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





Commission
File No. 000-51430


_______________





INDEX
OIL AND GAS INC.


(Exact
Name of Registrant as Specified in Its Charter)





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





10000
Memorial Drive, Suite 440


Houston,
Texas 77024


(Address
of principal executive offices, including zip code)


(713) 683-0800


(Registrant’s
telephone number, including area code)





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





None





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





Common
Stock, $0.001








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





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





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





Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this
chapter) during the preceding 12 months (or for such shorter period that
the registrant was required to submit and post such files). Yes £     No R





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





Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a small reporting company. See
definitions of “large accelerated filer”, “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act. (Check
one):




Large
accelerated filer £                                                            Accelerated
Filer £


Non-accelerated
Filer £                                                            
Smaller reporting company  R


(Do not
check if a smaller reporting company)





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





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





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





Documents
Incorporated by Reference





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

















TABLE
OF CONTENTS





PART
      I
                3Item
      1.  Business
                3Item
      1A.  Risk Factors
                10Item
      1B.  Unresolved Staff Comments
                17Item
      2.  Properties.
                18Item
      3.  Legal Proceedings.
                22Item
      4.  Submission of Matters to a Vote of Security
      Holders.
                22PART
      II
                24Item
      5.  Market For Registrant’s Common Equity, Related Stockholder
      Matters and Issuer Purchases of Equity Securities.
                24Item
      6.  Selected Financial Data.
                26Item
      7.  Management’s Discussion and Analysis of Financial Condition
      and Results of Operations.
                26Item
      7A.  Quantitative and Qualitative Disclosures About Market
      Risk.
                33Item
      8.  Financial Statements and Supplementary Data.
                34Item
      9.  Changes in and Disagreements With Accountants on Accounting
      and Financial Disclosure.
                34Item
      9A. Controls and Procedures.
                34Item
      9A(T).  Controls and Procedures.
                34Item
      9B.  Other Information.
                34PART
      III
                35Item
      10. Directors, Executive Officers, and Corporate
    Governance.
                35Item
      11. Executive Compensation.
                35Item
      12. Security Ownership of Certain Beneficial Owners and Management and
      Related Stockholder Matters.
                35Item
      13.  Certain Relationships and Related Transactions, and
      Director Independence.
                35Item
      14.  Principal Accountant Fees and Services.
                35PART
      IV
                36Item
      15. Exhibits and Financial Statement Schedules.
                36SIGNATURES
                37











Cautionary
Note Regarding Forward Looking Statements





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





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





•           our
ability to attract and retain management;


•           our
growth strategies;


•           anticipated
trends in our business;


•           our
future results of operations;


•           our
ability to make or integrate acquisitions;


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


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


•           market
conditions in the oil and natural gas industry;


•           the
timing, cost and procedure for acquisitions;


•           the
impact of government regulation;


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


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


•           increases
in oil and natural gas production;


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


•           estimates,
plans and projections relating to acquired properties;


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


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


•           the
possibility that our acquisitions may involve unexpected costs;


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


•           the
accuracy of internally estimated proved reserves;


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


•           the
ability to replace oil and natural gas reserves;


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


•           environmental
risks;


•           exploration
and development risks;


•           competition;


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


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





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












PART
I





Item  1.  Business





Organization





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





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





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





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





Overview





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





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





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





3


Going
Concern Issues





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





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





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





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





Strengths
and Strategies





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





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




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





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





4


Our
Operating Areas




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





Kansas





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





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





Louisiana





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





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




Texas





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





5


Texas
      ProductionYear
      ending March 31, 2009Well
      name
                
                Gas,
      MMcf
                
                
                Oil,
      MBbl
                
                
                Equivalent,
      MBoe
                
                
                Equivalent,
      MMcfeVieman
      1
                
                
                2.382
                
                
                
                0.005
                
                
                
                0.402
                
                
                
                2.413Hawkins
      1
                
                
                27.352
                
                
                
                0.005
                
                
                
                4.564
                
                
                
                27.352Freidrich
      Gas Unit 1
                
                
                29.708
                
                
                
                0.000
                
                
                
                4.951
                
                
                
                29.708Schroeder
      Gas Unit 1
                
                
                1.421
                
                
                
                0.000
                
                
                
                0.237
                
                
                
                1.421Cason
      wells *
                
                
                14.661
                
                
                
                0.000
                
                
                
                2.444
                
                
                
                14.661Outlar
      1
                
                
                71.022
                
                
                
                4.412
                
                
                
                16.249
                
                
                
                97.493Ducroz
      1
                
                
                36.692
                
                
                
                0.034
                
                
                
                6.149
                
                
                
                36.894Cochran
      1
                
                
                12.856
                
                
                
                0.190
                
                
                
                2.333
                
                
                
                13.998Total
                
                
                196.094
                
                
                
                4.646
                
                
                
                37.328
                
                
                
                223.940





*   Cason
1, Cason 2 and Cason 3




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





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


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


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


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





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





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





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





Alligator
Bayou prospect:





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





Garwood
field:





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





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




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







6





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





Our
Industry





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





Competitive
Conditions in the Business





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




Customers





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





Seasonality
of Business





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





Operational
Risks





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





Governmental
Regulation





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




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










7






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






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





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





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




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





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





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





Federal,
State or Native American Leases





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





8


Waste
Handling





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





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





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





Compliance
– General





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





Employees





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




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





Access
to Company Reports





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





Corporate
Governance Matters





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





9


Item  1A.  Risk
Factors





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





Risks
Related To Index’s Financial Results





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





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





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





•           Continue
to develop our oil exploration and production assets;





•           Respond
to competitive developments; and





•           Attract,
integrate, retain and motivate qualified personnel.





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




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





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





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





•           identify
and exploit oil and natural gas opportunities;





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





•           evaluate
drilling opportunities; and





•           evaluate
future projects and areas for long term development.





10


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





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





•           success
of ongoing operations;





•           forward
commodity prices; and





•           operating
costs (including human resources costs).





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





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





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





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





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




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





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





Risks
Related to Our Business





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





We do not
operate any of our properties. The success of the drilling, development,
production and marketing of the oil and natural gas from our properties is
dependent upon the decisions of such third-party operators and their diligence
to comply with various laws, rules and regulations affecting such properties.
The failure of any third-party operator to make decisions, perform their
services, discharge their obligations, deal with regulatory agencies, and comply
with laws, rules and regulations, including environmental laws and regulations
in a proper manner with respect to properties in which we have an interest could
result in material adverse consequences to our interest in such properties,
including substantial penalties and compliance costs. Such adverse consequences
could result in substantial liabilities to us or reduce the value of our
properties, which could negatively affect our results of
operations.





11


Our
operators may be unable to renew or maintain contracts with independent
purchasers, which would harm our business and financial results.





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





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





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





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





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





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




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





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





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





12


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





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





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





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





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





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




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





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




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








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





13


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





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





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





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




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





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





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





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





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





14


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





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





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





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





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





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




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





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





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





The
price of our Common Stock may be volatile.





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





•
            our
      results of operations and the performance of our
    competitors;


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


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


•
            changes
      in general economic conditions;


•
            changes
      in market prices for oil and gas;


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


•
            actions
      by institutional investors trading in our
stock;


•
            disruption
      of our operations;


•
            any
      major change in our management
team;


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


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





15


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





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





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





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


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





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





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


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





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





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


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





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





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





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





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





•
            institute
      a comprehensive compliance
function;


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


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


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


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


•
            establish
      an investor relations function.





16


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





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





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





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





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





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





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





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





Item  1B.  Unresolved
Staff Comments





None





17


Item  2.  Properties.





