Forward Looking Statements

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

Business Overview

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

Results of Operations

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

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

                                            Years Ended March 31,           Increase
                                            2009             2008          (Decrease)

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

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


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

                                                                   Years Ended March 31,

                                                                   2009             2008

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

Operating Activities

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

Investing Activities

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

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

Financing Activities

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

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

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

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

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

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

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

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

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

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

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

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

Contractual Obligations

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

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

Off-Balance Sheet Arrangements

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

Critical Accounting Policies and Estimates

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

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

. . .