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, 2008OR£
            TRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
      OF 1934





Commission
File No. 000-51430


_______________





INDEX
OIL AND GAS INC.


(Exact
Name of Registrant as Specified in Its Charter)





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





10000
Memorial Drive, Suite 440


Houston,
Texas 77024


(Address
of principal executive offices, including zip code)


(713) 683-0800


(Registrant’s
telephone number, including area code)





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


None


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


Common
Stock, $0.001








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





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





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





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





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




Large
accelerated filer £                                                                 Accelerated
Filer £


Non-accelerated
Filer £                                                                 
Smaller reporting company  R


(Do not
check if a Small reporting company)





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





The
aggregate market value of the voting stock held by non-affiliates of the
registrant based on the closing price of the Registrant’s common stock as
reported on the OTC Bulletin Board on September 28, 2007 was
$46,365,872.





As of
June 15, 2008, there were outstanding 71,455,594 shares of common
stock.





Documents
Incorporated by Reference





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











TABLE
OF CONTENTS







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





Cautionary
Note Regarding Forward Looking Statements





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





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





•
            our
      ability to attract and retain management;•
            our
      growth strategies;•
            anticipated
      trends in our business;•
            our
      future results of operations;•
            our
      ability to make or integrate acquisitions;•
            our
      liquidity and ability to finance our exploration, acquisition and
      development activities;•
            our
      ability to successfully and economically explore for and develop oil and
      gas resources;•
            market
      conditions in the oil and natural gas industry;•
            the
      timing, cost and procedure for acquisitions;•
            the
      impact of government regulation;•
            estimates
      regarding future net revenues from oil and natural gas reserves and the
      present value thereof;•
            planned
      capital expenditures (including the amount and nature
  thereof);•
            increases
      in oil and natural gas production;•
            the
      number of wells we anticipate being drilled in the future;•
            estimates,
      plans and projections relating to acquired properties;•
            the
      number of potential drilling locations on lands in which we have an
      interest;•
            our
      financial position, business strategy and other plans and objectives for
      future operations;•
            the
      possibility that our acquisitions may involve unexpected
  costs;•
            the
      volatility in commodity prices for oil and natural gas;•
            the
      accuracy of internally estimated proved reserves;•
            the
      presence or recoverability of estimated oil and natural gas
      reserves;•
            the
      ability to replace oil and natural gas reserves;•
            the
      availability and costs of drilling rigs and other oilfield services use by
      the operators of properties in which we have an
  interest;•
            environmental
      risks;•
            exploration
      and development risks;•
            competition;•
            the
      ability of our management team to execute its plans to meet its goals;
      and


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





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


PART
I





Item
1.  Business





Organization





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





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





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





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





Overview





For the
fiscal year ended March 31, 2008, Index had year-on-year increases in reserves,
production and revenue.  We have sustained a history of drilling
success rates, while pursuing higher-impact prospects, all while remaining debt
free (excluding ordinary course trade debt).  The Company, as
described more fully in “Recent Financing”, raised $2.77 million in gross
proceeds in a private equity fund raise in a very challenging fiscal
environment.  The Company also recruited highly experienced senior
staff members in exploration and production, land and operations and in
accounting to the Index team.





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





Strengths
and Strategies





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





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




1




Our
strategy has been to establish a presence in the onshore gulf coast region
through participation in various projects with the goal of having those
operations reach a level of production sufficient to support the business at its
current levels while maintaining a debt-free basis (except for ordinary course
trade debt).  As of the end of our fiscal year ending March 31, 2008,
we believe that we have achieved this level of production with our existing
interests in producing properties.





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





Our
Operating Areas




We own
producing and non-producing oil and natural gas properties in Kansas, Louisiana,
and Texas.  See Item 2. Property for a description of our proved
reserves in each state. In each area we are pursuing geological objectives and
projects that are consistent with our technical expertise to provide the highest
potential economic returns. For the fiscal year ended March 31, 2008, we
participated in 14.0 gross and 2.2 net wells, for which principal drilling and,
where applicable, completion operations were concluded in the
year.  Of these wells, 11 gross and 2.1 net wells became productive
and with a gross completion rate of 79%.  The following is a summary
of our major operating areas in which we discuss their various characteristics,
including our working interests (“WI”) and our net revenue interests (“NRI”) in
various properties and wells.





Kansas





Properties
Summary.  At March 31, 2008, we owned approximately 271 net
acres in Kansas.  Our production is concentrated in Stafford and
Barton Counties.  Total net production for the fiscal year ended March
31, 2008, for all Kansas wells was approximately 2,500 Bbls or 15.0 MMcfe
(thousand Mcf of natural gas equivalent).





Operations
Summary.  Our Kansas properties represent a very low risk, low
cost, low working interest, and limited upside project and which is not expected
to be a significant contributor to future growth.  Our working
interest in the Kansas wells is either 5% for wells drilled in Stafford County
or 3.25% for wells drilled in Barton County, and the net revenue interest is
either approximately 4.155% or 2.64%, respectively. We have committed to a
current program of 14 wells for low-risk prospects in Stafford and Barton
Counties. To-date, in this program, we have participated in eight wells, of
which in June 2008, four are now on production (including one Stafford County
well which was drilled under farm-in arrangements and in which we have a 2.5%
WI), one is being completed and three have been plugged and abandoned. The two
most recent wells, with a 3.25% WI and a 2.64% NRI, are the Salem #1-8 well,
which was completed in April 2008 and the Miller-McReynolds Unit 1-17 which was
spudded in April 2008, completed and began production in June
2008.  Further activity is expected at approximately two wells per
month dependent on commodity pricing and evaluation of the program to
date.





Louisiana





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





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




2





Texas





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





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





*   Cason
1, Cason 2 and Cason 3




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





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





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




3





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





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





In April
2007, we announced that we had signed a Participation Agreement to explore for
gas in the West Wharton prospect. This project could consist of up to four
exploration wells within the AMI in Wharton County, Texas. We have a 10.9% WI in
the project that will reduce to 9.38% WI after prospect payout, defined as that
point in time when the gross proceeds of the sale of oil and/or gas produced and
sold from all wells drilled in the prospect, and/or  sale of any wells
in the prospect, after deducting all lease burdens, including all overriding
royalty interests, and taxes, (including gross production taxes, windfalls
profit taxes, if any, and ad valorum taxes) equals the actual costs of drilling
testing, completing, equipping, and operating the test well, and/or any
subsequent wells, in addition to the leasehold, overhead, and geological costs
of the prospect.  The first well, Outlar 1 (approximate NRI 8.2%
before payout and 7.0% after payout), spudded in August 2007 and sales began in
December 2007.  We view the West Wharton project as potentially
significant for us as it has existing leases on up to five well-defined
prospects. The second well in this prospect, Stewart 1 was spudded in May 2008.
We have also participated in additional leasing opportunities with the
operator.





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





Recent
Financing





On
February 26, 2008, we closed on a private placement offering in which we sold an
aggregate 5,541,182 units of our securities at a price of $0.50 per Unit, each
Unit consisting of 1 share of common stock, $0.001 par value, and one loyalty
warrant to purchase 0.50 share of Common Stock, at a purchase price of $0.50,
per share of the Company (the “Loyalty Warrant”), for aggregate gross proceeds
of approximately $2.77 million. The Loyalty Warrant shall not be exercisable
until February 26, 2010, and only those investors who meet the requirements set
forth in the Loyalty Warrant shall be able to exercise the Loyalty Warrant at
that time or thereafter.  The net proceeds of the offering were used
as working capital and for general corporate purposes.





Our
Industry





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





Competitive
Conditions in the Business





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




4





Customers





Through
contracts negotiated by our operators, we sell our crude oil and natural gas
production to independent purchasers (collectively, “purchaser”), as allowed by
our joint operating agreements.  Additionally, we may sell directly to
our operator crude oil and natural gas under our joint operating agreement. We
have limited input into the terms of the contracts for the marketing or sale of
our oil and natural gas production to purchasers.  Title to the
produced quantities transfers to the purchaser at the time the purchaser
collects or receives the quantities.  Prices for such production are
defined in sales contracts and are readily determinable based on certain
publicly available indices.  The purchasers of such production have
historically made payment for crude oil and natural gas purchases within
forty-five days of the end of each production month.  We periodically
review the difference between the dates of production and the dates we collect
payment for such production to ensure that receivables from those purchasers or
our operators are collectible. All transportation costs are accounted for as
costs that are offset against oil and natural gas sales revenue. In the fiscal
year ended March 31, 2008, approximately 28%, 25% and 17% of revenues from our
share of oil production were sold to three independent crude oil and gas
purchasers, together with low levels of gas sales, and for the 2007 fiscal year
ended March 31, 2007, approximately 53% and 47% of oil sales were sold to two
independent crude oil purchasers. We do not believe the loss of any one of our
purchasers would materially affect our ability to sell the oil and gas it
produces. We believe that other purchasers are available in our areas of
operations.





Seasonality
of Business





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





Operational
Risks





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





Governmental
Regulation





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




5





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





Transportation
and Sale of Natural Gas





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





Regulation
of Production





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





Environmental
Regulations





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





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




6





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





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





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





Federal,
State or Native American Leases





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





Waste
Handling





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





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





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





Compliance – General





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





Employees





As of
March 31, 2008, we had full time employment agreements with the following
officers: Mr. Lyndon West, CEO, Mr. Andrew Boetius, CFO, and Mr. Dan Murphy,
Chairman and secretary (who is to change to three days per week from July 1,
2008) and  Mr. Gregory Mendez, Controller. In addition, we had
consulting agreements with Dr. Ronald Bain, Senior Vice President Exploration
and Production, and Mr. Samuel Culpepper, Vice President Land and Operations. In
addition, we had a letter agreement with Mr. David Jenkins, our non-executive
director.  We also had one employee on our administrative
staff.  As at March 31, 2008 we had 5 total and 5 full time employees,
excluding the above consulting positions.




7





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





Access
to Company Reports





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





Corporate
Governance Matters





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





Item
1A.  Risk Factors





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





Risks
Related To Index’s Financial Results





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





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





•           Successfully
execute our business strategy;





•           Continue
to develop our oil exploration and production assets;





•           Respond
to competitive developments; and





•           Attract,
integrate, retain and motivate qualified personnel.





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




8





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





In the
fiscal year ended March 31, 2008, we incurred a financial loss after taxation of
approximately $1.9 million. We plan to significantly increase our corporate
expenses and general overhead. There is no assurance, however, that we will be
able to successfully achieve an increase in production and reserves so as to
operate in a profitable manner. If the business of oil and natural gas well
exploration and development slows, and commodity prices notably decline, our
margins and profitability will suffer. We are unable to predict whether our
operating results will be profitable.





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





•           identify
and exploit oil and natural gas opportunities;





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





•           evaluate
drilling opportunities; and





•           evaluate
future projects and areas for long term development.





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





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





•           success
of ongoing operations;





•           forward
commodity prices; and





•           operating
costs (including human resource costs).





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





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





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





9


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





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





Risks
Related to Our Business





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





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





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





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





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





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





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





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





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




10





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





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





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





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





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





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





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





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





We are a
small company with minimal employees as of March 31, 2008. We expect to
experience a period of significant expansion in headcount, facilities,
infrastructure and overhead and anticipate that further expansion will be
required to address potential growth and market opportunities. Future growth
will impose significant added responsibilities on members of management,
including the need to identify, recruit, maintain and integrate additional
independent contractors and managers. Our future financial performance and our
ability to compete effectively will depend, in part, on our ability to manage
any future growth effectively.




11





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





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





•           the
domestic and foreign supply of oil and gas;


• the
ability of members of the Organization of Petroleum Exporting Countries, or
OPEC, and other producing countries to agree upon and maintain oil prices and
production levels;


•           political
instability, armed conflict or terrorist attacks, whether or not in oil or gas
producing regions;


•           the
level of consumer product demand;


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


•           labor
unrest in oil and natural gas producing regions;


•           weather
conditions, including hurricanes and other natural disasters;


•           the
price and availability of alternative fuels;


•           the
price of foreign imports;


•           worldwide
economic conditions; and


•           the
availability of liquid natural gas imports.





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





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





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





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





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





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





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




12





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





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





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





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





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





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





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





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





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





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





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




13





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





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





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





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





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





Our
common stock has been quoted on the OTC Bulletin Board under the symbol
“IXOG.OB” since December 16, 2005. There is a limited trading market for our
common stock. Furthermore, the trading in our common stock maybe highly
volatile, as for example, approximately more than two-thirds of the trading days
during February of 2008 saw trading in our stock of less than 100,000 shares per
day. During that same period, the smallest number of shares trade in one day was
zero and the largest number of shares traded in one day was 412,526.
Accordingly, there can be no assurance as to the liquidity of any markets that
may develop for our common stock, the ability of holders of our common stock to
sell our common stock, or the prices at which holders may be able to sell our
common stock.





The
price of our Common Stock may be volatile.