Principal
Executive Offices





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





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





Oil
and Gas Reserves





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




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





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





In
      MBoe:
                
                Kansas
                
                
                Louisiana
                
                
                Texas
                
                
                TotalProved
      Reserves at Year EndDeveloped
                
                
                11.046
                
                
                
                --
                
                
                
                59.833
                
                
                
                70.879Undeveloped
                
                
                --
                
                
                
                --
                
                
                
                16.824
                
                
                
                16.824Total
                
                
                11.046
                
                
                
                --
                
                
                
                76,657
                
                
                
                87.703Gross
      Wells (1)
                
                
                29.000
                
                
                
                1.000
                
                
                
                8.000
                
                
                
                38.000Net
      Wells (1)
                
                
                1.3725
                
                
                
                0.1250
                
                
                
                1.4688
                
                
                
                2.9663





(1)
            Gross wells or acreage means
      the total wells or acreage in which a working interest is owned, and net
      wells or acreage means the sum of the fractional working interests owned
      in gross wells or acreage, as the case may
  be.





18


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





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





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




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




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





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





Productive
Wells and Acreage





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





Acreage





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





Developed
      Acreage
                
                
                Undeveloped
      Acreage
                
                
                Total
      AcreageState
                
                Gross
                
                
                Net
                
                
                Gross
                
                
                Net
                
                
                Gross
                
                
                NetKansas
                
                
                3,654.00
                
                
                
                168.14
                
                
                
                1,090.30
                
                
                
                58.83
                
                
                
                4,744.30
                
                
                
                226.97Louisiana
                
                
                132.00
                
                
                
                16.53
                
                
                
                —
                
                
                
                —
                
                
                
                132.00
                
                
                
                16.53Texas
                
                
                1,917.02
                
                
                
                205.52
                
                
                
                21,645.13
                
                
                
                1,750.26
                
                
                
                23,562.15
                
                
                
                1,955.78Total
      Acreage
                
                
                5,703.02
                
                
                
                390.19
                
                
                
                22,735.43
                
                
                
                1,809.09
                
                
                
                28,438.45
                
                
                
                2,199.28




19


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





2009
                
                
                2010
                
                
                2011
                
                
                ThereafterGross
                
                
                Net
                
                
                Gross
                
                
                Net
                
                
                Gross
                
                
                Net
                
                
                Gross
                
                
                NetUndeveloped
      Acreage
                
                
                5,823.31
                
                
                
                724.17
                
                
                
                16,896.54
                
                
                
                1,083.21
                
                
                
                15.58
                
                
                
                1.71
                
                
                
                --
                
                
                
                --




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





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




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





March
      31,2009
                
                
                2008
                
                
                2007Capitalized
      costs:Proved
      and evaluated properties
                
                $
                4,878,182
                
                
                $
                11,181,430
                
                
                $
                3,254,211Unproved
      and unevaluated properties
                
                
                4,878,940
                
                
                
                2,821,271
                
                
                
                1,927,7769,757,122
                
                
                
                14,002,701
                
                
                
                5,181,987Less
      accumulated depreciation and depletion
                
                
                3,493,586
                
                
                
                1,407,610
                
                
                
                315,937$
                6,263,536
                
                
                $
                12,595,091
                
                
                $
                4,866,050




20


Production





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





Years
      Ended March 31,2009
                
                
                2008
                
                
                2007Gas
      production (MMcf):
                
                
                237.381
                
                
                
                126.888
                
                
                
                8.4900Oil
      production (MBbl)
                
                
                8.216
                
                
                
                7.478
                
                
                
                6.660Equivalent
      production (MBoe)
                
                
                47.779
                
                
                
                28.626
                
                
                
                8.075Average
      price per unit:Gas
      (per Mcf)
                
                $
                8.79
                
                
                $
                8.21
                
                
                $
                6.61Oil
      (per Bbl)
                
                $
                90.31
                
                
                $
                88.69
                
                
                $
                60.20Equivalent
      (per Boe)
                
                $
                59.20
                
                
                $
                59.58
                
                
                $
                56.60




Drilling
Activity





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





Years
      Ended March 31,2009
                
                
                2008
                
                
                2007Gross
                
                
                Net
                
                
                Gross
                
                
                Net
                
                
                Gross
                
                
                NetGross
      Exploratory Wells:Productive
                
                
                4.00
                
                
                
                0.165
                
                
                
                10.00
                
                
                
                2.019
                
                
                
                5.00
                
                
                
                0.2150Dry
                
                
                1.00
                
                
                
                0.094
                
                
                
                3.00
                
                
                
                0.150
                
                
                
                4.00
                
                
                
                0.6825Total
      Exploratory
                
                
                5.00
                
                
                
                0.259
                
                
                
                13.00
                
                
                
                2.169
                
                
                
                9.00
                
                
                
                0.8975Gross
      Development Wells:Productive
                
                
                2.00
                
                
                
                0.100
                
                
                
                1.00
                
                
                
                0.075
                
                
                
                1.00
                
                
                
                0.195Dry
                
                
                --
                
                
                
                --
                
                
                
                --
                
                
                
                --
                
                
                
                --
                
                
                
                --Total
      Development
                
                
                2.00
                
                
                
                0.100
                
                
                
                1.00
                
                
                
                0.075
                
                
                
                1.00
                
                
                
                0.195Total
      Gross Wells:Productive
                
                
                6.00
                
                
                
                0.265
                
                
                
                11.00
                
                
                
                2.094
                
                
                
                6.00
                
                
                
                0.323Dry
                
                
                1.00
                
                
                
                0.094
                
                
                
                3.00
                
                
                
                0.150
                
                
                
                4.00
                
                
                
                0.518Total
                
                
                7.00
                
                
                
                0.359
                
                
                
                14.00
                
                
                
                2.244
                
                
                
                10.00
                
                
                
                0.841





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






21


Present
Activities





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





Delivery
Commitments





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





Item  3.  Legal
Proceedings.





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





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





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





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





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





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




22


The
vote tallies were as follows:





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





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








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





For
                
                
                Against
                
                
                Abstain36,276,720
                
                
                
                41,589
                
                
                
                1,600,100








(3)             Ratification
of the 2008 Stock Incentive Plan.





For
              
              
              Against
              
              
              Abstain16,912,165
              
              
              
              3,925,748
              
              
              
              6,267,393








23


PART
II





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





Market
Information





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





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





High
                
                
                Low2008
      Fiscal YearJune
      30, 2007
                
                
                1.50
                
                
                
                0.78September
      30, 2007
                
                
                1.07
                
                
                
                0.70December
      31, 2007
                
                
                0.84
                
                
                
                0.49March
      31, 2008
                
                
                0.64
                
                
                
                0.472009
      Fiscal YearJune
      30, 2008
                
                
                0.87
                
                
                
                0.54September
      30, 2008
                
                
                0.64
                
                
                
                0.24December
      31, 2008
                
                
                0.32
                
                
                
                0.07March
      31, 2009
                
                
                0.44
                
                
                
                0.07





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





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





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





24


Holders





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




Dividends





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





Securities
Authorized for Issuance Under Equity Compensation Plans





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





Plan
      Category
                
                Number
      of securities to be issued upon exercise of outstanding options, warrants
      and rights
                
                
                Weighted
      average exercise price of outstanding options, warrants and
      rights
                
                
                Number
      of securities remaining available for future issuance under equity
      compensation plans (excluding securities reflected in column (a))
      *(a)
                
                
                (b)
                
                
                (c)Equity
      compensation plans approved by security holders
                
                
                4,952,526
                
                
                $
                0.37
                
                
                
                5,441,037Equity
      compensation plans not approved by security holders
                
                
                -0-
                
                
                $
                -0-
                
                
                
                -0-Total
                
                
                4,952,526
                
                
                $
                0.37
                
                
                
                5,441,037





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





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





25


Unregistered
Sales of Equity Securities and Use of Proceeds





Issuance
of Unregistered Securities





None.





Purchases
of Equity Securities by the Issuer and Affiliated Purchasers.





None.




Item  6.  Selected
Financial Data.





Not
Applicable.





