Horn Indago Petroleum Report 201005 - Final

8/19/2019 Horn Indago Petroleum Report 201005 - Final

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INDAGO PETROLEUMR ESEARCH & A NALYSIS, OCTOBER 2005


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T H E C O M P A N Y• Indago Petroleum (Indago) is a new company that intends to list on AiM in November 2005.

• Indago was formed through a management buy-out of the United Arab Emirates (UAE) and Omani assets of NovusPetroleum (Novus), an oil company previously listed on the ASX. Novus was acquired by PT Medco Energi (Medco),the Indonesian oil company, in a hostile take-over in 2004.

• The acquisition of Indago was financed by Meridian Capital which owns 69% of the company. Crosby Capital and themanagement team respectively own 21% and 10% of the company.

T H E M A N A G E M E N T• The management of Indago have been in place for over 9 years and have built an attractive exploration portfolio using

their strengths in field mapping and integration.

• Indago's management have established a reputation in the region as a competent partner through their operatorshipof the offshore Bukha gas and condensate field (Block 8, Oman). In addition, in the same block, they have taken the WestBukha well through appraisal to development phase.

A S S E T P O RT F O L I O• Indago have focused on developing an understanding of the fold-belt fairway of the Northern Arabia Peninsula, in Oman

and the UAE. They have integrated surface geology with improved seismic imaging to generate a suite of attractiveexploration prospects. All reservoir targets have established analogous regional producers.

• Indago has developed a mature prospect inventory with Hagil and Ash Sham in the UAE (Onshore RAK); Jebel Hafit(Block 31), and Adam and Izz (Block 47) in Oman.

• There are also several follow-up leads in each of the blocks to enable Indago to build on any exploration success in thecurrent drillable prospects. Indago also has a number of opportunities in the region which may enable it to grow the

portfolio further in the event of exploration success.

W O R K P R O G R A M• Indago is expected to raise up to US$ 120 million (m) at its IPO to be applied to debt repayment, project development,

the drilling of 5 wells, exploration and the finalisation of new projects.

• The US$ 60 m West Bukha development well is underway. The US$ 16.7 m Hagil well spudded at the start of October 2005.Thereafter, Indago expects to spud a US$ 11.4 m well at Adam in May 2006, followed by a US$ 24.8 m well at Jebel Hafitin September/October 2006. A US$ 10.2 m well at Izz will be spudded either before or after drilling starts at Hafit,with a US$ 5.4 m well at Ash Sham scheduled for August 2006.

VA L U AT I O N• With a target reserve base of 1.93 billion (bn) barrel of oil equivalent (boe), with a gross adjusted probability value

of US$ 1.6 bn, Indago has a range of high impact exploration opportunities.

• The estimated unrisked recoverable Gas Initially In Place (GIIP) of the Prospect portfolio is 6.2 trillion cubic feet of gas(Tcf) gas. Using a 1 in 5 probability, and a fixed gas price of US$ 1.20 and US$ 1.40/MMbtu for the Oman and theUAE respectively, the value is approximately US$ 403 m.

• The estimated unrisked Condensate Initially In Place (CIIP) plus LPG volume from the current prospect inventoryis 789 MMboe. 82% of condensate potential is contained with two prospects, Jebel Hafit and Hafit. On a risked basisat a West Texas Intermediate (WTI) oil price equivalent of US$ 30/bbl, the value of this condensate portfoliois approximately US$ 1.2 bn.

• The expected volume from the current lead inventory is 212 Bcf gas and 4.7 MMboe condensate plus LPG. Using a 1 in 20probability at the fixed gas prices noted above and a WTI of US$ 30/bbl, the value of the gas, condensate and LPG Leadportfolio is approximately US$ 7.4 m. This valuation only reflects those leads valued by Petrenel, the technical consultant.In addition, Indago’s management have developed a portfolio of leads to which no value has as yet been attributed

• Adjusting for possible back-in's, a 30% weighting of the calculated value of Jebel Hafit and Hagil, and a deductionof 25% from the adjusted value for various risk factors; within a WTI price range of US$ 30/bbl to US$ 54/bbl, an indicativevaluation for Indago is between US$ 427 m to US$ 701 m.

E X E C U T I V E S U M M A R Y

Indago Petroleum would like to thank NASA for providing the cover image for this Report.


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1 I ND AG O P ETROLEUM

THE COMPANY 2

OVERVIEW 2

STRATEGY 4

NON-EXECUTIVE DIRECTORS 5

EXECUTIVE DIRECTORS 7

OPERATING STRUCTURE 8

CORPORATE GOVERNANCE 10

THE U NITED ARAB EMIRATES AND OMAN 12

R EGIONAL E NERGY SUPPLY AND DEMAND 16

ASSET PROFILE 18

PRODUCTION 22

DEVELOPMENT 24

PROSPECTS 26

LEADS 32OPPORTUNITY 38

WORK SCOPE & FINANCING 40

R ISKS 44

FINANCIAL A NALYSIS 48

VALUATION 54

GLOSSARY 62

APPENDIX 1: OVERVIEW OF THE E NERGY SECTOR 64

R ATINGS SYSTEM & CERTIFICATION 69

R ESEARCH DISCLOSURES 70

DISCLAIMER 71

C O N T E N T S


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T H E C O M P A N Y

2MIRABAUD SECURITIES, M. HOR N & CO.