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





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


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


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


•
            changes
      in general economic conditions;


•
            changes
      in market prices for oil and gas;


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


•
            actions
      by institutional investors trading in our
stock;


•
            disruption
      of our operations;


•
            any
      major change in our management
team;


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


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





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




14




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





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





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


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





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





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


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





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





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


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





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





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





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





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





•
            institute
      a comprehensive compliance
function;


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


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


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


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


•
            establish
      an investor relations function.




15




In
addition, rules adopted by the SEC pursuant to Section 404 of the Sarbanes-Oxley
Act of 2002 will require annual assessment of our internal control over
financial reporting, and attestation of the assessment by our independent
registered public accountants. The requirement of an annual assessment of our
internal control over financial reporting and the attestation of the assessment
by our independent registered public accountants, as the rules now stand, will
first apply to our annual report for fiscal year ending March 31, 2009. In the
future, our ability to continue to comply with our financial reporting
requirements and other rules that apply to reporting companies could be
impaired, and we may be subject to sanctions or investigation by regulatory
authorities. In addition, failure to comply with Section 404 or a report of a
material weakness may cause investors to lose confidence in us and may have a
material adverse effect on our stock price.





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





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





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





We
currently have 6,103,947 outstanding options and warrants, excluding the Loyalty
Warrants associated with our $2.77 million private placement which have
contingent exercise requirements, and options to purchase shares of our common
stock outstanding, at March 31, 2008. The exercise of warrants and/or options by
a substantial number of holders within a relatively short period of time could
have the effect of depressing the market price of our common stock and could
impair our ability to raise capital through the sale of additional equity
securities. See Note #10 “Options and Warrants and Stock-Based Compensation” to
the Notes accompanying our audited financial statements filed
herewith.





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





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





Item
1B.  Unresolved Staff Comments





None





Item
2.  Properties.





Principal
Executive Offices





We hold
an arrangement to rent our main office comprising of approximately 300 square
feet which is located at 10,000 Memorial Drive, Suite 440, Houston, Texas 77024.
Lease payments at fiscal year ended March 31, 2008, were $4,500 per month and
are due on a month-to-month basis. We also have a month-to-month lease, related
to corporate housing for UK based officers while periodically working at the
corporate office.  This lease is currently operating on a rolling
monthly basis with $1,760 due per month.





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





Oil
and Gas Reserves





The March
31, 2008 proved reserve estimates presented in this Annual Report were prepared
by Ancell Energy Consulting, Inc. (“Ancell”). The estimates of quantities of
proved reserves below were made in accordance with the definitions contained in
SEC Regulation S-X, Rule 4-10(a). For additional information regarding estimates
of proved reserves, the preparation of such estimates by Ancell and other
information about our oil and natural gas reserves, see Item 7 “Management’s
Discussion and Analysis of Financial Condition and Results of Operations.” Our
reserves are sensitive to commodity prices and their effect on economic
producing rates. Our estimated proved reserves are based on oil and gas spot
market prices in effect for the periods presented in this report on the last
trading day of March 2008, 2007 and 2006, respectively. There are a number of
uncertainties inherent in estimating quantities of proved reserves, including
many factors beyond our control, such as commodity pricing. Therefore, the
reserve information in this Annual Report represents only estimates. Reservoir
engineering is a subjective process of estimating underground accumulations of
oil and natural gas that cannot be measured in an exact manner. The accuracy of
any reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a result, estimates
of different engineers may vary. In addition, results of drilling, testing and
production subsequent to the date of an estimate may justify revising the
original estimate. Accordingly, initial reserve estimates are often different
from the quantities of oil and natural gas that are ultimately recovered. The
meaningfulness of such estimates depends primarily on the accuracy of the
assumptions upon which they were based. Except to the extent we acquire
additional properties containing proved reserves or conduct successful
exploration and development activities or both, our proved reserves will decline
as reserves are produced.




16





At March
31, 2008, our estimated total proved oil and natural gas reserves were
approximately 219.469 MBoe, consisting of 37.767 thousand barrels of oil (MBbls)
and 1,090.213 million cubic feet (MMcf) of natural gas. Approximately 218.379
MBoe or 99.5% of our proved reserves were classified as proved developed
producing and proved behind pipe. We aim to maintain a portfolio of long-lived,
lower risk reserves along with shorter lived, higher margin reserves. We believe
that a balanced reserve mix will provide a diversified cash flow foundation to
contribute to funding our development and exploration drilling
programs.





The
following table presents certain information as of March 31, 2008, and for our
reserves and properties all located onshore in the United States. Shut-in wells
currently not capable of production are excluded from the producing well
information.





In
      MBoe:
            
            Kansas
            
            
            Louisiana
            
            
            Texas
            
            
            TotalProved
      Reserves at Year EndDeveloped
            
            
            13.942
            
            
            
            90.465
            
            
            
            113.972
            
            
            
            218.379Undeveloped
            
            
            1.090
            
            
            
            --
            
            
            
            --
            
            
            
            1.090Total
            
            
            15.032
            
            
            
            90.465
            
            
            
            113,972
            
            
            
            219.469Gross
      Wells (1)
            
            
            24.000
            
            
            
            1.000
            
            
            
            7.000
            
            
            
            32.000Net
      Wells (1)
            
            
            1.123
            
            
            
            0.300
            
            
            
            2.268
            
            
            
            3.691





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





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





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





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




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




17





Oil
prices used in this report are based on the March 31, 2008, oil price received
at various points and averaged $100.13 per barrel. Natural gas prices used in
this report are based on a March 31, 2008, NYMEX spot market price and averaged
of $10.11 per Mcf, adjusted by lease for energy content, transportation fees,
and regional price differentials. Oil and natural gas prices are held constant
in accordance with SEC guidelines.





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





Productive
Wells and Acreage





As of
March 31, 2008, we had interests in 32 gross productive wells (3.477 net
productive wells).  Our oil (only) wells totaled 21 gross productive
wells and 1.033 net productive oil wells, our gas (only) wells totaled 5 gross
productive wells and 1.375 net productive oil wells and our mixed oil and gas
wells totaled 6 gross and 1.069 net mixed oil and gas productive
wells.





Acreage





“Gross”
represents the total number of acres or wells in which a working interest is
owned and in which we own a working interest.  “Net” represents our
proportionate working interest resulting from our ownership in the gross acres
or wells. Productive wells are wells in which we have a working interest and
that are capable of producing oil or natural gas. The following table sets forth
our interest in undeveloped acreage and developed acreage in which we own a
working interest as of March 31, 2008.





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




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





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




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




18





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





March
      31,2008
            
            
            2007
            
            
            2006Capitalized
      costs:Proved and evaluated
      properties
            
            $
            11,181,430
            
            
            $
            3,254,211
            
            
            $
            722,056Unproved and unevaluated
      properties
            
            
            2,821,271
            
            
            
            1,927,776
            
            
            
            356,72914,002,701
            
            
            
            5,181,987
            
            
            
            1,078,785Less
      accumulated depreciation and depletion
            
            
            1,407,610
            
            
            
            315,937
            
            
            
            127,586$
            12,595,091
            
            
            $
            4,866,050
            
            
            $
            951,199




Production





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





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




Drilling
Activity





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





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





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




19




Present
Activities





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





Delivery
Commitments





At March
31, 2008, we had no delivery commitments with our purchasers.





Item
3.  Legal Proceedings.





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





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





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





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





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





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





20





PART
II





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





Market
Information





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





The
following sets forth the range of the closing bid prices for our common stock
for the quaters in the period starting April 1, 2006, through March 31, 2008.
Such prices represent inter-dealer quotations, do not represent actual
transactions, and do not include retail mark-ups, markdowns or commissions. Such
prices were determined from information provided by a majority of the market
makers for the Company’s common stock.





High
      Close
            
            
            Low
      Close2007
      Fiscal YearJune
      30, 2006
            
            
            1.65
            
            
            
            1.32September
      30, 2006
            
            
            1.54
            
            
            
            1.15December
      31, 2006
            
            
            1.70
            
            
            
            1.36March
      31, 2007
            
            
            1.65
            
            
            
            1.182008
      Fiscal YearJune
      30, 2007
            
            
            1.50
            
            
            
            0.78September
      30, 2007
            
            
            1.07
            
            
            
            0.70December
      31, 2007
            
            
            0.84
            
            
            
            0.49March
      31, 2008
            
            
            0.64
            
            
            
            0.47





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





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





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





Holders





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




21





Dividends





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





Securities
Authorized for Issuance Under Equity Compensation Plans





The
following table shows information with respect to each equity compensation plan
under which our common stock is authorized for issuance as of March 31,
2008:





Plan
      Category
            
            Number
      of securities to be issued upon exercise of outstanding options, warrants
      and rights
            
            
            Weighted
      average exercise price of outstanding options, warrants and
      rights
            
            
            Number
      of securities remaining available for future issuance under equity
      compensation plans (excluding securities reflected in column
      (a)(a)
            
            
            (b)
            
            
            (c)Equity
      compensation plans approved by security holders
            
            
            5,202,526
            
            
            $
            0.42
            
            
            
            22,474Equity
      compensation plans not approved by security holders
            
            
            -0-
            
            
            $
            -0-
            
            
            
            -0-Total
            
            
            5,202,526
            
            
            $
            0.42
            
            
            
            22,474





Unregistered
Sales of Equity Securities and Use of Proceeds





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





Issuance
of Unregistered Securities





None.





Purchases
of Equity Securities by the Issuer and Affiliated Purchasers.





None.




Item
6.  Selected Financial Data.





Not
Applicable.





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





Forward
Looking Statements





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




22





Business
Overview





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





Results
of Operations





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





We had a
net loss of $1.9 million for the fiscal year ended March 31, 2008 compared to a
net loss of $2.2 million for the fiscal year ended March 31,
2007.  Revenue and operating income increased by $1.2 million and $0.4
million, respectively, but were offset by general and administrative costs of
$2.5 million, which decreased by $0.3 million, increased
depletion of $0.9 million to $1.1 million and lower interest
income on capital previously raised and used in our operations.  The
following table summarizes key items of comparison and their related increase
(decrease) for the fiscal years ended March 31, 2008 and 2007.





Years
      Ended March 31,
            
            
            Increase2008
            
            
            2007
            
            
            (Decrease)Oil
      and gas sales
            
            $
            1,705,593
            
            
            $
            457,046
            
            
            $
            1,248,547Production
      expenses:Lease operating
            
            
            188,521
            
            
            
            80,186
            
            
            
            108,335Taxes
      other than income
            
            
            114,952
            
            
            
            34,549
            
            
            
            80,403General
      and administrative:General and
      administrative
            
            
            2,155,018
            
            
            
            1,848,142
            
            
            
            306,876Stock-based
      compensation
            
            
            302,911
            
            
            
            875,092
            
            
            
            (572,181
            )Depletion
      — Full cost
            
            
            1,091,673
            
            
            
            188,351
            
            
            
            903,322Depreciation
      — Other
            
            
            4,556
            
            
            
            1,028
            
            
            
            3,528Impairment
            
            
            --
            
            
            
            --
            
            
            
            --Interest
      expense (income) and other
            
            
            (205,608
            )
            
            
            (344,646
            )
            
            
            139,038Income
      tax benefit (provision)
            
            
            --
            
            
            
            --
            
            
            
            --Net
      income (loss)
            
            $
            (1,946,430
            )
            
            $
            (2,225,656
            )
            
            $
            279,226Production:Natural
      Gas — MMcf
            
            
            126.888
            
            
            
            8.490
            
            
            
            118.398Crude
      Oil — MBbl
            
            
            7.478
            
            
            
            6.660
            
            
            
            0.818Equivalent
      — MBoe
            
            
            28.626
            
            
            
            8.075
            
            
            
            20.551Average
      price per unit:Gas
      price per Mcf
            
            $
            8.21
            
            
            $
            6.61
            
            
            $
            1.60Oil
      price per Bbl
            
            $
            88.69
            
            
            $
            60.20
            
            
            $
            28.49Equivalent
      per Boe
            
            $
            59.58
            
            
            $
            56.60
            
            
            $
            2.98Average
      cost per Boe:Production
      expenses:Lease operating
            
            $
            6.59
            
            
            $
            9.93
            
            
            $
            (3.34
            )Taxes
      other than income
            
            $
            4.02
            
            
            $
            4.28
            
            
            $
            (0.26
            )General
      and administrative expense:General and
      administrative
            
            $
            75.28
            
            
            $
            228.87
            
            
            $
            (153.59
            )Stock-based
      compensation
            
            $
            10.58
            
            
            $
            108.37
            
            
            $
            (97.79
            )Depletion
      expense
            
            $
            38.14
            
            
            $
            23.32
            
            
            $
            14.82





For the
year ended March 31, 2008, oil and natural gas sales increased $1.2 million,
from the same period in 2007, to $1.7 million. The increase for the year was
primarily due to the increase in production volumes of 20.6 MBoe from 8.1 MBoe
to 28.6 MBoe or approximately the whole $1.2 million increase. The increase in
volumes of 20.6 MBoe was primarily due to new volumes from Outlar of 6.3
MBoe, Shadyside of 6.8 MBoe Friedrich of 4.8 MBoe and Schroeder of 2.2 MBoe,
offset by Walker which decreased 2.0 MBoe and our Kansas wells which decreased,
in total, by 1.0 MBoe. The Cason wells also contributed 1.5 MBoe along with
Hawkins which contributed 0.7 MBoe.  Total oil production was 7.5 MBoe
and total natural gas production was 126.9 MMcf.  Additionally, our
revenue variance related to year on year price changes was a slight increase
with our average price per Boe increasing by $2.98, or 5.0%, in fiscal 2008 to
$59.58 per Bbl from $56.60 per Bbl in fiscal 2007 and reflecting an increased
proportion of natural gas volumes which had a lower energy equivalent value.
This is based on weighted average gas volumes at an increased price of $8.21 per
Mcf and weighted average oil volumes at an increased price per barrel of $88.69.
We benefited from increased product prices in the year to March 31, 2008, both
for oil and natural gas.  However, our production and sales mix has
switched to become predominantly natural gas comprised and the year on year
price increase on a Boe basis is less significant than the absolute price
changes for each product, due to natural gas realizing a lower energy equivalent
price compared to crude oil.