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





Forward
Looking Statements





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




Business
Overview





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





Results
of Operations





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





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





Years
      Ended March 31,
                
                
                Increase2009
                
                
                2008
                
                
                (Decrease)Oil
      and gas sales
                
                $
                2,828,751
                
                
                $
                1,705,593
                
                
                $
                1,123,158Production
      expenses:Lease
      operating
                
                
                520,434
                
                
                
                188,521
                
                
                
                331,913Taxes
      other than income
                
                
                183,748
                
                
                
                114,952
                
                
                
                68,796General
      and administrative:General
      and administrative
                
                
                2,218,695
                
                
                
                2,155,018
                
                
                
                63,677Stock-based
      compensation
                
                
                211,748
                
                
                
                302,911
                
                
                
                (91,163
                )Depletion
      — Full cost
                
                
                2,085,976
                
                
                
                1,091,673
                
                
                
                994,303Depreciation
      — Other
                
                
                8,506
                
                
                
                4,556
                
                
                
                3,949Impairment
                
                
                7,002,472
                
                
                
                --
                
                
                
                7,002,472Interest
      expense (income) and other
                
                
                (24,207
                )
                
                
                (205,608
                )
                
                
                181,401Income
      tax benefit (provision)
                
                
                --
                
                
                
                --
                
                
                
                --Net
      income (loss)
                
                $
                (9,378,621
                )
                
                $
                (1,946,430
                )
                
                $
                (7,432,191)Production:Natural
      Gas — MMcf
                
                
                237.381
                
                
                
                126.888
                
                
                
                110.493Crude
      Oil — MBbl
                
                
                8.216
                
                
                
                7.478
                
                
                
                0.738Equivalent
      — MBoe
                
                
                47.779
                
                
                
                28.626
                
                
                
                19.153Average
      price per unit:Gas
      price per Mcf
                
                $
                8.79
                
                
                $
                8.21
                
                
                $
                0.58Oil
      price per Bbl
                
                $
                90.31
                
                
                $
                88.69
                
                
                $
                1.62Equivalent
      per Boe
                
                $
                59.20
                
                
                $
                59.58
                
                
                $
                (0.38)Average
      cost per Boe:Production
      expenses:Lease
      operating
                
                $
                10.89
                
                
                $
                6.59
                
                
                $
                4.30Taxes
      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





26


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





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





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





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





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





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




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





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





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





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





27


Liquidity
and Capital Resources





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





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





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





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





Years
      Ended March 31,2009
                  
                  
                  2008Cash
      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
                  
                  
                  --
                  
                  
                  
                  2,397,752Effect
      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.





28


Liquidity
Issues and Going Concern Issues





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





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





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





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





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





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.





29


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





Contractual
Obligations





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





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





Off-Balance
Sheet Arrangements





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




Critical
Accounting Policies and Estimates





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





30


Oil
and Gas Activities





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





Full
Cost Method





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





Proved
Oil and Gas Reserves





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





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




Depreciation,
Depletion and Amortization





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





Full
Cost Ceiling Limitation





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





31


Future
Development and Abandonment Costs





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





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





Allocation
of Purchase Price in Business Combinations





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





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




Revenue
Recognition





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





Recent
Accounting Developments





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





32


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 value to measure assets and
liabilities in interim and annual periods subsequent to initial recognition. The
disclosures focus on the inputs used to measure fair value and for recurring
fair value measurements using significant unobservable inputs, the effect of the
measurements on earnings for the period. The FASB also issued FASB Staff
Position (“FSP”) FAS 157-2 (“FSP No. 157-2”), which delayed the effective date
of SFAS No. 157 for nonfinancial assets and liabilities, except for items that
are recognized or disclosed at fair value in the financial statements on a
recurring basis (at least annually), until fiscal years beginning after November
15, 2008. We are still in the process of evaluating the effect of SFAS No. 157
on our nonfinancial assets and liabilities and therefore have not yet determined
the impact that it will have on our financial statements upon full adoption The
initial adoption of SFAS 157 did not have a material impact on the company’s
consolidated financial position, results of operations or cash
flows.





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





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





Not
applicable.





33


Item  8.  Financial
Statements and Supplementary Data.





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





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





None.





Item  9A.
Controls and Procedures.





Not
Applicable.




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





Evaluation
of Disclosure Controls and Procedures




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




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




Management’s
Annual Report on Internal Control Over Financial Reporting





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





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





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





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





Changes
in Internal Control Over Financial Reporting




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







Item  9B.  Other
Information.





None.





34





PART
III





Item  10.
Directors, Executive Officers and Corporate Governance.




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




Item  11.
Executive Compensation.





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





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





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




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





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





Item  14.  Principal
Accountant Fees and Services.





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





35


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
              
              Description3.1
              
              Restated
      Articles of Incorporation of Index Oil and Gas Inc., Inc.
      (1)3.2
              
              Bylaws
      of Index Oil and Gas Inc. (2)10.1
              
              Acquisition
      Agreement between Index Oil and Gas Inc., certain stockholders of Index
      Oil & Gas Ltd, and Briner Group Inc. dated January 20, 2006.
      (3)10.2
              
              Form
      of Share and Warrant Exchange Agreement entered into by and between Index
      Oil and Gas Inc., Inc. and certain Index Oil & Gas Ltd stockholders.
      (3)10.3+
              
              Employment
      Agreement entered into by and between Index Oil & Gas Ltd and Lyndon
      West, dated January 20, 2006. (3)10.4+
              
              Employment
      Agreement entered into by and between Index Oil & Gas Ltd and Andy
      Boetius, dated January 20, 2006. (3)10.5+
              
              Employment
      Agreement entered into by and between Index Oil & Gas Ltd and Daniel
      Murphy, dated January 20, 2006. (3)10.6+
              
              Letter
      Agreement entered into by and between Index Oil & Gas Ltd and David
      Jenkins, dated January 20, 2006. (3)10.7+
              
              Letter
      Agreement entered into by and between Index Oil & Gas Ltd and Michael
      Scrutton, dated January 20, 2006. (3)10.8+
              
              Employment
      Agreement entered into by and between Index Oil and Gas Inc. and John G.
      Williams, dated August 29, 2006. (4)10.9
              
              Form
      of Subscription Agreement dated as of January 20, 2006.
      (3)10.10
              
              Form
      of Subscription Agreement dated as of August 29 and October 4, 2006.
      (5)10.11
              
              Form
      of Registration Rights Agreement dated as of August 29, 2006.
      (5)10.12+
              
              Index
      Oil and Gas Inc. 2006 Incentive Stock Option Plan.
    (6)10.13
              
              Securities
      Purchase Agreement dated as of November 5, 2007.
  (7)10.14
              
              Form
      of Warrant to Purchase Common Stock. (7)10.15+
              
              Agreement
      for Exploration, Production and Strategic Services dated February 1, 2008
      between the Company and ConRon Consulting Inc., as amended by Addendum #1
      dated June 1, 2008 and Addendum #2 dated July 1, 2008.
  (8)10.16+
              
              Amended
      and Restated Agreement for Exploration, Production and Strategic Services
      between Index Oil and Gas Inc. and ConRon Consulting Inc. dated December
      8, 2008. (9)10.17+
              
              Amended
      Employment Agreement of Daniel Murphy, dated March 4, 2009.
      (10)10.18+
              
              Amended
      Employment Agreement of Lyndon West, dated March 4, 2009.
    (10)10.19+
              
              Amended
      Employment Agreement of Andrew Boetius, dated March 4, 2009.
      (10)14.1
              
              Code
      of Ethics and Business Conduct for officers, directors and employees of
      Index Oil and Gas Inc. adopted by the Company’s Board of Directors on
      March 31, 2006. (11)21.1
              
              List
      of subsidiaries of the Company. *23.1
              
              Consent
      of RBSM LLP. *23.2
              
              Consent
      of Ancell Energy Consulting, Inc. *31.1
              
              Certification
      by Chief Executive Officer required by Rule 13a-14(a) or Rule 15d-14(a) of
      the Exchange Act. *31.2
              
