accounting Changes and Error Corrections. An entity shall follow the disclosure requirements of that Statement, and additionally, disclose the accounting principles that were used before and after the application of the provisions of this Statement and the reason why applying this Statement resulted in a change in accounting principle. The Company has not yet assesed the impact of this Statment 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 acquiree 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.

F-16

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. Prior to this Statement, there were different definitions of fair value and limited guidance for applying those definitions in GAAP. This Statement provides the definition to increase consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The Statement emphasizes that fair value is a market-based measurement, not an entity-specific measurement. The Statement 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. The Statement expands disclosures about the use of fair vale 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. The Statement 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 does not expect adoption of this standard will have a material impact on its consolidated financial position, operations or cash flows.

The Fair Value Option for Financial Assets and Financial Liabilities. 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”, 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. The statement applies to all entities, including not-for profit organizations. Most of the provisions of this Statement 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 does not expect adoption of this standard will have a material impact on its consolidated financial position, operations or cash flows.

NOTE 3 - TRADE RECEIVABLES

Historically, through March 31, 2008, all of the Company’s trade receivables related to its net revenue interest share of oil and gas sales have been collected. No allowance for doubtful accounts has been recorded at March 31, 2008 and 2007.

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, 2008 and 2007 consist of the following:

	March 31,
	2008		2007
Proved properties	$	11,181,430	$	3,254,211
Unevaluated and unproved properties		2,821,271		1,927,776
Gross oil and gas properties-onshore		14,002,701		5,181,987
Less: accumulated depletion		1,407,610		315,937
Net oil and gas properties-onshore	$	12,595,091	$	4,866,050

Included in the Company's oil and gas properties are asset retirement obligations of $88,209 and $41,552 as of March 31, 2008 and 2007, respectively.

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Depletion expense was $1,091,673 and $188,351 or $38.14 and $23.32 per barrel of production for the years ended March 31, 2008 and 2007, respectively.

It is anticipated that the cost of undeveloped acreage of $860,385 and exploration costs of 1,960,886 will be included in depreciation, depletion and amortization when the related projects are planned and drilled and completed. Included in exploration cost and undeveloped acreage are costs of approximately $0.4 million and $0.4 related to undeveloped leasehold for the Supple Jack Creek and Alligator Bayou, respectively that will be drilled or completed in fiscal year 2009 and approximately $0.1 million related to the West Wharton Project.

At March 31, 2008 and 2007, the Company excluded the following capitalized costs from depletion, depreciation and amortization:

	March 31, 2008		March 31, 2007
Not subject to depletion-onshore:
Exploration costs	$	1,960,886	$	1,669,478
Cost of undeveloped acreage		860,385		258,298
Total not subject to depletion	$	2,821,271	$	1,927,776

Acquisitions and Dispositions

There were no acquisitions or dispositions in the fiscal year ended March 31, 2008 other than those described in Note 1 to these consolidated financial statements.

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, 2008 and 2007 were as follows:

	March 31,
	2007			2006
Computer Costs and Furniture and Fixtures, including foreign translation		$	42,069		$	23,858
Less: accumulated depreciation			16,038			11,365
Total other property and equipment		$	26,031		$	12,493

Depreciation expenses from continuing operations amounted to $4,556 and $1,028 for the years ended March 31, 2008 and 2007, respectively.

Capitalized Interest

There was no interest capitalized in property, plant and equipment at March 31, 2008 and 2007.

NOTE 5 - NOTES PAYABLE

At March 31, 2008 and 2007, there was no outstanding debt.  During the first quarter of fiscal year ended March 31, 2007, Index repaid a one-year bank term note in the amount of $48,569 at the closing exchange rate that had been entered into in the prior fiscal year.  The Company has not entered into any other term or other debt in fiscal year ended March 31, 2008 or 2007. The bank held the following security: a secured debenture including fixed equitable charge over all present and future freehold and leasehold property of Index Ltd; first fixed charge over, among other things, book and other debts, chattels, goodwill and uncalled capital; first floating charge over all assets and undertakings both present and future of Index Ltd.; joint and severable guarantee given by Lyndon West and Michael Scrutton.