23





Our major
market risk exposure to inflation is in the pricing of our oil and natural gas
production. Realized pricing is primarily driven by the prevailing worldwide
price for crude oil and spot market prices applicable to our U.S. natural gas
production. Pricing for oil and natural gas production has been volatile and
unpredictable for several years, and we expect this volatility to continue in
the future. The prices we receive for production depend on many factors outside
of our control. Based on average daily production for the years ended March 31,
2008 and 2007, our annual income before income taxes would change by
approximately $12,000 and $1,000, respectively for each $0.10 per Mcf
change in natural gas prices and approximately $7,000 and $6,000,
respectively for each $1.00 per Bbl change in crude oil prices, excluding
the effects of hedging activities, which we currently do not engage
in.





Lease
operating expenses increased approximately $0.1 million for the year ended March
31, 2008 as compared to the same period in 2007. The increase was primarily due
to production from the new wells in fiscal year 2008 of Outlar, Shadyside, the
three Cason wells, Ducroz and Hawkins.  This also included a full year
of production for the Friedrich and Schroeder wells that were drilled in fiscal
year 2007 and completed in fiscal year 2008.  On a per unit basis,
lease operating expenses decreased significantly by $3.34 per Boe to $6.59 per
Boe in 2008 from $9.93 per Boe in 2007 due primarily to an increase in
production volumes offset by industry-wide service costs associated with the
overall increase in commodity prices.





Taxes
other than income increased $0.1 million for the year ended March 31, 2008 as
compared to the same period in 2007 due to higher oil and gas revenues, but on a
per unit basis decreased $0.26 per Boe to $4.02 per Boe. This was due to our
increased production in the State of Texas, relative to our Louisiana and Kansas
wells.  Production taxes are generally assessed as a percentage of
gross oil and/or natural gas sales.




General
and administrative expenses, excluding stock-based compensation expense, for the
year ended March 31, 2008 increased $0.3 million to $2.2 million compared to the
same period in 2007.  The increase in general and administrative
expenses was 17% for the fiscal year ended March 31, 2008 versus 163% and 59%
for the same period in 2007 and 2006, respectively. We recruited senior
management staff in the exploration and production, land and operations and
accounting areas and therefore, associated expenses related to salaries, fees,
benefits and business expenses for employee/directors increased approximately
$0.1 million.   Consulting fees and public company costs
increased by approximately $0.2 million with the implementation of Sarbanes
Oxley 404 compliance efforts, continued SEC filing fees, investor relations
costs and other professional fees as the Company pursues growth
strategies.





Stock-based
compensation expense, within general and administrative expenses, was $0.3
million for the year ended March 31, 2008 as compared to $0.9 million for the
year ended March 31, 2007 for a net decrease of $0.6 million in fiscal 2008.
This is primarily due to more stock-based compensation expense in fiscal year
2007 related to a larger stock-based award in 2006 granted to all officers and
directors, at the effective date of the reverse merger with Index Ltd., which
was largely expensed in fiscal years 2006 and 2007 and not in fiscal year
2008.  This stock-based compensation expense was greater than the
stock-based compensation expense generated from new stock awards granted in
fiscal year 2008.  All stock compensation was calculated at fair
market value and other required inputs at the date of the grant in accordance
with SFAS 123(R).





Depletion
expense increased $0.9 million from the same period in 2007 to $1.1 million for
the year ended March 31, 2008. This increase is primarily due to increased
volumes as detailed above. Depletion for oil and gas properties is calculated
using the unit of production method, which essentially depletes the capitalized
costs associated with the proved properties based on the ratio of production
volume for the current period to total remaining reserve volume for the proven
properties. On a per unit basis, average depletion expense increased 63% from
$23.32 to $38.14 per Boe.





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





There was
no provision for income taxes for the fiscal years ended 2008 and 2007 due to a
valuation allowance of $5.1 million and $2.0  million recorded for the
years ended March 31, 2008 and 2007, respectively on the total tax provision as
we believed that it is more likely than not that the asset will not be utilized
during the next year.




24




Liquidity
and Capital Resources





Our
primary sources of cash in fiscal year 2008 were from financing and equity
transactions. Proceeds from private placement equity fund raising was offset by
cash used in operating and investing activities for our properties. Operating
cash flow fluctuations were substantially driven by commodity prices and changes
in our production volumes. Prices for oil and natural gas have historically been
subject to seasonal influences characterized by peak demand and higher prices in
the winter heating season for natural gas and summer travel for oil; however,
the impact of other risks and uncertainties have influenced prices throughout
the recent years. Working capital was substantially influenced by these
variables. Fluctuation in cash flow may result in an increase or decrease in our
capital and exploration expenditures. See Results of Operations for a review of
the impact of prices and volumes on sales. Cash flows continued to be used in
operating activities and did not contribute to funding exploration and
development expenditures. See below for additional discussion and analysis of
cash flow.





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




Operating
Activities





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





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





Investing
Activities





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





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





Financing
Activities





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




25





On
February 26, 2008, we closed on a private placement offering in which it sold an
aggregate 5,541,182 units of its securities at a price of $0.50 per Unit, each
Unit consisting of 1 share of Common Stock, $0.001 par value, and one Loyalty
Warrant to purchase to purchase 0.50 share of Common Stock, at a purchase price
of $0.50 per share, for aggregate gross proceeds of approximately $2.77 million.
The Loyalty Warrant shall not be exercisable until February 28, 2010, and only
those investors who meet the requirements set forth in the Loyalty Warrant shall
be able to exercise the Loyalty Warrant at that time and thereafter. The net
proceeds of the offering were used as working capital and for general corporate
purposes of the Company.




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





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





As of
March 31, 2008 and 2007, our common stock is the only class of stock outstanding
and we have no outstanding long-term debt financing.





Contractual
Obligations





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





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





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





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





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





Off-Balance
Sheet Arrangements





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




26





Critical
Accounting Policies and Estimates





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





Oil
and Gas Activities





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





Full
Cost Method





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





Proved
Oil and Gas Reserves





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





Our
estimated proved reserves for the four years ended March 31, 2008 were prepared
by Ancell Energy Consulting, Inc., an independent petroleum engineering
firm. For more information regarding reserve estimation, including historical
reserve revisions, refer to Item 8. Consolidated Financial Statements and
Supplementary Data, Supplemental Oil and Gas Disclosure.




27





Depreciation,
Depletion and Amortization





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





Full
Cost Ceiling Limitation





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





Future
Development and Abandonment Costs





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





The
accounting for future abandonment costs changed on January 1, 2003 with the
adoption of SFAS No. 143, Accounting for Asset Retirement Obligations. This new
standard requires that a liability for the discounted fair value of an asset
retirement obligation be recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its present value each period,
and the capitalized cost is depreciated over the useful life of the related
asset. Holding all other factors constant, if our estimate of future abandonment
and development costs is revised upward, earnings would decrease due to higher
depreciation, depletion and amortization (DD&A) expense. Likewise, if these
estimates are revised downward, earnings would increase due to lower DD&A
expense. Of the total ARO, $88,209 and $41,552 are classified as a long-term
liability at March 31, 2008 and 2007, respectively. For each of the years ended
March 31, 2008 and 2007, the Company recognized no depreciation expense related
to its ARO, due to the assumption of a full offset of salvage
values.





Allocation
of Purchase Price in Business Combinations





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





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




28





Revenue
Recognition





We
recognize revenue when crude oil and natural gas quantities are delivered to or
collected by the respective purchaser or operator (collectively "purchasers").
We sold our crude oil and natural gas production to several purchasers as
of March 31, 2008. Title to the produced quantities transfers to the purchaser
at the time the purchaser collects or receives the quantities. Prices for such
production are defined in sales contracts and are readily determinable based on
certain publicly available indices. The purchasers of such production have
historically made payment for crude oil and natural gas purchases within
forty-five days of the end of each production month. We periodically review the
difference between the dates of production and the dates we collect payment for
such production to ensure that receivables from those purchasers are
collectible. All transportation costs are accounted for as a reduction of oil
and natural gas sales revenue.





Recently
Issued Accounting Standards





Certain Hybrid Instruments.
On February 16, 2006 the FASB issued SFAS 155, “Accounting for Certain Hybrid
Instruments,” which amends SFAS 133, “Accounting for Derivative Instruments and
Hedging Activities,” and SFAS 140, “Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities.” SFAS 155 allows financial
instruments that have embedded derivatives to be accounted for as a whole
(eliminating the need to bifurcate the derivative from its host) if the holder
elects to account for the whole instrument on a fair value basis. SFAS 155 also
clarifies and amends certain other provisions of SFAS 133 and SFAS 140. This
statement is effective for all financial instruments acquired or issued in
fiscal years beginning after September 15, 2006. The Company adopted this new
standard, effective April 1, 2007, with no impact on its consolidated financial
position, results of operations or cash flows as it currently does not have any
hybrid instruments outstanding at December 31, 2007 and March 31, 2007,
respectively.





Accounting for Servicing of
Financial Assets. In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of
Financial Assets—an amendment of FASB Statement No. 140”(“SFAS No. 156”),
which amends FASB Statement No. 140, Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities, with
respect to the accounting for separately recognized servicing assets and
servicing liabilities. This Statement requires that all separately recognized
servicing assets and servicing liabilities be initially measured at fair value,
if practicable. The Board concluded that fair value is the most relevant
measurement attribute for the initial recognition of all servicing assets and
servicing liabilities, because it represents the best measure of future cash
flows. This Statement permits, but does not require, the subsequent measurement
of servicing assets and servicing liabilities at fair value. An entity that uses
derivative instruments to mitigate the risks inherent in servicing assets and
servicing liabilities is required to account for those derivative instruments at
fair value. Under this Statement, an entity can elect subsequent fair value
measurement of its servicing assets and servicing liabilities by class, thus
simplifying its accounting and providing for income statement recognition of the
potential offsetting changes in fair value of the servicing assets, servicing
liabilities, and related derivative instruments. An entity that elects to
subsequently measure servicing assets and servicing liabilities at fair value is
expected to recognize declines in fair value of the servicing assets and
servicing liabilities more consistently than by reporting other-than-temporary
impairments.  The Company adopted this new standard effective April 1,
2007, with no impact on the Company’s consolidated financial position,
results of operations or cash flows as the Company does not have any derivative
or hedging instruments.





Income Taxes. In June 2006,
the FASB issued FASB Interpretation No 48 (“FIN 48”), “Accounting for
Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109”, which
clarifies the accounting for uncertainty in income taxes recognized in an
enterprise’s financial statements in accordance with FASB 109. The
Interpretation prescribes a recognition threshold and measurement attribute for
the financial statement recognition and measurement of a tax position taken or
expected to be taken in a tax return. The Interpretation also provides guidance
on derecognition, classification, interest and penalties, accounting in interim
periods, disclosure and transition. The Company adopted the new standard
effective April 1, 2007 with no material impact on the Company’s consolidated
financial position, results of operations or cash flows.





In
December 2006, the FASB issued FSP EITF 00-19-2, Accounting for Registration
Payment Arrangements (“FSP 00-19-2”) which addresses accounting for registration
payment arrangements. FSP 00- 19-2 specifies that the contingent obligation to
make future payments or otherwise transfer consideration under a registration
payment arrangement, whether issued as a separate agreement or included as a
provision of a financial instrument or other agreement, should be separately
recognized and measured in accordance with FASB Statement No. 5, Accounting for
Contingencies. FSP 00-19-2 further clarifies that a financial instrument subject
to a registration payment arrangement should be accounted for in accordance with
other applicable generally accepted accounting principles without regard to the
contingent obligation to transfer consideration pursuant to the registration
payment arrangement. For registration payment arrangements and financial
instruments subject to those arrangements that were entered into prior to the
issuance of EITF 00-19-2, this guidance shall be effective for financial
statements issued for fiscal years beginning after December 15, 2006 and interim
periods within those fiscal years. The Company adopted the new pronouncement
effective April 1, 2007 with no impact the Company’s consolidated financial
position, results of operations or cash flows.