              Certification
      by Chief Financial Officer required by Rule 13a-14(a) or Rule 15d-14(a) of
      the Exchange Act. *32.1
              
              Certification
      by Chief Executive Officer required by Rule 13a-14(b) or Rule 15d-14(b) of
      the Exchange Act and Section 1350 of Chapter 63 of Title 18 of the United
      States Code. *32.2
              
              Certification
      by Chief Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) of
      the Exchange Act and Section 1350 of Chapter 63 of Title 18 of the United
      States Code. *




*
      Filed Herewith+
      Compensatory plan or arrangement(1)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on September 5, 2008.(2)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on October 9, 2008.(3)
      Incorporated by reference to the Company’s Amended Current Report filed on
      Form 8-K/A with the SEC on March 15, 2006.(4)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on September 8, 2006.(5)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on September 11, 2006.(6)
      Incorporated by reference to the Company’s Registration Statement filed on
      Form S-8 with the SEC on October 3, 2007.(7)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on February 29, 2008.(8)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on July 8, 2008.(9)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on December 12, 2008.(10)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on March 6, 2009.(11)
      Incorporated by reference to the Company’s Annual Report filed on Form
      10-KSB with the SEC on April 10,
2006.




36











SIGNATURES




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




INDEX
      OIL AND GAS INC.Date: July
      10, 2009
            By:
            /s/ Lyndon
    WestLyndon
      WestPresident
      and Chief Executive Officer




INDEX
      OIL AND GAS INC.Date: July
      10, 2009
            By:
            /s/ Andrew
      BoetiusAndrew
      BoetiusChief
      Financial Officer, (Principal Accounting Officer and Principal Financial
      Officer)




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




Signature
            
            Title
            
            Date/s/
      Daniel
      Murphy
            
            Chairman
      of the Board
            
            July
      10, 2009Daniel
      Murphy/s/
      Lyndon
      West
            
            Chief
      Executive Officer and Director
            
            July
      10, 2009Lyndon
      West/s/
      Andrew
      Boetius
            
            Chief
      Financial Officer, (Principal Accounting Officer),
            
            July
      10, 2009Andrew
      Boetius
            
            (Principal
      Financial Officer) and Director/s/David
      Jenkins
            
            Director
            
            July
      10, 2009David
      Jenkins







37





Index
to Consolidated Financial Statements








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








F-1


















REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





Board of
Directors


Index Oil
and Gas Inc.


Houston,
USA





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





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





In our
opinion, the financial statements referred to above present fairly, in all
material respects, the financial position of Index Oil and Gas Inc. at March 31,
2009 and 2008 and the results of its operations and its cash flows for each of
the two years in the period ended March 31, 2009, in conformity with accounting
principles generally accepted in the United States of America.





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







/s/ RBSM
LLP





New York,
New
York


July 10,
2009








F-2










INDEX
OIL AND GAS INC.


CONSOLIDATED
BALANCE SHEETS


MARCH
31, 2009 AND 2008




2009
                      
                      
                      2008ASSETSCurrent
      Assets:Cash
      and cash equivalents (Note 2)
                      
                      $
                      335,817
                      
                      
                      $
                      2,537,302Trade
      receivables (Note 3 and Note 13)
                      
                      
                      326,737
                      
                      
                      
                      970,794Other
      receivables (Note 2)
                      
                      
                      5,144
                      
                      
                      
                      5,402Other
      current assets (Note 2)
                      
                      
                      41,157
                      
                      
                      
                      43,460Total
      Current Assets
                      
                      
                      708,855
                      
                      
                      
                      3,556,958Oil
      & Gas Properties, full cost, net of accumulated depletion (Notes 2, 4,
      7 and 9)
                      
                      
                      6,263,537
                      
                      
                      
                      12,595,091Property
      and Equipment, net of accumulated depreciation (Notes 2 and
      4)
                      
                      
                      21,595
                      
                      
                      
                      26,031Total
      Oil & Gas  Properties and Property and
      Equipment
                      
                      
                      6,285,132
                      
                      
                      
                      12,621,122Total
      Assets
                      
                      $
                      6,993,987
                      
                      
                      $
                      16,178,080LIABILITIES
      AND STOCKHOLDERS’ EQUITYCurrent
      Liabilities:Accounts
      payable and accrued expenses
                      
                      $
                      978,856
                      
                      
                      $
                      1,025,894Asset
      Retirement Obligation (Notes 2 and 7)
                      
                      
                      125,716
                      
                      
                      
                      -Total
      Current Liabilities
                      
                      
                      1,104,572
                      
                      
                      
                      1,025,894Long-Term
      Liabilities:Asset
      Retirement Obligation (Notes 2 and 7)
                      
                      
                      14,998
                      
                      
                      
                      88,209Total
      Liabilities
                      
                      
                      1,119,570
                      
                      
                      
                      1,114,103Commitments
      and Contingencies (Note 9)
                      
                      
                      -
                      
                      
                      
                      -Stockholders
      Equity: (Notes 10, 11 and 12)Preferred
      stock, par value $0.001, 10 million shares authorized, no shares issued
      and outstanding at March 31, 2009 and 2008 (see Note
    10)
                      
                      
                      -
                      
                      
                      
                      -Common
      stock, par value $0.001, 500 million shares
      authorized,
                        71,636,019
      and 71,369,880 issued and outstanding at March 31, 2009 and 2008,
      respectively (see Note 10)
                      
                      
                      71,636
                      
                      
                      
                      71,370Additional
      paid in capital
                      
                      
                      21,950,246
                      
                      
                      
                      21,738,764Accumulated
      deficit
                      
                      
                      (16,126,289
                      )
                      
                      
                      (6,747,667
                      )Other
      comprehensive income (Note 2)
                      
                      
                      (21,176)
                      
                      
                      
                      1,510Total
      Stockholders’ Equity
                      
                      
                      5,874,417
                      
                      
                      
                      15,063,977Total
      Liabilities and Stockholders’ Equity
                      
                      $
                      6,993,987
                      
                      
                      $
                      16,178,080






See
accompanying notes to consolidated financial statements




F-3




INDEX
OIL AND GAS INC.


CONSOLIDATED
STATEMENT OF LOSSES


FOR
THE YEARS ENDED MARCH 31, 2009 AND 2008





2009
                
                
                2008Revenue:Oil
      & gas sales (Note 2 and Note 13)
                
                $
                2,828,751
                
                
                $
                1,705,593Operating
      Expenses:Operating
      costs
                
                
                704,183
                
                
                
                303,474Depletion,
      depreciation and amortization (Note 4)
                
                
                2,094,481
                
                
                
                1,096,229Impairment
      charges (Note 4)
                
                
                7,002,472
                
                
                
                -General
      and administrative expenses
                
                
                2,430,443
                
                
                
                2,457,929Total
      Operating Expenses
                
                
                12,231,579
                
                
                
                3,857,632Loss
      from Operations
                
                
                (9,402,828
                )
                
                
                (2,152,039
                )Other
      Income:Interest
      income
                
                
                24,207
                
                
                
                205,609Total
      Other Income
                
                
                24,207
                
                
                
                205,609Loss
      before Income Taxes
                
                
                (9,378,621
                )
                
                
                (1,946,430
                )Income
      Taxes Benefit (Note 8)
                
                
                -
                
                
                
                -Net
      Loss
                
                $
                (9,378,621
                )
                
                $
                (1,946,430
                )Loss
      per share (Note 12):Basic
      and assuming dilution
                
                $
                (0.13
                )
                
                $
                (0.03
                )Weighted
      average shares outstanding:Basic
      and assuming dilution
                
                
                71,477,513
                
                
                
                66,288,104







See
accompanying notes to consolidated financial statements







F-4




INDEX
OIL AND GAS INC.