OVERVIEW

Indago Petroleum (Indago) intends to list on the London AiM market

in November 2005.

Indago is a focused oil and gas Exploration and Production (E&P)

company with a portfolio of opportunities, which vary in risk and maturity.

Indago was formed through a management buy-out of the United Arab

Emirates (UAE) and Sultanate of Oman (Oman) assets of NovusPetroleum (Novus).

Novus was acquired by PT Medco Energi (Medco), the Indonesian oil

company, in a hostile take-over in 2004.

The buy-out of the assets of Indago was financed by Meridian Capital

which on a pre-money basis owns 69% of the company. Silk Route

Petroleum, a company controlled by Crosby Capital, and the management

currently own 21% and 10% of the company respectively.

Indago is the 100% owner of subsidiary companies Indago Technical

Services Ltd, Indago Oman Ltd (IOL) and Indago Al Khaleej Ltd (IAK).

These companies hold its interests in a producing gas-condensate field

(Bukha), and an approved gas-condensate development (West Bukha),

which is expected to come in stream in late 2007. Both of these assets are

located off the Musandam Peninsula in Omani waters.

In addition, Indago has 5 drillable prospects (Jebel Hafit, Block 31; Hagil

and Ash Sham, Ras Al Khaimah; Adam and Izz, Block 47) and plans to drill

5 exploration wells prior to 2007.

Indago is an active explorer and in addition to its portfolio of Prospects,

it has several Leads in different stages of development.

The company is also actively evaluating a number of new venture

opportunities.


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Source: Indago Petroleum


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STRATEGY

Indago aims to become a leading producer of natural gas in Oman and the

UAE in order to satisfy a significant forecast regional supply/demand

imbalance.

This objective will be achieved through:

• Development of existing fields

• Exploration in existing licenses held by the company

• Acquisition of related acreage and existing undeveloped discoveries.

Indago has a significant amount of license acreage in the UAE and Oman,

and is strategically well placed with strong political and working

relationships in the region.

COMPANY STRUCTURE


Silk RoutePetroleum Ltd

Indago Petroleum Ltd

Indago OmanBlock 30 Ltd

OmanBlock 30

RAKOnshore

OmanBlock 17

OmanBlock 31

AtlantisHeritage

PetroleumLG

HeritagePetroleum

OmanBlock 47

OmanBlock 8

Indago Al Khaleej Ltd

Indago TechnicalServices Ltd

IndagoOman Ltd

21%

100% 100%

100% 100% 100%40%

10%50% 10%50%

100% 40%

100% 100%

69% 10%

MeridianMiddle East Inv. Ltd

Management

BVI

Cayman Islands

Guernsey

Bermuda

Petroleum Concession Incl. Indago Interest

Non Indago Companies


T H E C O M P A N Y


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NON-EXECUTIVE DIRECTORS

The Rt. Hon. Tim EggarCHAIRMAN, NON-EXECUTIVE

The Rt. Hon. Tim Eggar Chairman, Non-Executive. Mr. Eggar worked

at Hambros Bank before spending 8 years with European Banking

Company. In 1979, he was elected to the UK parliament. From 1985,

he served in several UK ministerial positions and ultimately was Minister

for Industry and Energy from 1992 to 1996. Since leaving government,he has served as a director of a number of companies, including Chairman

of MW Kellogg Limited and of Agip UK Limited. He was Chief Executive

Officer of Monument Oil and Gas plc. From 2000 to 2004, Mr. Eggar was

Global Head of ABN AMRO's Global Energy Corporate Finance Group

and, most recently, Chairman of UK Client Coverage. Mr. Eggar

is currently a Non-Executive Director of Anglo Asian Mining and Expro

Group International. He is President of the Russo-British Chamber

of Commerce. He was the Chairman of the Anglo-Azeri Society.

Barry GoldbergDIRECTOR

Mr Goldberg is a principal of Genuity Capital Markets. Mr. Goldberg has

extensive public company advisory experience. Prior to joining Genuity

Capital Markets, from 1998 to 2005 Mr. Goldberg was a Managing Director

at BMO Nesbitt Burns where he was the Head of Restructuring. From

1996 to 1998, Mr. Goldberg was a partner at the law firm Heenan Blaikie.

From 1990 to 1996 he was a partner at the law firm Osler Hoskin and

Harcourt. Mr. Goldberg has an undergraduate degree, a Bachelor of Civil

Law, and a Bachelor of Common Law from McGill University.

He is a member of the Ontario Bar.

Rod PerryDIRECTOR

Mr Perry is global head of Venture Capital for 3i plc. He is a member of the

board of 3i Group plc and a member of both the Executive Committee and

the Investment Committee. Between 1997 and 2001, Rod was responsible

for the 3i investment business in Asia Pacific. Rod has a B.Sc. in Physics

and is a member of the Institution of Electrical Engineers.