F-18

NOTE 6 - ASSET RETIREMENT OBLIGATION

Activity related to the Company’s ARO during the years ended March 31, 2008 and 2007 is as follows:

	March 31,
	2008		2007
ARO as of beginning of period	$	41,552	$	25,300
Liabilities incurred during period		46,657		16,252
Liabilities settled during period		-		-
Accretion expense		-		-
Balance of ARO as of end of period	$	88,209	$	41,552

Of the total ARO, $88,209 and $41,552 are classified as a long-term liability at March 31, 2008 and 2007, respectively. For each of the years ended March 31, 2008 and 2007, the Company recognized no accretion expense related to its ARO, due to the assumption of a full offset of salvage values.

 NOTE 7 - 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, 2008 and 2007, the Company generated for federal income tax purposes a net operating loss carry forward of approximately $13.8 million and $5.2 million (which has been restated based on new estimates) 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, 2008 is in 2028, and this loss can be used to offset future taxable income. However, a valuation allowance of $5.1 million and $2.0 million (which has been restated based on new estimates) was recorded for the years ended March 31, 2008 and 2007, 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 $0.9 million for the years ended March 31, 2008 and 2007, 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,
	2008			2007 (Restated)
Current
UK	$	-		$	-
US		-			-
State		-			-
Total current tax expense (benefit)		-			-
Deferred
UK		(289,526	)		(253,659	)
US		(4,143,281	)		(1,549,612	)
State		(621,492	)		(232,442	)
Total deferred tax expense (benefit)		(5,054,299	)		(2,035,713	)
Less valuation allowance		5,054,299			2,035,713
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,
	2008			2007
Deferred tax assets
Restricted stock compensation accrual	$	-		$	-
Share issue basis difference		-			-
Other		-			-
Oil & Gas basis differences		3,529,359			1,013,912
Depreciation		512,673			200,546
Net operating loss carryforward		2,284,516			1,618,378
Total gross deferred tax assets		6,326,548			2,832,836
Deferred tax liabilities
Amortization of share issue costs		-			-
Other		3,139			2,386
Foreign currency translation		-			-
Oil & Gas basis differences		-			-
Depreciation		521,363			144,735
Stock Compensation		747,747			650,002
Total gross deferred tax liabilities		1,272,249			797,123
Less valuation allowance		(5,054,299	)		(2,035,713	)
Net deferred tax assets	$	-		$	-

NOTE 8 - 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 litigation matters arising from our oil and gas exploration and production activities, except as disclosed in Note 1, 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. The Company also has a month-to-month lease related to corporate housing for UK based officers while periodically working at the corporate office.

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. See Note 13 for Related Party Transactions.

Stockholder Matters

The Company did not bring any matters before the stockholders of record during the fiscal year ended March 31, 2008.

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 9 - CAPITAL STOCK

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 of December 31, 2007	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. The net proceeds of the Offering are expected to be used as working capital and for general corporate purposes of the Company.

In February 2008, the Company issued 75,000 shares of restricted common stock each to Dr. Ron Bain, a manager and consultant to the Company, and to a consulting firm for professional services.  Of the total 150,000 shares of restricted stock issued 85,714 shares of restricted stock vests on June 1, 2008 with the remaining shares of restricted stock vesting on September 1, 2008. 

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.

On August 13, 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.   

F-21

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.

During the fiscal year ended March 31, 2007:

The breakdown of stock issuances of 11,192,691 shares of the Company’s common stock, $0.001 par value, during the year ended March 31, 2007 was as follows:

Issuance of common stock on private offerings	10,965,598
Issuance of stock upon vesting of stock award	50,000
Issuance of stock for services	40,000
Issuance of stock upon exercise of warrants	124,593
Issuance of stock for performance bonuses	12,500
Total	11,192,691

In September 2006, the stockholders of the Company holding the majority of issued and outstanding common stock of the Company approved the increase in authorized common stock of the Company from 75,000,000 shares to 500,000,000 shares and to create 10,000,000 shares of “blank check” preferred stock, $0.001 par value per share (the “Approvals”). Subsequently, the Company filed a Certificate of Amendment to its Articles of Incorporation, as amended, with the Secretary of State of the State of Nevada that was effective as of September 21, 2006. The Amendment was filed to effect the Approvals.