CONSOLIDATED
STATEMENT OF STOCKHOLDERS’ EQUITY


FOR
THE TWO YEARS ENDED MARCH 31, 2009








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








See
accompanying notes to consolidated financial statements




F-5




INDEX
OIL AND GAS INC.


CONSOLIDATED
STATEMENT OF CASH FLOWS


FOR
THE YEARS ENDED MARCH 31, 2009 AND 2008





2009
                
                
                2008Cash
      Flows From Operating Activities:Net
      loss
                
                $
                (9,378,621
                )
                
                $
                (1,946,430
                )Adjustments
      to reconcile net loss to net cash (used in) operating
      activities:Non
      cash stock based compensation cost
                
                
                211,748
                
                
                
                302,911Depreciation,
      amortization and impairment
                
                
                9,096,953
                
                
                
                1,096,229Allowance
      for doubtful accounts
                
                
                49,320
                
                
                
                -Decrease
      (Increase) in receivables
                
                
                597,034
                
                
                
                (859,427
                )(Decrease)
      Increase in accounts payable and accrued expenses
                
                
                (84,134
                )
                
                
                211,968Net
      Cash Provided By (Used In) Operating Activities
                
                
                492,300
                
                
                
                (1,194,749
                )Cash
      Flows From Investing Activities:Payments
      for property and equipment
                
                
                (4,070
                )
                
                
                (18,094
                )Payments
      for oil and gas properties
                
                
                (2,704,388
                )
                
                
                (8,774,058
                )Net
      Cash (Used In) Investing Activities
                
                
                (2,708,458
                )
                
                
                (8,792,152
                )Cash
      Flows From Financing Activities:Proceeds
      from issuance of shares
                
                
                -
                
                
                
                2,779,923Payment
      for share issue costs
                
                
                -
                
                
                
                (382,171
                )Net
      Cash Provided by Financing Activities
                
                
                -
                
                
                
                2,397,752Effect of exchange rate
      changes on cash and cash equivalents
                
                
                14,674
                
                
                
                (14,674)Net
      (Decrease) in Cash And Cash Equivalents
                
                
                (2,201,485
                )
                
                
                (7,603,823)Cash
      and cash equivalents at beginning of year
                
                $
                2,537,302
                
                
                $
                10,141,125Cash
      and cash equivalents at the end of year
                
                $
                335,817
                
                
                $
                2,537,302Supplemental
      Disclosures of Cash Flow Information:Cash
      received during the year for interest
                
                $
                24,207
                
                
                $
                205,608Cash
      paid during the year for taxes
                
                $
                -
                
                
                $
                -Non-cash
      Financing and Investing Transactions:Non-cash
      stock based compensation cost
                
                $
                211,747
                
                
                $
                302,911








See
accompanying notes to consolidated financial statements




F-6




INDEX
OIL AND GAS INC.


NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


MARCH
31, 2009 AND 2008





NOTE
1 - ORGANIZATION AND OPERATIONS OF THE COMPANY





Organization





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





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





Overview





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





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





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





Operations





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





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





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





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





F-7


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


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


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


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





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





Alligator
Bayou prospect:


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





Garwood
field:


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





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




NOTE
2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES





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




Principles of
Consolidation





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





Use of
Estimates





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





Correction of
Errors





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





F-8


Cash and Cash Equivalents,
and Concentrations of Credit Risk





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





Accounting for Bad Debts and
Allowances





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





Other Current
Assets





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





Oil and Gas
Properties





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





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





Other Property, Plant and
Equipment





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





F-9


Comprehensive
Income





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





Net Earnings (Losses) Per
Common Share





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





Revenue
Recognition





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





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





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





Derivative and
Hedging





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





Foreign Currency
Translation





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





Income
Taxes





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





F-10


Segment
Information





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





Stock Based
Compensation





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





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





Asset Retirement
Obligations





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





Long-Lived
Assets





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





F-11





Conditional Asset Retirement
Obligations




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





Employers’ Defined Benefit
Pension and Other Postretirement Plans





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





Certain
Hybrid 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 from the adoption of this new standard on its
consolidated financial position, results of operations or cash flows as it
currently does not have any hybrid instruments outstanding at March 31,
2009.





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





This
Statement:





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 accountingb.
                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:





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.




F-12




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




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





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





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




F-13


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




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




Recent Accounting
Developments and New Accounting Pronouncements Not Yet
Adopted


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


F-14




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




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





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





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





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





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







F-15





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





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





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





NOTE
3 - TRADE RECEIVABLES




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





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




Oil and Gas
Properties




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





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





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





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




Impairment
Charges




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





F-16


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





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




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




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





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





Acquisitions and
Dispositions





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




Other Property and
Equipment





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





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





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





Capitalized
Interest





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





F-17


NOTE
5 - COMPREHESIVE LOSS





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





Years
      Ended March 31,2009
                
                
                2009
                
                
                2008
                
                
                2008Accumulated
      other comprehensive
                  income beginning of period
                
                
                $
                1,510
                
                
                
                
                
                $
                15,399Net
      (loss)
                
                $
                (9,378,621
                )
                
                
                
                
                
                $
                (1,946,430
                )Foreign
      currency translation (loss)
                
                
                (22,687
                )
                
                
                
                
                
                
                (13,889
                )Total
      other comprehensive (loss)
                
                
                (22,687
                )
                
                
                (22,687
                )
                
                
                (13,889
                )
                
                
                (13,889
                )Comprehensive
      (loss)
                
                $
                (9,401,308
                )
                
                
                
                
                
                $
                (1,960,319
                )Accumulated
      other comprehensive income (loss)
                  end
      of period
                
                
                $
                (21,177
                )
                
                
                
                
                
                $
                1,510





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





NOTE
6 - NOTES PAYABLE





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





F-18





NOTE
7 - ASSET RETIREMENT OBLIGATION





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





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





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







NOTE 8 - INCOME
TAXES





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





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





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




March
      31,2009
                  
                  
                  2008CurrentUK
                  
                  $
                  -
                  
                  
                  $
                  -US
                  
                  
                  -
                  
                  
                  
                  -State
                  
                  
                  -
                  
                  
                  
                  -Total
      current tax expense (benefit)
                  
                  
                  -
                  
                  
                  
                  -DeferredUK
                  
                  
                  (302,465
                  )
                  
                  
                  (289,526
                  )US
                  
                  
                  (7,026,879
                  )
                  
                  
                  (4,143,281
                  )State
                  
                  
                  (1,054,032
                  )
                  
                  
                  (621,492
                  )Total
      deferred tax expense (benefit)
                  
                  
                  (8,383,375
                  )
                  
                  
                  (5,054,299
                  )Less
      valuation allowance
                  
                  
                  8,383,375
                  
                  
                  
                  5,054,299Total
      deferred tax expense (benefit)
                  
                  $
                  -
                  
                  
                  $
                  -Total
      tax provision-continuing operations
                  
                  $
                  -
                  
                  
                  $
                  -








F-19


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




Components
of deferred tax amounts are as follows:





Deferred
      Tax Components
                
                March
      31,2009
                
                
                2008Deferred
      tax assetsRestricted
      stock compensation accrual
                
                $
                -
                
                
                $
                -Share
      issue basis difference
                
                
                -
                
                
                
                -Other
                
                
                -
                
                
                
                -Oil
      & Gas basis differences
                
                
                3,722,521
                
                
                
                3,529,359Depreciation
                
                
                1,169,112
                
                
                
                512,673Net
      operating loss carryforward
                
                
                5,518,200
                
                
                
                2,284,516Total
      gross deferred tax assets
                
                
                10,409,833
                
                
                
                6,326,548Deferred
      tax liabilitiesAmortization
      of share issue costs
                
                
                -
                
                
                
                -Other
                
                
                3,969
                
                
                
                3,139Foreign
      currency translation
                
                
                -
                
                
                
                -Oil
      & Gas basis differences
                
                
                -
                
                
                