29





New
Accounting Pronouncements Not Yet Adopted





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




a.
            How
      and why an entity uses derivative instrumentsb.
            How
      derivative instruments and related hedged items are accounted for under
      Statement 133 and its related
interpretations


c.
            How
      derivative instruments and related hedged items affect an entity’s
      financial position, financial performance, and cash
  flows.





To meet
those objectives, this Statement requires qualitative disclosures about
objectives and strategies for using derivatives, quantitative disclosures about
fair value amounts of and gains and losses on derivative instruments, and
disclosures about credit-risk-related contingent features in derivative
agreements.  This Statement shall be effective for financial
statements issued for fiscal years and interim periods beginning after November
15, 2008. Early application is encouraged.  This Statement encourages
but does not require disclosures for earlier periods presented for comparative
purposes at initial adoption. In years after initial adoption, this Statement
requires comparative disclosures only for periods subsequent to initial
adoption.  The adoption of SFAS 161 is not expected to have an impact
on the Company’s consolidated financial position, results of operations or cash
flows as the Company has not engaged in any derivative instruments or hedging
activities.





The Hierarchy of Generally Accepted
Accounting Principles.  In May 2008, the FASB issued SFAS No.
162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS
162”).  This Statement identifies the sources of accounting principles
and the framework for selecting the principles used in the preparation of
financial statements of nongovernmental entities that are presented in
conformity with generally accepted accounting principles (GAAP) in the United
States (the GAAP hierarchy).  This Statement shall be effective 60
days following the SEC’s approval of the Public Company Accounting Oversight
Board (PCAOB) amendments to AU Section 411, The Meaning ofPresent Fairly in
Conformity With Generally Accepted Accounting Principles.  An entity
that has and continues to follow an accounting treatment in category (c) or category (d) as of March 15, 1992, need
not change to an accounting treatment in a higher category ((b) or (c)) if its effective date was
before March 15, 1992.  For pronouncements whose effective date is
after March 15, 1992, and for entities initially applying an accounting
principle after March 15, 1992 (except for EITF consensus positions issued
before March 16, 1992, which become effective in the hierarchy for initial
application of an accounting principle after March 15, 1993), an entity shall
follow this Statement.  Any effect of applying the provisions of this
Statement shall be reported as a change in accounting principle in accordance
with FASB Statement No. 154, Accounting Changes and Error Corrections.An entity shall follow the disclosure requirements of that Statement, and
additionally, disclose the accounting principles that were used before and after
the application of the provisions of this Statement and the reason why applying
this Statement resulted in a change in accounting principle. The Company has not
yet assesed the impact of this Statement on its consolidated financial position,
results of operations or cash flows.





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




30




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





Fair Value Measurements. In
September 2006, the FASB issued SFAS 157, “Fair Value Measurements”, which
defines fair value, establishes a framework for measuring fair value in
generally accepted accounting principles (“GAAP”), and expands disclosures about
fair value measurements. Prior to this Statement, there were different
definitions of fair value and limited guidance for applying those definitions in
GAAP. This Statement provides the definition to increase consistency and
comparability in fair value measurements and for expanded disclosures about fair
value measurements. The Statement emphasizes that fair value is a market-based
measurement, not an entity-specific measurement. The Statement clarifies that
market participant assumptions include assumptions about risk, i.e. the risk
inherent in a particular valuation technique used to measure fair value and/or
the risk inherent in the inputs to the valuation technique. The Statement
expands disclosures about the use of fair vale to measure assets and liabilities
in interim and annual periods subsequent to initial recognition. The disclosures
focus on the inputs used to measure fair value and for recurring fair value
measurements using significant unobservable inputs, the effect of the
measurements on earnings for the period. The Statement is effective for
financial statements issued for fiscal years beginning after November 15, 2007,
and interim periods within those fiscal years. Earlier application is
encouraged, provided that the reporting entity has not yet issued financial
statements for that fiscal year, including the financial statements for an
interim period within that fiscal year. In November207, the FASB deferred the
implementation of SFAS 157 for non-financial assets and liabilities until
October 2008.  The Company does not expect adoption of this standard
will have a material impact on its consolidated financial position, results
of operations or cash flows.





The Fair Value Option for Financial
Assets and Financial Liabilities. In February 2007, the FASB issued SFAS
159, “The Fair Value Option for Financial Assets and Financial
Liabilities—including an amendment of FASB Statement No. 115”, permitting
entities to choose to measure many financial instruments and certain other items
at fair value. The objective is to improve financial reporting by providing
entities with the opportunity to mitigate volatility in reported earnings caused
by measuring related assets and liabilities differently without having to apply
complex hedge accounting measurement. The statement applies to all entities,
including not-for profit organizations. Most of the provisions of this Statement
apply only to entities that elect the fair value option. However, the amendment
to FASB Statement No. 115, “Accounting for Certain Investments in Debt and
Equity Securities”, applies to all entities with available-for-sale and trading
securities. The Company does not expect adoption of this standard will have a
material impact on its consolidated financial position, results of
operations or cash flows.





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





Not
applicable.





Item
8.  Financial Statements and Supplementary Data.





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





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





None.





Item
9A. Controls and Procedures.





Not
Applicable.





31





Item 9A(T).  Controls and
Procedures.





Evaluation
of Disclosure Controls and Procedures




Under the
supervision and with the participation of our management, including our Chief
Executive Officer and Chief Financial Officer, we conducted an evaluation of the
effectiveness of the design and operation of our disclosure controls and
procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities
Exchange Act of 1934, as amended (“Exchange Act”), as of March 31, 2008.
Disclosure controls and procedures are those controls and procedures designed to
provide reasonable assurance that the information required to be disclosed in
our Exchange Act filings is (1) recorded, processed, summarized and reported
within the time periods specified in Securities and Exchange Commission’s rules
and forms, and (2) accumulated and communicated to management, including our
Chief Executive Officer and Chief Financial Officer, as appropriate, to allow
timely decisions regarding required disclosure.




Based on
that evaluation, the Chief Executive Officer and Chief Financial Officer
concluded that, as of March 31, 2008, our disclosure controls and procedures
were effective.




Management’s
Annual Report on Internal Control Over Financial Reporting





Management,
including our Chief Executive Officer and Chief Financial Officer, is
responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act Rule 13a –
15(f).  Management conducted an assessment as of March 31, 2008 of the
effectiveness of our internal control over financial reporting based on the
framework in Internal Control
– Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (“COSO”).  Based on that
evaluation, management concluded that our internal control over financial
reporting was effective as of March 31, 2008, based on criteria inInternal Control – Integrated
Framework issued by the COSO.





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





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





Changes
in Internal Control Over Financial Reporting




There has
been no change in our internal control over financial reporting during the
quarter ended March 31, 2008 that has materially affected, or is reasonably
likely to materially affect, our internal control over financial
reporting.




Item 9B.  Other
Information.





None.





PART
III





Item
10. Directors, Executive Officers, and Corporate Governance.




The
information required to be contained in this Item is incorporated by reference
from Part I of this report and by reference either to our definitive proxy
statement to be filed with respect to our 2008 annual meeting or via the filing
of an amendment to this Annual Report on Form 10-K.




32





Item
11. Executive Compensation.





The
information required to be contained in this Item is incorporated either by
reference to our definitive proxy statement to be filed with respect to our 2008
annual meeting under the heading “Executive Compensation” or via the filing of
an amendment to this Annual Report on Form 10-K.





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





This
information required to be contained in this Item is incorporated either by
reference to our definitive proxy statement to be filed with respect to our 2008
annual meeting under the heading “Principal Stockholders and Security Ownership
of Management” or via the filing of an amendment to this Annual Report on Form
10-K.




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





The
information required to be contained in this Item is incorporated either by
reference to our definitive proxy statement to be filed with respect to our 2008
annual meeting under the heading “Certain Transactions” or via the filing of an
amendment to this Annual Report on Form 10-K.





Item
14.  Principal Accountant Fees and
Services.





The
information required to be contained in this Item is incorporated either by
reference to our definitive proxy statement to be filed with respect to our 2008
annual meeting or via the filing of an amendment to this Annual Report
on Form 10-K.








PART
IV





Item 15.Exhibits
and Financial Statement Schedules.




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




(1)
            Our
      Consolidated Financial Statements are listed on page F-1 of this Annual
      Report.(2)
            Financial
      Statement Schedules:




None




(3)
            Exhibits:




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




Exhibit
              Number
            
            Description3(i)(1)1
            
            Articles
      of Incorporation of Index Oil and Gas Inc., Inc. (4)3(i)(2)
            
            Certificate
      of Amendment to the Articles of Incorporation of Index Oil and Gas Inc.
      (the “Company”), filed with the Secretary of the State of Nevada on
      November 30, 2005, changing the name of the Company from Thai One On Inc.
      to Index Oil and Gas Inc., Inc., and increasing the number of authorized
      shares from 25,000,000 to 75,000,000. (1)3(i)(2)
            
            Certificate
      of Amendment to the Articles of Incorporation of Index Oil and Gas Inc.
      (the “Company”), filed with the Secretary of the State of Nevada on
      September 21, 2006, increasing the number of authorized shares from
      75,000,000 to 500,000,000, and creating a class of preferred stock,
      authorizing the issuance of 10,000,000 shares, $0.001 par value per share,
      of preferred stock. (7)3(ii)
            
            Bylaws
      of Index Oil and Gas Inc. (4)10.1
            
            Acquisition
      Agreement between Index Oil and Gas Inc., certain stockholders of Index
      Oil & Gas Ltd, and Briner Group Inc. dated January 20, 2006.
      (1)




33




10.2
            
            Form
      of Share and Warrant Exchange Agreement entered into by and between Index
      Oil and Gas Inc., Inc. and certain Index Oil & Gas Ltd stockholders.
      (1)10.3+
            
            Employment
      Agreement entered into by and between Index Oil & Gas Ltd and Lyndon
      West, dated January 20, 2006. (1)10.4+
            
            Employment
      Agreement entered into by and between Index Oil & Gas Ltd and Andy
      Boetius, dated January 20, 2006. (1)10.5+
            
            Employment
      Agreement entered into by and between Index Oil & Gas Ltd and Daniel
      Murphy, dated January 20, 2006. (1)10.6+
            
            Letter
      Agreement entered into by and between Index Oil & Gas Ltd and David
      Jenkins, dated January 20, 2006. (1)10.7+
            
            Letter
      Agreement entered into by and between Index Oil & Gas Ltd and Michael
      Scrutton, dated January 20, 2006. (1)10.8+
            
            Employment
      Agreement entered into by and between Index Oil and Gas Inc. and John G.
      Williams, dated August 29, 2006. (5)10.9
            
            Form
      of Subscription Agreement dated as of January 20, 2006.
  (1)10.10
            
            Form
      of Subscription Agreement dated as of August 29 and October 4, 2006.
      (6)10.11
            
            Form
      of Registration Rights Agreement dated as of August 29, 2006.
      (6)10.12+
            
            Index
      Oil and Gas Inc. 2006 Incentive Stock Option Plan. (9)10.13
            
            Securities
      Purchase Agreement dated as of November 5, 2007. (10)10.14
            
            Form
      of Warrant to Purchase Common Stock. (10)14.1
            
            Code
      of Ethics and Business Conduct for officers, directors and employees of
      Index Oil and Gas Inc. adopted by the Company’s Board of Directors on
      March 31, 2006. (3)


21.1
            
            List
      of subsidiaries of the Company. *23.1
            
            Consent
      of RBSM LLP. *23.2
            
            Consent
      of Ancell Energy Consulting, Inc. *31.1
            
            Certification
      by Chief Executive Officer required by Rule 13a-14(a) or Rule 15d-14(a) of
      the Exchange Act. *31.2
            
            Certification
      by Chief Financial Officer required by Rule 13a-14(a) or Rule 15d-14(a) of
      the Exchange Act. *32.1
            
            Certification
      by Chief Executive Officer required by Rule 13a-14(b) or Rule 15d-14(b) of
      the Exchange Act and Section 1350 of Chapter 63 of Title 18 of the United
      States Code. *32.2
            
            Certification
      by Chief Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) of
      the Exchange Act and Section 1350 of Chapter 63 of Title 18 of the United
      States Code. *




34





*
      Filed Herewith+
      Compensatory plan or arrangement(1)
      Incorporated by reference to the Company’s Amended Current Report filed on
      Form 8-K/A with the SEC on March 15, 2006.(2)
      Incorporated by reference to the Company’s Annual Report filed on Form
      10-K with the SEC on July 17, 2006.(3)
      Incorporated by reference to the Company’s Annual Report filed on Form
      10-KSB with the SEC on April 10, 2006.(4)
      Incorporated by reference to the Company’s Registration Statement filed on
      Form SB-2 with the SEC on May 24, 2004.(5)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on September 8, 2006.(6)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on September 11, 2006.(7)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on September 28, 2006.(8)
      Incorporated by reference to the Company’s Registration Statement filed on
      Form SB-2 with the SEC on October 11, 2006.(9)
      Incorporated by reference to the Company’s Registration Statement filed on
      Form S-8 with the SEC on October 3, 2007.(10)
      Incorporated by reference to the Company’s Current Report filed n Form 8-K
      with the SEC on February 29, 2008.


