On August 29, 2006, the Company completed the first closing under a private placement offering in which the Company sold 1419.58 units of its securities at a price of $5,000 per unit to certain accredited investors, each unit consisting of 5,000 shares of common stock of the Company for a total of 7,097,898 shares of $0.001 par value common stock of the Company at a price of $1.00 per share for aggregate gross proceeds of approximately $7.1 million. Total fees paid on the first closing of the private placement were approximately $730,000.

Furthermore on October 4, 2006, the Company completed a second closing of the private placement offering in which the Company sold an additional 693.54 units of its securities at a price of $5,000 per unit to certain accredited investors, each unit consisting of 5000 shares of common stock of the Company for gross proceeds of approximately $3.5 million and it subsequently sold another 80 units on October 5, 2006, for a total of 3,867,700 shares of common stock of the Company at a price of $1.00 per share for overall aggregate proceeds of approximately $3.9 million. Total fees paid on the second closing were approximately $316,000. The combined net proceeds of this placement are being applied to the expansion of Company's operations in the U.S.

The purchasers agreed not to sell the Common stock included in the units for a period of six months from the date of their purchase, unless permitted earlier by the Company. Notwithstanding the foregoing, the purchasers further agreed to be bound by any lock-up period required by state or federal regulation. The shares of common stock are restricted securities under Securities Act of 1933, as amended and applicable state securities laws and, therefore, may only be transferred pursuant to the registration requirements of federal and state securities laws or pursuant to an exemption from such registration requirements.

Subsequently, on October 11, 2006 pursuant to the requirements of the Registration Rights Agreement entered into by and among the Company and the Investors, the Company filed a Registration Statement with the SEC on Form SB-2 to register, among other securities, the units of common stock sold in the private placement offering. The Company agreed to have the Registration Statement declared effective by the SEC no later than 180 days from August 29, 2006. If the Company had failed to have the Registration Statement declared effective on or before them time frame described, the Investors would have been entitled to the liquidated damages from the Company in an amount equal to 2% of the aggregate subscription amounts per month for each month that the Company was delinquent in failing to obtain the effectiveness of the Registration Statement, subject to an overall limit of up to 15 months of partial liquidated damages. The Company obtained initial effectiveness on February 9, 2007, within the time frame prescribed. The Company has therefore, not incurred any liability associated with the liquidated damages.

F-22

On August 29, 2006, the Board of Directors appointed John Williams as Executive Vice President of Exploration and Production and a director of the Company effective August 1, 2006. In addition to Mr. Williams’ salary, he was awarded a restricted bonus stock award of 50,000 shares of the Company’s common stock contingent on 183 days of continuous service to the Company. Total compensation expense over the vesting period of $60,000 was recorded on the award at the market price of $1.20 per share, the market price at the date of the grant. The terms of the award were satisfied in January 2007 and Mr. Williams was issued 50,000 shares of restricted common stock of the Company. Additionally, Mr. Williams was awarded a performance bonus of 37,500 shares of restricted common stock per the terms of his bonus program. The shares vest one-third at the date of the grant, March 31, 2007, with the remaining shares vesting at one-third in each of the next two consecutive years. The shares were valued at $1.50 per share of the date of the first vesting award or March 31, 2007 for compensation expense of $18,750.

In February 2007, 40,000 shares of common stock of the Company were issued for legal services related to the filing of the Registration Statement and other services at a value of $1.60 per share for a total cost of $64,000.

In February 2007, 124,593 warrants were exercised into 124,593 shares of common stock at an exercise price of $0.14 per share or $17,443 by a stockholder.

NOTE 10 - 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 excersise requirements, and the related exercise prices for the shares of the Company's common stock issued as follows (See Note 10):

	Number of Shares			Weighted Average Exercise Price Per Share
Outstanding and Exercisable at March 31, 2006		1,092,676		$	0.13
Granted		-			-
Exchanged		-			-
Exercised		(124,593	)		0.14
Canceled or expired		-			-
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

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		2.50	$	0.07		138,655	$	0.07
$	0.14		143,037		2.50	$	0.14		143,037	$	0.14
$	0.14		253,961		2.50	$	0.14		253,961	$	0.14
$	0.14		339,033		2.50	$	0.14		339,033	$	0.14
$	0.14		26,735		2.50	$	0.14		26,735	$	0.14
			901,421		2.50	$	0.13		901,421	$	0.13

F-23

In June 2007, 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.