                -Depreciation
                
                
                1,241,024
                
                
                
                521,363Stock
      Compensation
                
                
                781,464
                
                
                
                747,747Total
      gross deferred tax liabilities
                
                
                2,026,457
                
                
                
                1,272,249Less
      valuation allowance
                
                
                (8,383,375
                )
                
                
                (5,054,299
                )Net
      deferred tax assets
                
                $
                -
                
                
                $
                -




NOTE
9 - COMMITMENTS AND CONTINGENCIES





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




F-20




Lease
Commitments





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





Consulting
Agreements





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





Stockholder
Matters





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





Litigation





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








NOTE
10 - CAPITAL STOCK





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





Balance
      at March 31, 2008
              
              
              71,369,880Stock
      awards for services
              
              
              266,139Balance
      at March 31, 2009
              
              
              71,636,019





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





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


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


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





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





Balance
      at March 31, 2007
              
              
              65,737,036Issuance
      of stock related to private placement
              
              
              5,541,182Issuance
      of restricted stock related to stock bonus award
              
              
              25,000Exercise
      of warrants
              
              
              66,662Balance
      at March 31, 2008
              
              
              71,369,880





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





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








F-21


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





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





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





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








NOTE
11 - OPTIONS AND WARRANTS AND STOCK-BASED COMPENSATION





Warrants





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





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




Warrants
      Outstanding
                
                
                Warrants
      ExercisableExercise
      Prices
                
                
                Number
      Outstanding
                
                
                Weighted
      Average
                  Remaining
      Contractual Life (Years)
                
                
                Weighted
      Average
                  Exercise
      Price
                
                
                Number
      Exercisable
                
                
                Weighted
      Average Exercise Price
                  Exercise
      Price$
                0.07
                
                
                
                138,655
                
                
                
                1.50
                
                
                $
                0.07
                
                
                
                138,655
                
                
                $
                0.07$
                0.14
                
                
                
                762,766
                
                
                
                1.50
                
                
                $
                0.14
                
                
                
                762,766
                
                
                $
                0.14901,421
                
                
                
                2.50
                
                
                $
                0.13
                
                
                
                901,421
                
                
                $
                0.13





F-22


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





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





Stock
Options





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





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




Options
      Outstanding
                
                
                Options
      ExercisableExercise
      Price
                
                
                Number
                  Outstanding
                
                
                Weighted
      Average Remaining Contractual Life (Years)
                
                
                Weighted
      Average Exercise Price
                
                
                Number
                  Exercisable
                
                
                Weighted
      Average Exercise Price$
                0.35
                
                
                
                4,577,526
                
                
                
                1.81
                
                
                $
                0.35
                
                
                
                4,577,526
                
                
                $
                0.35$
                0.83
                
                
                
                125,000
                
                
                
                3.47
                
                
                $
                0.83
                
                
                
                93,750
                
                
                $
                0.83$
                0.60
                
                
                
                100,000
                
                
                
                3.76
                
                
                $
                0.60
                
                
                
                50,000
                
                
                $
                0.60$
                0.51
                
                
                
                150,000
                
                
                
                3.82
                
                
                $
                0.51
                
                
                
                75,000
                
                
                $
                0.514,952,526
                
                
                
                1.95
                
                
                $
                0.37
                
                
                
                4,796,276
                
                
                $
                0.37




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





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





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





Prior to
the reverse merger with Index Inc. in 2006, Index Ltd. adopted a Stock Option
Plan to grant options to various officers, directors and others. Following the
completion of the acquisition the Board of Directors of Index Inc. agreed to and
ratified the adoption of the plan as the 2006 Incentive Stock Option Plan,
providing for the issuance of up to 5,225,000 shares of Common Stock of Index
Inc. to officers, directors, employees and consultants of Index Inc. and/or its
subsidiaries. Pursuant to the 2006 Incentive Stock Option Plan stock options to
purchase 4,577,526 shares of Common Stock at $0.35 per share to newly appointed
directors and officers of Index Inc. and that had held options to purchase
ordinary shares of Index Ltd. prior to the completion of the acquisition. All
these stock options are currently 100% vested. Other principal terms are: the
share options are non-transferable other than to a legal or beneficial holder of
the options upon the option holder’s death. The rights to vested but unexercised
options cease to be effective: (1) 18 months after death of the stock options
holder; (2) 6 months after Change of Control of Index Inc.; (3) 12 months after
loss 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 $211,747 and $302,911 for the years ended
March 31, 2009 and 2008, respectively. Total stock based compensation expense on
unvested stock options remaining at March 31, 2009 is $9,611.





F-23


NOTE 12 - EARNINGS PER
SHARE




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





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





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




NOTE
13 - MAJOR CUSTOMERS





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





NOTE
14 - RELATED PARTY TRANSACTIONS





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








F-24


INDEX
OIL AND GAS INC.


SUPPLEMENTAL
INFORMATION (UNAUDITED)


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





Oil
and Natural gas Producing Activities





The
following disclosures for the Company are made in accordance with Statement of
Financial Accounting Standards (“SFAS”) No. 69, “Disclosures About Oil and
Natural gas Producing Activities (an amendment of FASB Statements 19, 25, 33 and
39)” (“SFAS No. 69”). Users of this information should be aware that the
process of estimating quantities of proved, proved developed and proved
undeveloped crude oil and natural gas reserves is very complex, requiring
significant subjective decisions in the evaluation of all available geological,
engineering and economic data for each reservoir. The data for a given reservoir
may also change substantially over time as a result of numerous factors
including, but not limited to, additional development activity, evolving
production history and continual reassessment of the viability of production
under varying economic conditions. Consequently, material revisions to existing
reserve estimates occur from time to time. Although every reasonable effort is
made to ensure that reserve estimates reported represent the most accurate
assessments possible, the significance of the subjective decisions required and
variances in available data for various reservoirs make these estimates
generally less precise than other estimates presented in connection with
financial statement disclosures.





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





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





Proved
undeveloped reserves are reserves that are expected to be recovered from new
wells on undrilled acreage or from existing wells where a relatively major
expenditure is required for recompletion. Reserves on undrilled acreage are
limited to those drilling units offsetting productive units that are reasonably
certain of production when drilled. Proved reserves for other undrilled units
can be claimed only where it can be demonstrated with certainty that there is
continuity of production from the existing productive formation. Estimates for
proved undeveloped reserves are not attributed to any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual tests
in the area and in the same reservoir.





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





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




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




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




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




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




F-25





Capitalized
Costs Relating to Oil and Gas Producing Activities





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




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








F-26


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





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










Continuing
                  Operations
                
                
                Discontinued
                  OperationsYear
      Ended March 31, 2007:Acquisition
      costs of propertiesProved
                
                $
                -
                
                
                $
                -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 propertiesProved
                
                $
                985,605
                
                
                $
                -Unproved
                
                
                292,382Subtotal
                
                
                1,277,987Exploration
      and development costs
                
                
                7,496,071Total
                
                $
                8,774,058
                
                
                $
                -Year
      Ended March 31, 2009:Acquisition
      costs of propertiesProved
                
                $
                72,078
                
                
                $
                -Unproved
                
                
                (32,316
                )Subtotal
                
                
                39,762Exploration
      and development costs
                
                
                2,664,626Total
                
                $
                2,704,388
                
                
                $
                -




Results
of Operations for Oil and Natural Gas Producing Activities




Year
      Ended
                  March 31,
                  2009
                
                
                Year
      Ended
                  March 31,
                  2008
                
                
                Year
      Ended
                  March 31,
                  2007Oil
      and natural gas production revenuesThird-party
                
                $
                2,828,751
                
                
                $
                1,705,593
                
                
                $
                457,046Affiliate
                
                
                -
                
                
                
                -
                
                
                
                -Total
      revenues
                
                
                2,828,751
                
                
                
                1,705,593
                
                
                
                457,046Exploration
      expenses, including dry hole
                
                
                -
                
                
                