35


SIGNATURES




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




INDEX
      OIL AND GAS INC.Date: June
      30, 2008
              By:
              /s/ Lyndon WestLyndon
      WestPresident
      and Chief Executive Officer




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







36


Index
to Consolidated Financial Statements








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

















F-1






REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





Board of
Directors


Index Oil
and Gas Inc.


Houston,
USA





We have
audited the accompanying consolidated balance sheets of Index Oil and Gas Inc.
(and subsidiaries) (the “Company”) as of March 31, 2008 and 2007 and the related
consolidated statements of losses, stockholders’ equity, and cash flows for each
of the two years in the period ended March 31, 2008. These financial statements
are the responsibility of the company’s management. Our responsibility is to
express an opinion on the financial statements based upon our
audits.





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





In our
opinion, the financial statements referred to above present fairly, in all
material respects, the financial position of Index Oil and Gas Inc. at March 31,
2008 and 2007 and the results of its operations and its cash flows for each of
the two years in the period ended March 31, 2008, in conformity with accounting
principles generally accepted in the United States of America.




/s/ RBSM
      LLP





New York,
New
York


June 30,
2008




F-2




INDEX
OIL AND GAS INC.


CONSOLIDATED
BALANCE SHEETS


MARCH
31, 2008 AND 2007




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






See
accompanying notes to consolidated financial statements




F-3




INDEX
OIL AND GAS INC.


CONSOLIDATED
STATEMENT OF LOSSES


FOR
THE YEARS ENDED MARCH 31, 2008 AND 2007





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







See
accompanying notes to consolidated financial statements




F-4





INDEX
OIL AND GAS INC.


CONSOLIDATED
STATEMENT OF STOCKHOLDERS’ EQUITY


FOR
THE TWO YEARS ENDED MARCH 31, 2008








Common
      Stock
            
            
            Additional Paid
      in
            
            
            (Accumulated
            
            
            Other Comprehensive
            
            
            Total Stockholders’Shares
            
            
            Amount
            
            
            Capital
            
            
            Deficit)
            
            
            Income/(Loss)
            
            
            EquityBalance
      at March 31, 2006
            
            
            54,544,345
            
            
            $
            54,544
            
            
            $
            8,387,306
            
            
            $
            (2,575,581
            )
            
            $
            19,690
            
            
            $
            5,885,959Issuance
      of common stock on private offerings
            
            
            10,965,598
            
            
            
            10,966
            
            
            
            10,954,632
            
            
            
            -
            
            
            
            -
            
            
            
            10,965,598Stock
      issue costs
            
            
            -
            
            
            
            -
            
            
            
            (1,190,512
            )
            
            
            -
            
            
            
            -
            
            
            
            (1,190,512
            )Stock
      compensation, net of tax of $0
            
            
            -
            
            
            
            -
            
            
            
            792,342
            
            
            
            -
            
            
            
            -
            
            
            
            792,342Issuance
      of stock upon vesting of stock award
            
            
            50,000
            
            
            
            50
            
            
            
            (50
            )
            
            
            -
            
            
            
            -
            
            
            
            -Issuance
      of stock for services, net of tax of $0
            
            
            40,000
            
            
            
            40
            
            
            
            63,960
            
            
            
            -
            
            
            
            -
            
            
            
            64,000Issuance
      of stock upon exercise of warrants
            
            
            124,593
            
            
            
            125
            
            
            
            17,318
            
            
            
            -
            
            
            
            -
            
            
            
            17,443Issuance
      of stock for performance bonuses
            
            
            12,500
            
            
            
            12
            
            
            
            18,738
            
            
            
            -
            
            
            
            -
            
            
            
            18,750Other
      comprehensive income foreign currency
              translation
      adjustment
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (4,291
            )
            
            
            (4,291
            )Net
      loss
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (2,225,656
            )
            
            
            -
            
            
            
            (2,225,656
            )Balance
      at March 31, 2007
            
            
            65,737,036
            
            
            $
            65,737
            
            
            $
            19,043,734
            
            
            $
            (4,801,237
            )
            
            $
            15,399
            
            
            $
            14,323,633Issuance
      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
            
            
            $
            15,063,977








See
accompanying notes to consolidated financial statements




F-5




INDEX
OIL AND GAS INC.


CONSOLIDATED
STATEMENT OF CASH FLOWS


FOR
THE YEARS ENDED MARCH 31, 2008 AND 2007





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








See
accompanying notes to consolidated financial statements




F-6




INDEX
OIL AND GAS INC.


NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


MARCH
31, 2008 AND 2007





NOTE
1 - ORGANIZATION AND OPERATIONS OF THE COMPANY





Organization





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





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






Overview





For the
fiscal year ended March 31, 2008, Index had year-on-year increases in reserves,
production and revenue.  The Company sustained its history of drilling
success rates, while pursuing higher-impact prospects, all while remaining debt
free.  The Company, as described more fully in “Recent Financing”,
raised $2.77 million in gross proceeds in a private equity fund raise in a very
challenging fiscal environment.  The Company also recruited highly
experienced senior staff members in exploration and production, land and
operations and in accounting to the Index team.





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





Operations





The
Company’s initial exploration project is located in Kansas, and is a very low
risk, low cost, low working interest, and limited upside project and which is
not expected to be a significant contributor to future growth.  Our
working interest (“WI”) in the Kansas Area of Mutual Interest ("AMI") wells is
either 5% for wells drilled in Stafford County or 3.25% for wells drilled in
Barton County and the net revenue interest (“NRI”) is either approximately
4.155% or 2.64%, respectively. The Company has committed to a current program of
14 wells for low-risk prospects in Stafford and Barton Counties. To-date, in
this program, the Company has participated in eight wells, of which in June
2008, four are now on production (including one Stafford County well which was
drilled under farm in arrangements and in which Index has a 2.5% WI), one is
being completed and three have been plugged and abandoned. The two most recent
wells with a 3.25% working interest and a 2.64% net revenue interest are the
Salem #1-8 well which was completed in April 2008 and the Miller-McReynolds Unit
1-17 which was spudded in April 2008, completed and began production in June
2008.  Further activity is expected at approximately two wells per
month dependent on commodity pricing and evaluation of the program to
date.  Total net production for the fiscal year ended March 31, 2008
for all Kansas wells was 2,500 Bbls or 15.0 MMcfe (thousand Mcf of natural gas
equivalent).




F-7





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





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




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





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





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





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





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




F-8




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





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





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





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





Recent
Financing:




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




NOTE
2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES





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




F-9





Principles of
Consolidation





The
consolidated financial statements as of March 31, 2008 and 2007 and for the
years ended March 31, 2008 and 2007 include the accounts of the Company and its
wholly owned subsidiaries after eliminating all significant intercompany
accounts and transactions.





Use of
Estimates





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





Correction of
Errors





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




Cash and Cash Equivalents,
and Concentrations of Credit Risk





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





Accounting for Bad Debts and
Allowances





Bad debts
and allowances are provided based on historical experience and management's
evaluation of outstanding accounts receivable. The management periodically
evaluates past due or delinquency of accounts receivable in evaluating its
allowance for doubtful accounts. There was no allowance for doubtful accounts at
March 31, 2008 and 2007.





Other Current
Assets





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




F-10





Oil and Gas
Properties





The
Company follows the full cost method of accounting for oil and gas properties.
Accordingly, all costs associated with acquisition, exploration, and development
of properties within a relatively large geopolitical cost center are capitalized
when incurred and are amortized as mineral reserves in the cost center are
produced, subject to a limitation that the capitalized costs not exceed the
value of those reserves. In some cases, however, certain significant costs, such
as those associated with offshore U.S. operations, are deferred separately
without amortization until the specific property to which they relate is found
to be either productive or nonproductive, at which time those deferred costs and
any reserves attributable to the property are included in the computation of
amortization in the cost center. All costs incurred in oil and gas producing
activities are regarded as integral to the acquisition, discovery, and
development of whatever reserves ultimately result from the efforts as a whole,
and are thus associated with the Company’s reserves. The Company capitalizes
internal costs directly identified with performing or managing acquisition,
exploration and development activities. The Company has not capitalized any
internal costs or interest at March 31, 2008 and 2007. Unevaluated costs are
excluded from the full cost pool and are periodically evaluated for impairment
rather than amortized. Upon evaluation, costs associated with productive
properties are transferred to the full cost pool and amortized. Gains or losses
on the sale of oil and natural gas properties are generally included in the full
cost pool unless the entire pool is sold.





Capitalized
costs and estimated future development costs are amortized on a
unit-of-production method based on proved reserves associated with the
applicable cost center. The Company has assessed the impairment for oil and
natural gas properties for the full cost pool at March 31, 2008 and 2007 and
will assess quarterly thereafter using a ceiling test to determine if impairment
is necessary. Specifically, the net unamortized costs for each full cost pool
less related deferred income taxes should not exceed the following:
(a) the present value, discounted at 10%, of future net cash flows from
estimated production of proved oil and gas reserves plus (b) all costs being
excluded from the amortization base plus (c) the lower of cost or estimated fair
value of unproved properties included in the amortization base less (d) the
income tax effects related to differences between the book and tax basis of the
properties involved. The present value of future net revenues should be based on
current prices, with consideration of price changes only to the extent provided
by contractual arrangements, as of the latest balance sheet presented. The full
cost ceiling test must take into account the prices of qualifying cash flow
hedges in calculating the current price of the quantities of the future
production of oil and gas reserves covered by the hedges as of the balance sheet
date. In addition, the use of the hedge-adjusted price should be consistently
applied in all reporting periods and the effects of using cash flow hedges in
calculating the ceiling test, the portion of future oil and gas production being
hedged, and the dollar amount that would have been charged to income had the
effects of the cash flow hedges not been considered in calculating the ceiling
limitation should be disclosed. Any excess is charged to expense during the
period that the excess occurs. The Company did not have any hedging activities
during the two year period ended March 31, 2008. Application of the ceiling test
is required for quarterly reporting purposes, and any write-downs cannot be
reinstated even if the cost ceiling subsequently increases by year-end. Sales of
proved and unproved properties are accounted for as adjustments of capitalized
costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves of oil and gas, in which case the gain or loss is recognized in
income.Abandonment
of properties is accounted for as adjustments of capitalized costs with no loss
recognized.





Other Property, Plant and
Equipment





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





Comprehensive
Income





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




F-11





Net Earnings (Losses) Per
Common Share





The
Company computes earnings (losses) per share under Statement of Financial
Accounting Standards No. 128, "Earnings Per Share" (“SFAS 128”). Net earnings
(losses) per common share is computed by dividing net income (loss) by the
weighted average number of shares of common stock and dilutive common stock
equivalents outstanding during the year. Dilutive common stock equivalents
consist of shares issuable upon conversion of convertible notes payable and the
exercise of the Company's stock options and warrants (calculated using the
treasury stock method). During the year ended March 31, 2008 and 2007, common
stock equivalents are not considered in the calculation of the weighted average
number of common shares outstanding because they would be anti-dilutive, thereby
decreasing the net loss per common share.





Revenue
Recognition





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





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





Imbalances. When actual
natural gas sales volumes exceed delivered share of sales volumes, an
over-produced imbalance could occur. To the extent an over-produced imbalance
exceeds the remaining estimated proved natural gas reserves for a given
property, the Company would record a liability. At and during the years ended
March 31, 2008 and 2007, the Company had no imbalances.





Derivative and
Hedging





The
Company has also not entered into any derivative contracts for any purpose from
the period of inception through March 31, 2008.