In February 2007, a total of 124,593 warrants were exercised at a price of $0.14 for a total of $17,443 and a total of 124,593 shares of common stock, $0.001 par value, were issued to stockholder.

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, 2008 and 2007:  (See Note 10).

	Number of Shares			Weighted Average Exercise Price Per Share
Outstanding at March 31, 2006		4,577,526		$	0.35
Granted		500,000		$	1.42
Exercised		-			-
Canceled or expired		-			-
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

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		2.81	$	0.35		4,577,526	$	0.35
$	1.42		250,000		0.33	$	1.42		250,000	$	1.42
$	0.83		125,000		4.47	$	0.83		62,500	$	0.83
$	0.60		100,000		4.76	$	0.60		50,000	$	0.60
$	0.51		150,000		4.82	$	0.51		75,000	$	0.51
			5,202,526		2.82	$	0.42		5,015,026	$	0.41

During the year ended March 31, 2008, the Company issued stock options to purchase 175,000 shares of common stock to two employees, of which 87,500 options vested on the date of the grant.  The Company also issued stock options to purchase 200,000 shares of common stock for professional fees of which 100,000 vested on the date of the grant. All remaining options issued in fiscal year ended March 31, 2008, vest 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.

F-24

On August 13, 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, 250,000 unvested options previously awarded to Mr. Williams in March 2007 were forfeited and the term of exercise for the remaining 250,000 vested options is now approved by the Index Board to end on July 31, 2008. This resulted in a revision in our previous estimate of forfeiture rate for stock options with a corresponding reduction in compensation expense of approximately $20,000 from grant date through September 30, 2007, net of a correction to previously recorded compensation expense on this award of approximately $8,000 during the quarter ended December 31, 2007.  No other compensation expense for this award was recorded in the current year.  In addition, total compensation expense related to the forfeiture of this award of approximately $79,400 will no longer be recorded.

Prior to the reverse merger with Index Inc., Index Ltd. adopted a Stock Option Plan to grant options to various officers, directors and others. As contemplated by the Acquisition Agreements, following the completion of the acquisition the Board of Directors of Index Inc. agreed to the adoption of the Stock Option Plan and ratified it on March 14, 2006 effective as of January 20, 2006, 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 Stock Option Plan, Index Inc. allowed for the issuance of options to purchase 4,577,526 shares of Common Stock at $0.35 per share to newly appointed directors and officers of Index Inc. that had held options to purchase ordinary shares of Index Ltd. prior to the completion of the acquisition.

The principal terms and conditions of the share options granted under the Share Option Plan are that vesting of the options granted occurs in three stages: (1) 50% on grant; (2) 25% one year after grant; and (3) 25% two years after grant. The 2006 options granted are exercisable at $0.35 per share. Furthermore, the share options granted under the Share Option Plan are generally 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 ofoffice 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 $302,911 and $875,092 for the year ended March 31, 2008 and 2007, respectively.  Total stock based compensation expense on unvested restricted stock and unvested stock options remaining at March 31, 2008 is $90,824.

NOTE 11 - 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 years ended March 31, 2008 and 2007, excluded from diluted earnings per share are 901,421 and 968,083, respectively of warrants to acquire common stock. As of both March 31, 2008 and 2007, there are 4,827,526 of options to acquire the Company’s common stock that were excluded from the computation of diluted earnings per share, and which excluded 375,000 of out of the money options at March 31, 2008.

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

	For the year ended March 31,
	2008		2007
Shares—basic		66,288,104		65,623,365
Dilution effect of stock option and awards at end of period		-		-
Shares—diluted		66,288,104		65,623,365
Stock awards and shares excluded from diluted earnings per share due to anti-dilutive effect		5,728,947		5,570,609

NOTE 12 - MAJOR CUSTOMERS

In the 2008 fiscal year ended March 31, 2008, approximately 28%, 25% and 17% 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 2007 fiscal year ended March 31, 2007, approximately 53% and 47% of oil sales were sold to two independent crude oil purchasers.