                -
                
                
                
                -Production
      costs
                
                
                (704,183
                )
                
                
                (303,474
                )
                
                
                (114,735
                )Depreciation,
      depletion, amortization and impairment
                
                
                (9,096,953
                )
                
                
                (1,091,673
                )
                
                
                (188,351
                )Income
      (loss) before income taxes
                
                
                (6,972,385
                )
                
                
                310,446
                
                
                
                153,960Income
      tax provision (benefit)
                
                
                -
                
                
                
                -
                
                
                
                -Results
      of continuing operations
                
                $
                (6,972,385
                )
                
                $
                310,446
                
                
                $
                153,960Results
      of discontinued operations
                
                $
                -
                
                
                $
                -
                
                
                $
                -





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







F-27


Net
Proved and Proved Developed Reserve Summary





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





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





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


Continuing
                  Operations
                
                
                Discontinued
                  OperationsNatural
      gas (Bcf)(1):Net
      proved reserves at March 31, 2006
                
                
                0.144
                
                
                
                -Revisions
      of previous estimates
                
                
                0.157
                
                
                
                -Purchases
      in place
                
                
                0.008
                
                
                
                -Extensions,
      discoveries and other additions
                
                
                0.240
                
                
                
                -Sales
      in place
                
                
                -
                
                
                
                -Production
                
                
                (0.008)
                
                
                
                -Net
      proved reserves at March 31, 2007
                
                
                0.541
                
                
                
                -Revisions
      of previous estimates
                
                
                (0.245)
                
                
                
                -Purchases
      in place
                
                
                0.084
                
                
                
                -Extensions,
      discoveries and other additions
                
                
                0.836
                
                
                
                -Sales
      in place
                
                
                -
                
                
                
                -Production
                
                
                (0.127)
                
                
                
                -Net
      proved reserves at March 31, 2008
                
                
                1.090
                
                
                
                -Revisions
      of previous estimates
                
                
                (0.628)
                
                
                
                -Purchases
      in place
                
                
                -
                
                
                
                -Extensions,
      discoveries and other additions
                
                
                0.176
                
                
                
                -Sales
      in place
                
                
                -
                
                
                
                -Production
                
                
                (0.237
                )
                
                
                -Net
      proved reserves at March 31, 2009
                
                
                0.400
                
                
                
                -Natural
      gas liquids and crude oil (MBbls)(2)(3):Net
      proved reserves at March 31, 2006
                
                
                35.401
                
                
                
                -Revisions
      of previous estimates
                
                
                (5.349)
                
                
                
                -Purchases
      in place
                
                
                0.066
                
                
                
                -Extensions,
      discoveries and other additions
                
                
                0.875
                
                
                
                -Sales
      in place
                
                
                -
                
                
                
                -Production
                
                
                (6.660
                )
                
                
                -Net
      proved reserves at March 31, 2007
                
                
                24.333
                
                
                
                -Revisions
      of previous estimates
                
                
                (6.591)
                
                
                
                -Purchases
      in place
                
                
                0.005
                
                
                
                -Extensions,
      discoveries and other additions
                
                
                27.497
                
                
                
                -Sales
      in place
                
                
                -
                
                
                
                -Production
                
                
                (7.477
                )
                
                
                -Net
      proved reserves at March 31, 2008
                
                
                37.767
                
                
                
                -Revisions
      of previous estimates
                
                
                (11.490
                )
                
                
                -Purchases
      in place
                
                
                -
                
                
                
                -Extensions,
      discoveries and other additions
                
                
                2.906
                
                
                
                -Sales
      in place
                
                
                -
                
                
                
                -Production
                
                
                (8.217
                )
                
                
                -Net
      proved reserves at March 31, 2009
                
                
                20.966
                
                
                
                -






F-28


(MBO)(2)
      equivalents(4):Net
      proved reserves at March 31, 2006
              
              
              59.471
              
              
              
              -Revisions
      of previous estimates
              
              
              20.748
              
              
              
              -Purchases
      in place
              
              
              1.478
              
              
              
              -Extensions,
      discoveries and other additions
              
              
              40.956
              
              
              
              -Sales
      in place
              
              
              -
              
              
              
              -Production
              
              
              (8.075)
              
              
              
              -Net
      proved reserves at March 31, 2007
              
              
              114.578
              
              
              
              -Revisions
      of previous estimates
              
              
              (47.393)
              
              
              
              -Purchases
      in place
              
              
              14.050
              
              
              
              -Extensions,
      discoveries and other additions
              
              
              166.859
              
              
              
              -Sales
      in place
              
              
              -
              
              
              
              -Production
              
              
              (28.625)
              
              
              
              -Net
      proved reserves at March 31, 2008
              
              
              219.469
              
              
              
              -Revisions
      of previous estimates
              
              
              (116.194)
              
              
              
              -Purchases
      in place
              
              
              -
              
              
              
              -Extensions,
      discoveries and other additions
              
              
              32.207
              
              
              
              -Sales
      in place
              
              
              -
              
              
              
              -Production
              
              
              (47.781)
              
              
              
              -Net
      proved reserves at March 31, 2009
              
              
              87.702
              
              
              
              -Net
      proved developed reserves:Natural
      gas (Bcf)(1)March
      31, 2007
              
              
              0.541
              
              
              
              -March
      31, 2008
              
              
              1.090
              
              
              
              -March
      31, 2009
              
              
              0.305
              
              
              
              -Natural
      gas liquids and crude oil (MBbls)(2)(3)March
      31, 2007
              
              
              22.953
              
              
              
              -March
      31, 2008
              
              
              36.677
              
              
              
              -March
      31, 2009
              
              
              20.015
              
              
              
              -MBO(2)
      equivalents(4)March
      31, 2007
              
              
              113.198
              
              
              
              -March
      31, 2008
              
              
              218.379
              
              
              
              -March
      31, 2009
              
              
              70.878
              
              
              
              -






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




(2)
            Thousand
      barrels.




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




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







F-29


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





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





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





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





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





Continuing
                  Operations
                
                
                Discontinued
      Operations(in
      $’000)March
      31, 2007:Future
      cash inflows
                
                $
                5,049.821
                
                
                $
                -Future
      production costs
                
                
                (1,055.600
                )
                
                
                -Future
      development costs
                
                
                (53.403
                )
                
                
                -Future
      income taxes
                
                
                -
                
                
                
                -Future
      net cash flows
                
                
                3,940.818
                
                
                
                -Discount
      to present value at 10% annual rate
                
                
                (841.922
                )
                
                
                -Standardized
      measure of discounted future net cash flows relating to proved natural
      gas, natural gas liquids and crude oil reserves
                
                $
                3,098.896
                
                
                $
                -March 31,
      2008:Future
      cash inflows
                
                $
                14,799.617
                
                
                $
                -Future
      production costs
                
                
                (2,733.919
                )
                
                
                -Future
      development costs
                
                
                (86.499
                )
                
                
                -Future
      income taxes
                
                
                -
                
                
                
                -Future
      net cash flows
                
                
                11,979.199
                
                
                
                -Discount
      to present value at 10% annual rate
                
                
                (2,007.956
                )
                
                
                -Standardized
      measure of discounted future net cash flows relating to proved natural
      gas, natural gas liquids and crude oil reserves
                
                $
                9,971.243
                
                
                $
                -






F-30


Continuing
                
                
                DiscontinuedOperations
                
                
                OperationsMarch 31,
      2009:Future
      cash inflows
                
                $
                2,530.215
                
                
                $
                -Future
      production costs
                
                
                (599.346
                )
                
                
                -Future
      development costs
                
                
                (375.000
                )
                
                
                -Future
      income taxes
                
                
                -
                
                
                
                -Future
      net cash flows
                
                
                1,555.869
                
                
                
                -Discount
      to present value at 10% annual rate
                
                
                (313.933
                )
                