Foreign Currency
Translation





The
Company translates the foreign currency financial statements in accordance with
the requirements of Statement of Financial Accounting Standards No. 52, “Foreign
Currency Translation.” Assets and liabilities of non-U.S. subsidiaries whose
functional currency is not the U.S. dollar are translated into U.S. dollars at
fiscal year-end exchange rates. Revenue and expense items are translated at
average exchange rates prevailing during the fiscal year. Translation
adjustments are included in Accumulated other comprehensive loss in the equity
section of the Consolidated Balance Sheet and totaled $(13,889) and
$(4,292) for the years ended March 31, 2008 and 2007, respectively, and foreign
currency transaction (losses)/gains are included in the
Consolidated Statement of Operations





Income
Taxes





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




F-12





Segment
Information





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




Stock Based
Compensation





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





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




Asset Retirement
Obligations




Our
financial statements reflect the provisions of Statement of Financial Accounting
Standards No. 143, Accounting for Asset Retirement Obligations. SFAS No.143
provides that, if the fair value for an asset retirement obligation can be
reasonably estimated, the liability should be recognized in the period when it
is incurred. Oil and gas producing companies incur this liability upon acquiring
or drilling a well. Under the method prescribed by SFAS No.143, the retirement
obligation is recorded as a liability at its estimated present value at the
asset’s inception, with an offsetting increase to producing properties on the
Consolidated Balance Sheet. Periodic accretion of discount of the estimated
liability is recorded as an expense in the Consolidated Statement of Operations.
The Company’s asset retirement obligations relate to the abandonment of oil
producing wells. The Company has recognized an asset retirement liability of
$88,209 and $41,552 at March 31, 2008 and 2007, respectively. It is estimated
that salvage values of well equipment will be equal, in aggregate, to the cost
of plugging and abandoning these wells at that point, and this estimate has been
taken into account in the calculation of accretion expense.




Long-Lived
Assets





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




F-13





Conditional
Asset Retirement Obligations.




In March
2005, the FASB issued FASB Interpretation (FIN) No. 47, “Accounting for
Conditional Asset Retirement Obligations, an interpretation of FASB Statement
No. 143”, which requires an entity to recognize a liability for the fair value
of a conditional asset retirement obligation when incurred if the liability's
fair value can be reasonably estimated. There was no impact of this
Interpretation on the Company’s consolidated financial position, results of
operations or cash flows since it currently does not have any conditional asset
retirement obligations outstanding at March 31, 2008 and 2007.





Employers’
Defined Benefit Pension and Other Postretirement Plans.





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





Certain Hybrid
Instruments.
On February 16, 2006 the FASB issued SFAS 155, “Accounting for Certain
Hybrid Instruments,” which amends SFAS 133, “Accounting for Derivative
Instruments and Hedging Activities,” and SFAS 140, “Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS 155
allows financial instruments that have embedded derivatives to be accounted for
as a whole (eliminating the need to bifurcate the derivative from its host) if
the holder elects to account for the whole instrument on a fair value basis.
SFAS 155 also clarifies and amends certain other provisions of SFAS 133 and SFAS
140. This statement is effective for all financial instruments acquired or
issued in fiscal years beginning after September 15, 2006. The Company had
no impact to the adoption of this new standard on its
consolidated financial position, results of operations or cash flows as it
currently does not have any hybrid instruments outstanding at March 31,
2008.





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





This
Statement:





1.
            Requires
      an entity to recognize a servicing asset or servicing liability each time
      it undertakes an obligation to service a financial asset by entering into
      a servicing contract in any of the following
  situations:




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





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





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





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





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





F-14




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




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




4.
            At
      its initial adoption, permits a one-time reclassification of
      available-for-sale securities to trading securities by entities with
      recognized servicing rights, without calling into question the treatment
      of other available-for-sale securities under Statement 115, provided that
      the available-for-sale securities are identified in some manner as
      offsetting the entity’s exposure to changes in fair value of servicing
      assets or servicing liabilities that a servicer elects to subsequently
      measure at fair value.





5.
            Requires
      separate presentation of servicing assets and servicing liabilities
      subsequently measured at fair value in the statement of financial position
      and additional disclosures for all separately recognized servicing assets
      and servicing liabilities.




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




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





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





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




F-15





New Accounting
Pronouncements Not Yet Adopted





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





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









To meet
those objectives, this Statement requires qualitative disclosures about
objectives and strategies for using derivatives, quantitative disclosures about
fair value amounts of and gains and losses on derivative instruments, and
disclosures about credit-risk-related contingent features in derivative
agreements.  This Statement shall be effective for financial
statements issued for fiscal years and interim periods beginning after November
15, 2008. Early application is encouraged.  This Statement encourages
but does not require disclosures for earlier periods presented for comparative
purposes at initial adoption. In years after initial adoption, this Statement
requires comparative disclosures only for periods subsequent to initial
adoption.  The adoption of SFAS 161 is not expected to have an impact
on the Company’s consolidated financial position, results of
operations or cash flows as the Company has not engaged in any derivative
instruments or hedging activities.





The Hierarchy of Generally Accepted
Accounting Principles.  In May 2008, the FASB issued SFAS No.
162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS
162”).  This Statement identifies the sources of accounting principles
and the framework for selecting the principles used in the preparation of
financial statements of nongovernmental entities that are presented in
conformity with generally accepted accounting principles (GAAP) in the United
States (the GAAP hierarchy).  This Statement shall be effective 60
days following the SEC’s approval of the Public Company Accounting Oversight
Board (PCAOB) amendments to AU Section 411, The Meaning of Present Fairly in
Conformity With Generally Accepted Accounting Principles.  An
entity that has and continues to follow an accounting treatment in category (c)
or category (d) as of March 15, 1992, need not change to an accounting treatment
in a higher category ((b) or (c)) if its effective date was before March 15,
1992.  For pronouncements whose effective date is after March 15,
1992, and for entities initially applying an accounting principle after March
15, 1992 (except for EITF consensus positions issued before March 16, 1992,
which become effective in the hierarchy for initial application of an accounting
principle after March 15, 1993), an entity shall follow this
Statement.  Any effect of applying the provisions of this Statement
shall be reported as a change in accounting principle in accordance with FASB
Statement No. 154, Accounting
Changes and Error Corrections. An entity shall follow the disclosure
requirements of that Statement, and additionally, disclose the accounting
principles that were used before and after the application of the provisions of
this Statement and the reason why applying this Statement resulted in a change
in accounting principle. The Company has not yet assesed the impact of this
Statment on its consolidated financial position, results of operations or cash
flows.





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





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




F-16





Fair Value Measurements. In
September 2006, the FASB issued SFAS 157, “Fair Value Measurements”, which
defines fair value, establishes a framework for measuring fair value in
generally accepted accounting principles (“GAAP”), and expands disclosures about
fair value measurements. Prior to this Statement, there were different
definitions of fair value and limited guidance for applying those definitions in
GAAP. This Statement provides the definition to increase consistency and
comparability in fair value measurements and for expanded disclosures about fair
value measurements. The Statement emphasizes that fair value is a market-based
measurement, not an entity-specific measurement. The Statement clarifies that
market participant assumptions include assumptions about risk, i.e. the risk
inherent in a particular valuation technique used to measure fair value and/or
the risk inherent in the inputs to the valuation technique. The Statement
expands disclosures about the use of fair vale to measure assets and liabilities
in interim and annual periods subsequent to initial recognition. The disclosures
focus on the inputs used to measure fair value and for recurring fair value
measurements using significant unobservable inputs, the effect of the
measurements on earnings for the period. The Statement is effective for
financial statements issued for fiscal years beginning after November 15, 2007,
and interim periods within those fiscal years. Earlier application is
encouraged, provided that the reporting entity has not yet issued financial
statements for that fiscal year, including the financial statements for an
interim period within that fiscal year. In November 2007, the FASB deferred the
implementation of SFAS 157 for non-financial assets and liabilities until
October 2008.  The Company does not expect adoption of this standard
will have a material impact on its consolidated financial position,
operations or cash flows.





The Fair Value Option for Financial
Assets and Financial Liabilities. In February 2007, the FASB issued SFAS
159, “The Fair Value Option for Financial Assets and Financial
Liabilities—including an amendment of FASB Statement No. 115”, permitting
entities to choose to measure many financial instruments and certain other items
at fair value. The objective is to improve financial reporting by providing
entities with the opportunity to mitigate volatility in reported earnings caused
by measuring related assets and liabilities differently without having to apply
complex hedge accounting measurement. The statement applies to all entities,
including not-for profit organizations. Most of the provisions of this Statement
apply only to entities that elect the fair value option. However, the amendment
to FASB Statement No. 115, “Accounting for Certain Investments in Debt and
Equity Securities”, applies to all entities with available-for-sale and trading
securities. The Company does not expect adoption of this standard will have a
material impact on its consolidated financial position, operations or cash
flows.





NOTE
3 - TRADE RECEIVABLES




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





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




Oil and Gas
Properties




Major
classes of oil and gas properties under the full cost method of accounting at
March 31, 2008 and 2007 consist of the following:





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





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




F-17





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




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




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




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




Acquisitions and
Dispositions




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




Other Property and
Equipment





Property
and equipment are stated at cost. When retired or otherwise disposed, the
related carrying value and accumulated depreciation are removed from the
respective accounts and the net difference less any amount realized from
disposition, is reflected in earnings. For financial statement purposes,
property and equipment are depreciated using the straight-line method over their
estimated useful lives of the assets. Maintenance, repairs, and minor renewals
are charged against earnings when incurred. Additions and major renewals are
capitalized. Major assets at March 31, 2008 and 2007 were as
follows:





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





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





Capitalized
Interest





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





NOTE
5 - NOTES PAYABLE





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





F-18





NOTE
6 - ASSET RETIREMENT OBLIGATION





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





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





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




NOTE 7 - INCOME
TAXES





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





At March
31, 2008 and 2007, the Company generated for federal income tax purposes a net
operating loss carry forward of approximately $13.8 million and $5.2 million
(which has been restated based on new estimates) respectively, both inclusive of
basis differences for net intangible drilling costs which are deductible for tax
purposes but capitalized and depreciated for book purposes. The latest expiry
date within the net operating loss carry forward at March 31, 2008 is in 2028,
and this loss can be used to offset future taxable income. However, a valuation
allowance of $5.1 million and $2.0 million (which has been restated based on new
estimates) was recorded for the years ended March 31, 2008 and 2007,
respectively on the total tax provision as the Company believes it is more
likely than not that the asset will not be utilized during the next year. Of the
total net operating loss carryforward, the United Kingdom (“UK”) total net
operating loss of approximately $1.0 million and $0.9 million for the years
ended March 31, 2008 and 2007, respectively, are not expected to be utilized.
The United States federal and state net operating loss carryforwards are
generally subject to limitations on their annual usage. Realization of the
deferred tax assets and net operating loss carryforwards is dependent, in part,
on generating sufficient taxable income prior to expiration of the loss
carryforwards. The amount of the deferred tax asset considered realizable,
however, might be adjusted if estimates of future taxable income during a future
period are expected.





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




March
      31,2008
            
            
            2007
              (Restated)CurrentUK
            
            $
            -
            
            
            $
            -US
            
            
            -
            
            
            
            -State
            
            
            -
            
            
            
            -Total
      current tax expense (benefit)
            
            
            -
            
            
            
            -DeferredUK
            
            
            (289,526
            )
            
            
            (253,659
            )US
            
            
            (4,143,281
            )
            
            
            (1,549,612
            )State
            
            
            (621,492
            )
            
            
            (232,442
            )Total
      deferred tax expense (benefit)
            
            
            (5,054,299
            )
            
            
            (2,035,713
            )Less
      valuation allowance
            
            
            5,054,299
            
            
            
            2,035,713Total
      deferred tax expense (benefit)
            
            $
            -
            
            
            $
            -Total
      tax provision-continuing operations
            
            $
            -
            
            
            $
            -





F-19





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




Components
of deferred tax amounts are as follows:





Deferred
      Tax Components
            
            March
      31,2008
            
            
            2007Deferred
      tax assetsRestricted
      stock compensation accrual
            
            $
            -
            
            
            $
            -Share
      issue basis difference
            
            
            -
            
            
            
            -Other
            
            
            -
            
            
            
            -Oil
      & Gas basis differences
            
            
            3,529,359
            
            
            
            1,013,912Depreciation
            
            
            512,673
            
            
            
            200,546Net
      operating loss carryforward
            
            
            2,284,516
            
            
            
            1,618,378Total
      gross deferred tax assets
            
            
            6,326,548
            
            
            
            2,832,836Deferred
      tax liabilitiesAmortization
      of share issue costs
            
            
            -
            
            
            
            -Other
            
            
            3,139
            
            
            
            2,386Foreign
      currency translation
            
            
            -
            
            
            
            -Oil
      & Gas basis differences
            
            
            -
            
            
            
            -Depreciation
            
            
            521,363
            
            
            
            144,735Stock
      Compensation
            
            
            747,747
            
            
            
            650,002Total
      gross deferred tax liabilities
            
            
            1,272,249
            
            
            
            797,123Less
      valuation allowance
            
            
            (5,054,299
            )
            
            
            (2,035,713
            )Net
      deferred tax assets
            
            $
            -
            
            
            $
            -




NOTE
8 - COMMITMENTS AND CONTINGENCIES





The
Company has various commitments to oil and gas exploration and production
capital expenditures related to its’ properties and projects in Kansas, Texas
and Louisiana, arising out of the normal course of business. The Company is
currently not involved in any litigation matters arising from our oil and gas
exploration and production activities, except as disclosed in Note 1, and as
such has accrued no liability with respect to litigation.