 NOTE 13 - RELATED PARTY TRANSACTIONS

Lyndon West and Michael Scrutton, jointly and severally, guaranteed the bank loan until it was paid off in June 2006.

Also during fiscal year 2007, the Company incurred a fee of $750 for real estate location services from a firm in which, a principal partner is a shareholder of the Company. The fee was paid in May 2007. 

F-25

INDEX OIL AND GAS INC.

SUPPLEMENTAL INFORMATION (UNAUDITED)

FOR THE YEARS ENDED MARCH 31, 2008, 2007 AND 2006

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, 2008, 2007 and 2006 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 Senior Vice President, Exploration and Production, 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 Senior Vice President, Exploration and Production, 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-26

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, 2008, 2007 and 2006:

	March 31,		March 31,		March 31,
	2008		2007		2006
Proved properties	$	11,181,430	$	3,254,211	$	722,056
Unevaluated & unproved properties		2,821,271		1,927,776		356,729
Total		14,002,701		5,181,987		1,078,785
Less: accumulated depreciation, depletion, amortization		1,407,610		315,937		127,586
Net capitalized costs	$	12,595,091	$	4,866,050	$	951,199

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, 2008, 2007 and 2006:

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. All of the Company's reserves are located in the United States.

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. 

F-27

	Continuing Operations		Discontinued Operations
Year Ended March 31, 2006:	$	486,056	$	-
Acquisition costs of properties
Proved	$	-	$	-
Unproved		-		-
Subtotal		-		-
Exploration and development costs		659,376		-
Total	$	1,145,432	$	-
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	$	-

Results of Operations for Oil and Natural Gas Producing Activities

	Year Ended March 31, 2008			Year Ended March 31, 2007			Year Ended March 31, 2006
Oil and natural gas production revenues
Third-party	$	1,705,593		$	457,046		$	191,114
Affiliate		-			-			-
Total revenues		1,705,593			457,046			191,114
Exploration expenses, including dry hole		-			-			-
Production costs		(303,474	)		(114,735	)		(41,953	)
Impairment		-			-			-
Depreciation, depletion and amortization		(1,091,673	)		(188,351	)		(65,311	)
Income (loss) before income taxes		310,446			153,960			83,850
Income tax provision (benefit)		-			-			-
Results of continuing operations	$	310,446		$	153,960		$	83,850
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-28

Net Proved and Proved Developed Reserve Summary

The following table sets forth the Company’s net proved and proved developed reserves (all within the United States) at March 31, 2008, 2007 and 2006, and the changes in the net proved reserves for each of the two years in the period then ended as estimated by the independent petroleum consultants. See Note 3.

	Continuing Operations			Discontinued Operations
Natural gas (Bcf)(1):
Net proved reserves at March 31, 2005		-			-
Revisions of previous estimates		-			-
Purchases in place		0.144			-
Extensions, discoveries and other additions		-			-
Sales in place		-			-
Production		-			-
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			-

Natural gas liquids and crude oil (MBbls)(2)(3):
Net proved reserves at March 31, 2005	20.591		-
Revisions of previous estimates	1.566		-
Purchases in place	11.565		-
Extensions, discoveries and other additions	5.060		-
Sales in place	-		-
Production	(3.381	)	-
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		-

F-29

(MBO)(2) equivalents(4):
Net proved reserves at March 31, 2005	20.591		-
Revisions of previous estimates	1.566		-
Purchases in place	35.635		-
Extensions, discoveries and other additions	5.060		-
Sales in place	-		-
Production	(3.381	)	-
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		-
Net proved developed reserves:
Natural gas (Bcf)(1)
March 31, 2006	0.090		-
March 31, 2007	0.541		-
March 31, 2008	1.090		-
Natural gas liquids and crude oil (MBbls)(2)(3)
March 31, 2006	28.942		-
March 31, 2007	22.953		-
March 31, 2008	36.677		-
MBO(2) equivalents(4)
March 31, 2006	30.518		-
March 31, 2007	113.198		-
March 31, 2008	218.379		-

(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-30

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, 2008, 2007 and 2006:

	Continuing Operations			Discontinued Operations
	(in $’000)
March 31, 2006:
Future cash inflows	$	3,080.376		$	-
Future production costs		(855.120	)		-
Future development costs		(515.632	)		-
Future income taxes		-			-
Future net cash flows		1,709.624			-
Discount to present value at 10% annual rate		(362.391	)		-
Standardized measure of discounted future net cash flows relating to proved natural gas, natural gas liquids and crude oil reserves	$	1,347.233		$	-

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		$	-

F-31

	Continuing			Discontinued
	Operations			Operations
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		$	-

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, 2008, 2007 and 2006:

	Continuing			Discontinued
	Operations			Operations
	(in $’000)
Balance, April 1, 2005	$	351.775		$	-
Sales and transfers of natural gas, natural gas liquids and crude oil produced, net of production costs		(149.200	)		-
Net changes in prices and production costs		92.288			-
Extensions, discoveries, additions and improved recovery, net of related costs		86.546			-
Development costs incurred		659.376			-
Revisions of previous quantity estimates and development costs		(412.504	)		-
Accretion of discount		(97.672	)		-
Net change in income taxes		-			-
Purchases of reserves in place		813.430			-
Sales of reserves in place		-			-
Changes in timing and other		3.194			-
Balance, March 31, 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		$	-

F-32

Exhibit Index

Exhibit Number	Description
3(i)(1)1	Articles of Incorporation of Index Oil and Gas Inc., Inc. (4)
3(i)(2)	Certificate of Amendment to the Articles of Incorporation of Index Oil and Gas Inc. (the “Company”), filed with the Secretary of the State of Nevada on November 30, 2005, changing the name of the Company from Thai One On Inc. to Index Oil and Gas Inc., Inc., and increasing the number of authorized shares from 25,000,000 to 75,000,000. (1)
3(i)(2)	Certificate of Amendment to the Articles of Incorporation of Index Oil and Gas Inc. (the “Company”), filed with the Secretary of the State of Nevada on September 21, 2006, increasing the number of authorized shares from 75,000,000 to 500,000,000, and creating a class of preferred stock, authorizing the issuance of 10,000,000 shares, $0.001 par value per share, of preferred stock. (7)
3(ii)	Bylaws of Index Oil and Gas Inc. (4)
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. (1)
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. (1)
10.3+	Employment Agreement entered into by and between Index Oil & Gas Ltd and Lyndon West, dated January 20, 2006. (1)
10.4+	Employment Agreement entered into by and between Index Oil & Gas Ltd and Andy Boetius, dated January 20, 2006. (1)
10.5+	Employment Agreement entered into by and between Index Oil & Gas Ltd and Daniel Murphy, dated January 20, 2006. (1)
10.6+	Letter Agreement entered into by and between Index Oil & Gas Ltd and David Jenkins, dated January 20, 2006. (1)
10.7+	Letter Agreement entered into by and between Index Oil & Gas Ltd and Michael Scrutton, dated January 20, 2006. (1)
10.8+	Employment Agreement entered into by and between Index Oil and Gas Inc. and John G. Williams, dated August 29, 2006. (5)
10.9	Form of Subscription Agreement dated as of January 20, 2006. (1)
10.10	Form of Subscription Agreement dated as of August 29 and October 4, 2006. (6)
10.11	Form of Registration Rights Agreement dated as of August 29, 2006. (6)
10.12+	Index Oil and Gas Inc. 2006 Incentive Stock Option Plan. (9)
10.13	Securities Purchase Agreement dated as of November 5, 2007. (10)
10.14	Form of Warrant to Purchase Common Stock. (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. (3)
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 Amended Current Report filed on Form 8-K/A with the SEC on March 15, 2006.

(2) Incorporated by reference to the Company’s Annual Report filed on Form 10-K with the SEC on July 17, 2006.

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

(4) Incorporated by reference to the Company’s Registration Statement filed on Form SB-2 with the SEC on May 24, 2004.

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

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

(7) Incorporated by reference to the Company’s Current Report filed on Form 8-K with the SEC on September 28, 2006.

(8) Incorporated by reference to the Company’s Registration Statement filed on Form SB-2 with the SEC on October 11, 2006.

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

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