                
                -Standardized
      measure of discounted future net cash flows relating to proved natural
      gas, natural gas liquids and crude oil reserves
                
                $
                1,241.936
                
                
                $
                -





Changes
in Standardized Measure of Discounted Future Net Cash Flows





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





Continuing
                
                
                DiscontinuedOperations
                
                
                Operations(in
      $’000)Balance,
      April 1, 2006
                
                $
                1,347.233
                
                
                $
                -Sales
      and transfers of natural gas, natural gas liquids and crude oil produced,
      net of production costs
                
                
                (342.311
                )
                
                
                -Net
      changes in prices and production costs
                
                
                (46.758)
                
                
                
                -Extensions,
      discoveries, additions and improved recovery, net of related
      costs
                
                
                1,180.549
                
                
                
                -Development
      costs incurred
                
                
                1,320.745
                
                
                
                -Revisions
      of previous quantity estimates and development costs
                
                
                (820.626
                )
                
                
                -Accretion
      of discount
                
                
                134.723
                
                
                
                -Net
      change in income taxes
                
                
                -
                
                
                
                -Purchases
      of reserves in place
                
                
                486.467
                
                
                
                -Sales
      of reserves in place
                
                
                -
                
                
                
                -Changes
      in timing and other
                
                
                (161.126
                )
                
                
                -Balance,
      March 31, 2007
                
                $
                3,098.896
                
                
                $
                -Sales
      and transfers of natural gas, natural gas liquids and crude oil produced,
      net of production costs
                
                $
                (1,402.119
                )
                
                $
                -Net
      changes in prices and production costs
                
                
                1,138.995
                
                
                
                -Extensions,
      discoveries, additions and improved recovery, net of related
      costs
                
                
                8,082.075
                
                
                
                -Development
      costs incurred
                
                
                -
                
                
                
                -Revisions
      of previous quantity estimates and development costs
                
                
                (1,910.908
                )
                
                
                -Accretion
      of discount
                
                
                309.890
                
                
                
                -Net
      change in income taxes
                
                
                -
                
                
                
                -Purchases
      of reserves in place
                
                
                592.974
                
                
                
                -Sales
      of reserves in place
                
                
                -
                
                
                
                -Changes
      in timing and other
                
                
                61.440
                
                
                
                -Balance,
      March 31, 2008
                
                $
                9,971.243
                
                
                $
                -Sales
      and transfers of natural gas, natural gas liquids and crude oil produced,
      net of production costs
                
                $
                (2,124.568
                )
                
                $
                -Net
      changes in prices and production costs
                
                
                (5,377.604
                )
                
                
                -Extensions,
      discoveries, additions and improved recovery, net of related
      costs
                
                
                194.356
                
                
                
                -Development
      costs incurred
                
                
                30.881
                
                
                
                -Revisions
      of previous quantity estimates and development costs
                
                
                (2,165.565
                )
                
                
                -Accretion
      of discount
                
                
                997.124
                
                
                
                -Net
      change in income taxes
                
                
                -
                
                
                
                -Purchases
      of reserves in place
                
                
                -
                
                
                
                -Sales
      of reserves in place
                
                
                -
                
                
                
                -Changes
      in timing and other
                
                
                (283.931
                )
                
                
                -Balance,
      March 31, 2009
                
                $
                1,241.936
                
                
                $
                -






F-31


Exhibit
Index







Exhibit
                Number
              
              Description3.1
              
              Restated
      Articles of Incorporation of Index Oil and Gas Inc., Inc.
      (1)3.2
              
              Bylaws
      of Index Oil and Gas Inc. (2)10.1
              
              Acquisition
      Agreement between Index Oil and Gas Inc., certain stockholders of Index
      Oil & Gas Ltd, and Briner Group Inc. dated January 20, 2006.
      (3)10.2
              
              Form
      of Share and Warrant Exchange Agreement entered into by and between Index
      Oil and Gas Inc., Inc. and certain Index Oil & Gas Ltd stockholders.
      (3)10.3+
              
              Employment
      Agreement entered into by and between Index Oil & Gas Ltd and Lyndon
      West, dated January 20, 2006. (3)10.4+
              
              Employment
      Agreement entered into by and between Index Oil & Gas Ltd and Andy
      Boetius, dated January 20, 2006. (3)10.5+
              
              Employment
      Agreement entered into by and between Index Oil & Gas Ltd and Daniel
      Murphy, dated January 20, 2006. (3)10.6+
              
              Letter
      Agreement entered into by and between Index Oil & Gas Ltd and David
      Jenkins, dated January 20, 2006. (3)10.7+
              
              Letter
      Agreement entered into by and between Index Oil & Gas Ltd and Michael
      Scrutton, dated January 20, 2006. (3)10.8+
              
              Employment
      Agreement entered into by and between Index Oil and Gas Inc. and John G.
      Williams, dated August 29, 2006. (4)10.9
              
              Form
      of Subscription Agreement dated as of January 20, 2006.
      (3)10.10
              
              Form
      of Subscription Agreement dated as of August 29 and October 4, 2006.
      (5)10.11
              
              Form
      of Registration Rights Agreement dated as of August 29, 2006.
      (5)10.12+
              
              Index
      Oil and Gas Inc. 2006 Incentive Stock Option Plan.
    (6)10.13
              
              Securities
      Purchase Agreement dated as of November 5, 2007.
  (7)10.14
              
              Form
      of Warrant to Purchase Common Stock. (7)10.15+
              
              Agreement
      for Exploration, Production and Strategic Services dated February 1, 2008
      between the Company and ConRon Consulting Inc., as amended by Addendum #1
      dated June 1, 2008 and Addendum #2 dated July 1, 2008.
  (8)10.16+
              
              Amended
      and Restated Agreement for Exploration, Production and Strategic Services
      between Index Oil and Gas Inc. and ConRon Consulting Inc. dated December
      8, 2008. (9)10.17+
              
              Amended
      Employment Agreement of Daniel Murphy, dated March 4, 2009.
      (10)10.18+
              
              Amended
      Employment Agreement of Lyndon West, dated March 4, 2009.
    (10)10.19+
              
              Amended
      Employment Agreement of Andrew Boetius, dated March 4, 2009.
      (10)14.1
              
              Code
      of Ethics and Business Conduct for officers, directors and employees of
      Index Oil and Gas Inc. adopted by the Company’s Board of Directors on
      March 31, 2006. (11)21.1
              
              List
      of subsidiaries of the Company. *23.1
              
              Consent
      of RBSM LLP. *23.2
              
              Consent
      of Ancell Energy Consulting, Inc. *31.1
              
              Certification
      by Chief Executive Officer required by Rule 13a-14(a) or Rule 15d-14(a) of
      the Exchange Act. *31.2
              
              Certification
      by Chief Financial Officer required by Rule 13a-14(a) or Rule 15d-14(a) of
      the Exchange Act. *32.1
              
              Certification
      by Chief Executive Officer required by Rule 13a-14(b) or Rule 15d-14(b) of
      the Exchange Act and Section 1350 of Chapter 63 of Title 18 of the United
      States Code. *32.2
              
              Certification
      by Chief Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) of
      the Exchange Act and Section 1350 of Chapter 63 of Title 18 of the United
      States Code. *






*
      Filed Herewith+
      Compensatory plan or arrangement(1)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on September 5, 2008.(2)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on October 9, 2008.(3)
      Incorporated by reference to the Company’s Amended Current Report filed on
      Form 8-K/A with the SEC on March 15, 2006.(4)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on September 8, 2006.(5)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on September 11, 2006.(6)
      Incorporated by reference to the Company’s Registration Statement filed on
      Form S-8 with the SEC on October 3, 2007.(7)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on February 29, 2008.(8)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on July 8, 2008.(9)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on December 12, 2008.(10)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on March 6, 2009.(11)
      Incorporated by reference to the Company’s Annual Report filed on Form
      10-KSB with the SEC on April 10,
2006.