F-20




Lease
Commitments





The
Company does not have any capital lease commitments. The Company rents its main
operating office in Houston on a month-to-month basis. The Company also has a
month-to-month lease related to corporate housing for UK based officers while
periodically working at the corporate office.





Consulting
Agreements





The
Company has held consulting agreements with outside contractors, certain of whom
are also Company stockholders. The Agreements are generally for a fixed term
from inception and renewable from time to time unless either the Company or
Consultant terminates such engagement by written notice. See Note 13 for Related
Party Transactions.





Stockholder
Matters





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





Litigation





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





NOTE
9 - CAPITAL STOCK





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





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





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





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




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





On August
13, 2007, Mr. John G. Williams informed the Company that he was resigning from
his position as Executive Vice President Exploration and Production effective as
of November 1, 2007.  As such, 25,000 unvested shares of restricted
stock previously awarded to Mr. Williams in March 2007 were
forfeited.




F-21





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





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





During
the fiscal year ended March 31, 2007:





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





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





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





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





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





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





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




F-22





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





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





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





NOTE
10 - OPTIONS AND WARRANTS AND STOCK-BASED COMPENSATION





Warrants





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





Number
      of Shares
            
            
            Weighted
      Average Exercise Price Per ShareOutstanding
      and Exercisable at March 31, 2006
            
            
            1,092,676
            
            
            $
            0.13Granted
            
            
            -
            
            
            
            -Exchanged
            
            
            -
            
            
            
            -Exercised
            
            
            (124,593
            )
            
            
            0.14Canceled
      or expired
            
            
            -
            
            
            
            -Outstanding
      and Exercisable at March 31, 2007
            
            
            968,083
            
            
            $
            0.13Granted
            
            
            -
            
            
            
            -Exchanged
            
            
            -
            
            
            
            -Exercised
            
            
            (66,662
            )
            
            
            (0.14
            )Canceled
      or expired
            
            
            -
            
            
            
            -Outstanding
      and Exercisable at March 31, 2008
            
            
            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
            
            
            
            2.50
            
            
            $
            0.07
            
            
            
            138,655
            
            
            $
            0.07$
            0.14
            
            
            
            143,037
            
            
            
            2.50
            
            
            $
            0.14
            
            
            
            143,037
            
            
            $
            0.14$
            0.14
            
            
            
            253,961
            
            
            
            2.50
            
            
            $
            0.14
            
            
            
            253,961
            
            
            $
            0.14$
            0.14
            
            
            
            339,033
            
            
            
            2.50
            
            
            $
            0.14
            
            
            
            339,033
            
            
            $
            0.14$
            0.14
            
            
            
            26,735
            
            
            
            2.50
            
            
            $
            0.14
            
            
            
            26,735
            
            
            $
            0.14901,421
            
            
            
            2.50
            
            
            $
            0.13
            
            
            
            901,421
            
            
            $
            0.13





F-23





In June
2007, a total of 66,662 warrants were exercised at a price of $0.14 for a total
of $9,333 and a total of 66,662 shares of common stock, $0.001 par value, were
issued to an executive officer and director.





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




Stock
Options





The
following tables summarize the changes in options outstanding and exercised and
the related exercise prices for the shares of the Company's common stock issued
to certain directors and stockholders at March 31, 2008 and
2007:  (See Note 10).





Number
      of Shares
            
            
            Weighted
      Average Exercise Price Per ShareOutstanding
      at March 31, 2006
            
            
            4,577,526
            
            
            $
            0.35Granted
            
            
            500,000
            
            
            $
            1.42Exercised
            
            
            -
            
            
            
            -Canceled
      or expired
            
            
            -
            
            
            
            -Outstanding
      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
            
            
            $
            0.42




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
            
            
            
            2.81
            
            
            $
            0.35
            
            
            
            4,577,526
            
            
            $
            0.35$
            1.42
            
            
            
            250,000
            
            
            
            0.33
            
            
            $
            1.42
            
            
            
            250,000
            
            
            $
            1.42$
            0.83
            
            
            
            125,000
            
            
            
            4.47
            
            
            $
            0.83
            
            
            
            62,500
            
            
            $
            0.83$
            0.60
            
            
            
            100,000
            
            
            
            4.76
            
            
            $
            0.60
            
            
            
            50,000
            
            
            $
            0.60$
            0.51
            
            
            
            150,000
            
            
            
            4.82
            
            
            $
            0.51
            
            
            
            75,000
            
            
            $
            0.515,202,526
            
            
            
            2.82
            
            
            $
            0.42
            
            
            
            5,015,026
            
            
            $
            0.41




During
the year ended March 31, 2008, the Company issued stock options to purchase
175,000 shares of common stock to two employees, of which 87,500 options vested
on the date of the grant.  The Company also issued stock options to
purchase 200,000 shares of common stock for professional fees of which 100,000
vested on the date of the grant. All remaining options issued in fiscal year
ended March 31, 2008, vest 25% one year after grant and 25% two years after
grant.  In March 2007, stock options to purchase 500,000 shares of
common stock were awarded to John Williams, of which 250,000 options vested on
date of grant.




F-24





On August
13, 2007, Mr. John G. Williams informed the Company that he was resigning from
his position as Executive Vice President Exploration and Production effective as
of November 1, 2007.  As such, 250,000 unvested options previously
awarded to Mr. Williams in March 2007 were forfeited and the term of exercise
for the remaining 250,000 vested options is now approved by the Index Board to
end on July 31, 2008. This resulted in a revision in our previous estimate of
forfeiture rate for stock options with a corresponding reduction in compensation
expense of approximately $20,000 from grant date through September 30, 2007, net
of a correction to previously recorded compensation expense on this award of
approximately $8,000 during the quarter ended December 31, 2007.  No
other compensation expense for this award was recorded in the current
year.  In addition, total compensation expense related to the
forfeiture of this award of approximately $79,400 will no longer be
recorded.





Prior to
the reverse merger with Index Inc., Index Ltd. adopted a Stock Option Plan to
grant options to various officers, directors and others. As contemplated by the
Acquisition Agreements, following the completion of the acquisition the Board of
Directors of Index Inc. agreed to the adoption of the Stock Option Plan and
ratified it on March 14, 2006 effective as of January 20, 2006, providing for
the issuance of up to 5,225,000 shares of Common Stock of Index Inc. to
officers, directors, employees and consultants of Index Inc. and/or its
subsidiaries. Pursuant to the Stock Option Plan, Index Inc. allowed for the
issuance of options to purchase 4,577,526 shares of Common Stock at $0.35 per
share to newly appointed directors and officers of Index Inc. that had held
options to purchase ordinary shares of Index Ltd. prior to the completion of the
acquisition.





The
principal terms and conditions of the share options granted under the Share
Option Plan are that vesting of the options granted occurs in three stages: (1)
50% on grant; (2) 25% one year after grant; and (3) 25% two years after grant.
The 2006 options granted are exercisable at $0.35 per share. Furthermore, the
share options granted under the Share Option Plan are generally non-transferable
other than to a legal or beneficial holder of the options upon the option
holder’s death. The rights to vested but unexercised options cease to be
effective: (1) 18 months after death of the stock options holder; (2) 6 months
after Change of Control of Index Inc.; (3) 12 months after loss ofoffice due to health
related incapacity or redundancy; or (4) 12 months after the retirement of the
options holder from a position with Index Inc. All options have a 5 years
expiring term.





Total
stock based compensation expense was $302,911 and $875,092 for the year ended
March 31, 2008 and 2007, respectively.  Total stock based compensation
expense on unvested restricted stock and unvested stock options remaining at
March 31, 2008 is $90,824.





NOTE 11 - EARNINGS PER
SHARE




Basic
earnings per share is computed by dividing income available to common
stockholders by the weighted average number of shares outstanding for the
period. Diluted EPS reflects the potential dilution that could occur if
contracts to issue common stock and related stock options were exercised at the
end of the period. For the years ended March 31, 2008 and 2007, excluded from
diluted earnings per share are 901,421 and 968,083, respectively of warrants to
acquire common stock. As of both March 31, 2008 and 2007, there are 4,827,526 of
options to acquire the Company’s common stock that were excluded from the
computation of diluted earnings per share, and which excluded 375,000 of out of
the money options at March 31, 2008.





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





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




NOTE
12 - MAJOR CUSTOMERS




In the
2008 fiscal year ended March 31, 2008, approximately 28%, 25% and 17% of
revenues from the Company’s share of production were sold to three independent
crude oil and gas purchasers or operators, as allowed by our joint operating
agreements and for the 2007 fiscal year ended March 31, 2007, approximately 53%
and 47% of oil sales were sold to two independent crude oil
purchasers.





NOTE 13 - RELATED PARTY
TRANSACTIONS





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





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




F-25


INDEX
OIL AND GAS INC.


SUPPLEMENTAL
INFORMATION (UNAUDITED)


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





Oil
and Natural gas Producing Activities





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





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





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





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





Estimates
of proved developed and proved undeveloped reserves as of March 31, 2008,
2007 and 2006 were based on estimates made by Ancell Energy Consulting, Inc,
independent petroleum engineers. Our independent petroleum engineers, Ancell
Energy Consulting, Inc. are engaged by and provide their reports to our senior
management team. We make representations to the independent
petroleum engineers that we have provided all relevant operating data and
documents, and in turn, we review these reserve reports provided by the
independent petroleum engineers to ensure completeness and accuracy.
Our Senior Vice President, Exploration and Production, and Chief Executive
Officer make the final decision on booked proved reserves by incorporating the
proved reserves from the independent petroleum engineers’ reports.





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




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




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




•
            
            review
      by our Senior Vice President, Exploration and Production, of the
      independent petroleum engineers’ reserves reports for completion and
      accuracy.




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




F-26





Capitalized
Costs Relating to Oil and Gas Producing Activities





The
following table sets forth the capitalized costs relating to the Company’s
natural gas and crude oil producing activities at March 31, 2008, 2007 and
2006:




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




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





The
following table sets forth costs incurred related to the Company’s oil and
natural gas activities for the twelve months ended March 31, 2008, 2007 and
2006:





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





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




F-27





Continuing
              Operations
            
            
            Discontinued
              OperationsYear
      Ended March 31, 2006:
            
            $
            486,056
            
            
            $
            -Acquisition
      costs of propertiesProved
            
            $
            -
            
            
            $
            -Unproved
            
            
            -
            
            
            
            -Subtotal
            
            
            -
            
            
            
            -Exploration
      and development costs
            
            
            659,376
            
            
            
            -Total
            
            $
            1,145,432
            
            
            $
            -Year
      Ended March 31, 2007:Acquisition
      costs of propertiesProved
            
            $
            -
            
            
            $
            -Unproved
            
            
            355,641Subtotal
            
            
            355,641Exploration
      and development costs
            
            
            3,731,308Total
            
            $
            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
            
            
            $
            -




Results
of Operations for Oil and Natural Gas Producing Activities




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





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




F-28





Net
Proved and Proved Developed Reserve Summary





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




Continuing
              Operations
            
            
            Discontinued
              OperationsNatural
      gas (Bcf)(1):Net
      proved reserves at March 31, 2005
            
            
            -
            
            
            
            -Revisions
      of previous estimates
            
            
            -
            
            
            
            -Purchases
      in place
            
            
            0.144
            
            
            
            -Extensions,
      discoveries and other additions
            
            
            -
            
            
            
            -Sales
      in place
            
            
            -
            
            
            
            -Production
            
            
            -
            
            
            
            -Net
      proved reserves at March 31, 2006
            
            
            0.144
            
            
            
            -Revisions
      of previous estimates
            
            
            0.157
            
            
            
            -Purchases
      in place
            
            
            0.008
            
            
            
            -Extensions,
      discoveries and other additions
            
            
            0.240
            
            
            
            -Sales
      in place
            
            
            -
            
            
            
            -Production
            
            
            (0.008
            )
            
            
            -Net
      proved reserves at March 31, 2007
            
            
            0.541
            
            
            
            -Revisions
      of previous estimates
            
            
            (0.245
            )
            
            
            -Purchases
      in place
            
            
            0.084
            
            
            
            -Extensions,
      discoveries and other additions
            
            
            0.836
            
            
            
            -Sales
      in place
            
            
            -
            
            
            
            -Production
            
            
            (0.127
            )
            
            
            -Net
      proved reserves at March 31, 2008
            
            
            1.090
            
            
            
            -


Natural
      gas liquids and crude oil (MBbls)(2)(3):Net
      proved reserves at March 31, 2005
            
            
            20.591
            
            
            
            -Revisions
      of previous estimates
            
            
            1.566
            
            
            
            -Purchases
      in place
            
            
            11.565
            
            
            
            -Extensions,
      discoveries and other additions
            
            
            5.060
            
            
            
            -Sales
      in place
            
            
            -
            
            
            
            -Production
            
            
            (3.381
            )
            
            
            -Net
      proved reserves at March 31, 2006
            
            
            35.401
            
            
            
            -Revisions
      of previous estimates
            
            
            (5.349
            )
            
            
            -Purchases
      in place
            
            
            0.066
            
            
            
            -Extensions,
      discoveries and other additions
            
            
            0.875
            
            
            
            -Sales
      in place
            
            
            -
            
            
            
            -Production
            
            
            (6.660
            )
            
            
            -Net
      proved reserves at March 31, 2007
            
            
            24.333
            
            
            
            -Revisions
      of previous estimates
            
            
            (6.591
            )
            
            
            -Purchases
      in place
            
            
            0.005
            
            
            
            -Extensions,
      discoveries and other additions
            
            
            27.497
            
            
            
            -Sales
      in place
            
            
            -
            
            
            
            -Production
            
            
            (7.477
            )
            
            
            -Net
      proved reserves at March 31, 2008
            
            
            37.767
            
            
            
            -




F-29




(MBO)(2)
      equivalents(4):Net
      proved reserves at March 31, 2005
            
            
            20.591
            
            
            
            -Revisions
      of previous estimates
            
            
            1.566
            
            
            
            -Purchases
      in place
            
            
            35.635
            
            
            
            -Extensions,
      discoveries and other additions
            
            
            5.060
            
            
            
            -Sales
      in place
            
            
            -
            
            
            
            -Production
            
            
            (3.381
            )
            
            
            -Net
      proved reserves at March 31, 2006
            
            
            59.471
            
            
            
            -Revisions
      of previous estimates
            
            
            20.748
            
            
            
            -Purchases
      in place
            
            
            1.478
            
            
            
            -Extensions,
      discoveries and other additions
            
            
            40.956
            
            
            
            -Sales
      in place
            
            
            -
            
            
            
            -Production
            
            
            (8.075
            )
            
            
            -Net
      proved reserves at March 31, 2007
            
            
            114.578
            
            
            
            -Revisions
      of previous estimates
            
            
            (47.393
            )
            
            
            -Purchases
      in place
            
            
            14.050
            
            
            
            -Extensions,
      discoveries and other additions
            
            
            166.859
            
            
            
            -Sales
      in place
            
            
            -
            
            
            
            -Production
            
            
            (28.625
            )
            
            
            -Net
      proved reserves at March 31, 2008
            
            
            219.469
            
            
            
            -Net
      proved developed reserves:Natural
      gas (Bcf)(1)March
      31, 2006
            
            
            0.090
            
            
            
            -March
      31, 2007
            
            
            0.541
            
            
            
            -March
      31, 2008
            
            
            1.090
            
            
            
            -Natural
      gas liquids and crude oil (MBbls)(2)(3)March
      31, 2006
            
            
            28.942
            
            
            
            -March
      31, 2007
            
            
            22.953
            
            
            
            -March
      31, 2008
            
            
            36.677
            
            
            
            -MBO(2)
      equivalents(4)March
      31, 2006
            
            
            30.518
            
            
            
            -March
      31, 2007
            
            
            113.198
            
            
            
            -March
      31, 2008
            
            
            218.379
            
            
            
            -







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




(2)
            Thousand
      barrels.




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




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





F-30




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





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





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





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





The
following table sets forth the standardized measure of discounted future net
cash flows from projected production of the Company’s natural gas and crude oil
reserves for the years ended March 31, 2008, 2007 and 2006:





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


March 31,
      2007:Future
      cash inflows
            
            $
            5,049.821
            
            
            $
            -Future
      production costs
            
            
            (1,055.600
            )
            
            
            -Future
      development costs
            
            
            (53.403
            )
            
            
            -Future
      income taxes
            
            
            -
            
            
            
            -Future
      net cash flows
            
            
            3,940.818
            
            
            
            -Discount
      to present value at 10% annual rate
            
            
            (841.922
            )
            
            
            -Standardized
      measure of discounted future net cash flows relating to proved natural
      gas, natural gas liquids and crude oil reserves
            
            $
            3,098.896
            
            
            $
            -




F-31




Continuing
            
            
            DiscontinuedOperations
            
            
            OperationsMarch 31,
      2008:Future
      cash inflows
            
            $
            14,799.617
            
            
            $
            -Future
      production costs
            
            
            (2,733.919
            )
            
            
            -Future
      development costs
            
            
            (86.499
            )
            
            
            -Future
      income taxes
            
            
            -
            
            
            
            -Future
      net cash flows
            
            
            11,979.199
            
            
            
            -Discount
      to present value at 10% annual rate
            
            
            (2,007.956
            )
            
            
            -Standardized
      measure of discounted future net cash flows relating to proved natural
      gas, natural gas liquids and crude oil reserves
            
            $
            9,971.243
            
            
            $
            -





Changes
in Standardized Measure of Discounted Future Net Cash Flows





The
following table sets forth the changes in the standardized measure of discounted
future net cash flows at March 31, 2008, 2007 and 2006:





Continuing
            
            
            DiscontinuedOperations
            
            
            Operations(in
      $’000)Balance,
      April 1, 2005
            
            $
            351.775
            
            
            $
            -Sales
      and transfers of natural gas, natural gas liquids and crude oil produced,
      net of production costs
            
            
            (149.200
            )
            
            
            -Net
      changes in prices and production costs
            
            
            92.288
            
            
            
            -Extensions,
      discoveries, additions and improved recovery, net of related
      costs
            
            
            86.546
            
            
            
            -Development
      costs incurred
            
            
            659.376
            
            
            
            -Revisions
      of previous quantity estimates and development costs
            
            
            (412.504
            )
            
            
            -Accretion
      of discount
            
            
            (97.672
            )
            
            
            -Net
      change in income taxes
            
            
            -
            
            
            
            -Purchases
      of reserves in place
            
            
            813.430
            
            
            
            -Sales
      of reserves in place
            
            
            -
            
            
            
            -Changes
      in timing and other
            
            
            3.194
            
            
            
            -Balance,
      March 31, 2006
            
            $
            1,347.233
            
            
            $
            -Sales
      and transfers of natural gas, natural gas liquids and crude oil produced,
      net of production costs
            
            $
            (342.311
            )
            
            $
            -Net
      changes in prices and production costs
            
            
            (46.758
            )
            
            
            -Extensions,
      discoveries, additions and improved recovery, net of related
      costs
            
            
            1,180.549
            
            
            
            -Development
      costs incurred
            
            
            1,320.745
            
            
            
            -Revisions
      of previous quantity estimates and development costs
            
            
            (820.626
            )
            
            
            -Accretion
      of discount
            
            
            134.723
            
            
            
            -Net
      change in income taxes
            
            
            -
            
            
            
            -Purchases
      of reserves in place
            
            
            486.467
            
            
            
            -Sales
      of reserves in place
            
            
            -
            
            
            
            -Changes
      in timing and other
            
            
            (161.126
            )
            
            
            -Balance,
      March 31, 2007
            
            $
            3,098.896
            
            
            $
            -Sales
      and transfers of natural gas, natural gas liquids and crude oil produced,
      net of production costs
            
            $
            (1,402.119
            )
            
            $
            -Net
      changes in prices and production costs
            
            
            1,138.995
            
            
            
            -Extensions,
      discoveries, additions and improved recovery, net of related
      costs
            
            
            8,082.075
            
            
            
            -Development
      costs incurred
            
            
            -
            
            
            
            -Revisions
      of previous quantity estimates and development costs
            
            
            (1,910.908
            )
            
            
            -Accretion
      of discount
            
            
            309.890
            
            
            
            -Net
      change in income taxes
            
            
            -
            
            
            
            -Purchases
      of reserves in place
            
            
            592.974
            
            
            
            -Sales
      of reserves in place
            
            
            -
            
            
            
            -Changes
      in timing and other
            
            
            61.440
            
            
            
            -Balance,
      March 31, 2008
            
            $
            9,971.243
            
            
            $
            -




F-32




Exhibit
Index







Exhibit
              Number
            
            Description3(i)(1)1
            
            Articles
      of Incorporation of Index Oil and Gas Inc., Inc. (4)3(i)(2)
            
            Certificate
      of Amendment to the Articles of Incorporation of Index Oil and Gas Inc.
      (the “Company”), filed with the Secretary of the State of Nevada on
      November 30, 2005, changing the name of the Company from Thai One On Inc.
      to Index Oil and Gas Inc., Inc., and increasing the number of authorized
      shares from 25,000,000 to 75,000,000. (1)3(i)(2)
            
            Certificate
      of Amendment to the Articles of Incorporation of Index Oil and Gas Inc.
      (the “Company”), filed with the Secretary of the State of Nevada on
      September 21, 2006, increasing the number of authorized shares from
      75,000,000 to 500,000,000, and creating a class of preferred stock,
      authorizing the issuance of 10,000,000 shares, $0.001 par value per share,
      of preferred stock. (7)3(ii)
            
            Bylaws
      of Index Oil and Gas Inc. (4)10.1
            
            Acquisition
      Agreement between Index Oil and Gas Inc., certain stockholders of Index
      Oil & Gas Ltd, and Briner Group Inc. dated January 20, 2006.
      (1)10.2
            
            Form
      of Share and Warrant Exchange Agreement entered into by and between Index
      Oil and Gas Inc., Inc. and certain Index Oil & Gas Ltd stockholders.
      (1)10.3+
            
            Employment
      Agreement entered into by and between Index Oil & Gas Ltd and Lyndon
      West, dated January 20, 2006. (1)10.4+
            
            Employment
      Agreement entered into by and between Index Oil & Gas Ltd and Andy
      Boetius, dated January 20, 2006. (1)10.5+
            
            Employment
      Agreement entered into by and between Index Oil & Gas Ltd and Daniel
      Murphy, dated January 20, 2006. (1)10.6+
            
            Letter
      Agreement entered into by and between Index Oil & Gas Ltd and David
      Jenkins, dated January 20, 2006. (1)10.7+
            
            Letter
      Agreement entered into by and between Index Oil & Gas Ltd and Michael
      Scrutton, dated January 20, 2006. (1)10.8+
            
            Employment
      Agreement entered into by and between Index Oil and Gas Inc. and John G.
      Williams, dated August 29, 2006. (5)10.9
            
            Form
      of Subscription Agreement dated as of January 20, 2006.
  (1)10.10
            
            Form
      of Subscription Agreement dated as of August 29 and October 4, 2006.
      (6)10.11
            
            Form
      of Registration Rights Agreement dated as of August 29, 2006.
      (6)10.12+
            
            Index
      Oil and Gas Inc. 2006 Incentive Stock Option Plan. (9)10.13
            
            Securities
      Purchase Agreement dated as of November 5, 2007. (10)10.14
            
            Form
      of Warrant to Purchase Common Stock.
(10)









14.1
            
            Code
      of Ethics and Business Conduct for officers, directors and employees of
      Index Oil and Gas Inc. adopted by the Company’s Board of Directors on
      March 31, 2006. (3)21.1
            
            List
      of subsidiaries of the Company. *23.1
            
            Consent
      of RBSM LLP. *23.2
            
            Consent
      of Ancell Energy Consulting, Inc. *31.1
            
            Certification
      by Chief Executive Officer required by Rule 13a-14(a) or Rule 15d-14(a) of
      the Exchange Act. *31.2
            
            Certification
      by Chief Financial Officer required by Rule 13a-14(a) or Rule 15d-14(a) of
      the Exchange Act. *32.1
            
            Certification
      by Chief Executive Officer required by Rule 13a-14(b) or Rule 15d-14(b) of
      the Exchange Act and Section 1350 of Chapter 63 of Title 18 of the United
      States Code. *32.2
            
            Certification
      by Chief Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) of
      the Exchange Act and Section 1350 of Chapter 63 of Title 18 of the United
      States Code. *





*
      Filed Herewith+
      Compensatory plan or arrangement(1)
      Incorporated by reference to the Company’s Amended Current Report filed on
      Form 8-K/A with the SEC on March 15, 2006.(2)
      Incorporated by reference to the Company’s Annual Report filed on Form
      10-K with the SEC on July 17, 2006.(3)
      Incorporated by reference to the Company’s Annual Report filed on Form
      10-KSB with the SEC on April 10, 2006.(4)
      Incorporated by reference to the Company’s Registration Statement filed on
      Form SB-2 with the SEC on May 24, 2004.(5)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on September 8, 2006.(6)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on September 11, 2006.(7)
      Incorporated by reference to the Company’s Current Report filed on Form
      8-K with the SEC on September 28, 2006.(8)
      Incorporated by reference to the Company’s Registration Statement filed on
      Form SB-2 with the SEC on October 11, 2006.(9)
      Incorporated by reference to the Company’s Registration Statement filed on
      Form S-8 with the SEC on October 3, 2007.(10)
      Incorporated by reference to the Company’s Current Report filed n Form 8-K
      with the SEC on February 29, 2008.