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Paul Alexander Marchand DIRECTOR

Mr. Marchand is General Counsel of Meridian Securities (UK) Limited.

Mr. Marchand was formerly a partner of White & Case LLP,

an international law firm. Prior to joining White & Case LLP, Mr. Marchand

was a solicitor at Linklaters, an international law firm. Mr. Marchand

is a member of the Law Society of England and Wales and holds

a Bachelor of Civil Law degree from the University of Oxford (Corpus

Christi College), an LL.B from the University of Stellenbosch and

a Bachelor of Commerce and Masters in Taxation Laws from the

University of the Witwatersrand.

Dr Robert Charles WilliamsDIRECTOR

Dr. Williams has degrees in geology from the Universities of Manchester

and Cambridge, England. He joined British Petroleum plc in early 1976,

where he worked in their international staff. In 1987 he became General

Manager and a Director of Oil Search Limited. In 1994, Dr. Williams

formed and led the team that created Novus Petroleum Limited, Australia's

largest IPO of an upstream oil and gas company. Dr. Williams was also the

Non-Executive Chairman of Nido Petroleum Limited. Dr. Williams became

a Fellow of the Australian Institute of Company Directors and is also

a Fellow of the Geological Society. He has served on a number of industry

committees in various countries. He is a member of the Advisory Board

of the Energy and Geoscience Institute, a division of the University of Utah

affiliated with Imperial College, London.

Dr. David Lawson Bremner DIRECTOR

Dr. Bremner joined British Petroleum plc in 1977, where he worked in their

international staff in London, Aberdeen, Alaska and San Francisco.

He resigned from BP in 1984 to become Exploration Manager of Merlin

Petroleum, a small start-up exploration company, based in San Francisco.

After the sale of Merlin Petroleum in 1989 and a successful role

in international petroleum consultancy, in 1995 he joined Monument Oil and

Gas plc, based in London, as Exploration Manager. In 1997, Dr. Bremner

was appointed Exploration Director for Monument, a role which he held until

that company was sold in 1999. Since that time Dr Bremner has been

engaged in international petroleum consultancy with a particular emphasis

on new business development and has been active in exploration

consultancy in the domestic United States. Dr. Bremner holds an honours

degree and a Ph.D. in geology from the University of Glasgow, Scotland.

T H E C O M P A N Y


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EXECUTIVE DIRECTORS

Peter Sadler CHIEF EXECUTIVE OFFICER

Mr. Sadler is a graduate of Oxford University and London Imperial College.

He commenced work with Schlumberger in 1978 and after obtaining his

MSc, he joined Unocal as a petroleum engineer. Prior to being appointed

as the Head of Engineering in 1996 by Novus (the forerunner of Indago),

Mr. Sadler worked with companies such as Texas Eastern, Exxon,Fletcher Challenge, Agip and Shell. In 2000 he was appointed by Novus

as Regional Manager Middle East. Mr. Sadler also sat on the Executive

Committee of Novus.

John HurstEXPLORATION DIRECTOR

Mr. Hurst obtained a B.Sc in geology from Hull University and a D. Phil and

D.Sc in geology from Oxford University. In 1976 he joined the Greenland

Survey mapping and exploration teams in Copenhagen. In 1983 he joined

British Petroleum in London and was initially involved in regionalexploration projects. He subsequently became Manager of the Basin

Studies Group. He resigned from BP in 1992 and joined Total in Paris

as Exploration and Production Adviser in carbonate petroleum systems

to the Exploration Manager. In 1996 he joined Novus as a roving

Exploration Consultant. He has managed since 1999 Novus' (and now

Indago's) Middle East exploration group.


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OPERATING STRUCTURE

Peter Sadler and John Hurst are based in Dubai and are responsible for

the day to day operations of Indago.

Indago employs 6 senior staff and several contractors.

Indago Oman Limited on behalf of the Bukha Joint Venture Partners

operates the offshore facilities.

A Production Operations Manager, 3 technicians and an office assistant,

all based in Ras Al Khaimah, are responsible for the day-to-day activities.

A Petroleum Engineer located in the Muscat office is responsible for

reservoir and production monitoring.

General management is provided by Indago's Dubai Office.

T H E C O M P A N Y


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I NDAGO PETROLEUM ORGANISATIONAL STRUCTURE (SEPT 2005)


Peter Sadler Chief Executive Officer

John HurstExploration Director

Miguel SotoChief Financial Officer

(acting)

Shelley WatsonCommercial Manager

Appointed*WB Dev. Project Man.

Jamie ParryRegional Ops Manager

Abduljalil Al FarsiOps ManagerOnshore Oman

Paula Pedler Snr Petroleum Engineer

David Moore*Drilling Manager

Steve Hendry*Snr Drilling Engineer

Ben Hennessy*Snr Drilling Supervisor

Morris Ferris*Snr Completions

& Welltest Engineer

Maria FernandezDrilling Sec

Gary Morrison*Materials/Logistics

Supervisor

John BrownOps Geologist

AppointedSnr Geophysicist

Thomas Lagler Technical Assistant

Lois KapeGeologist

Salim Al Salmi Accounts Administrator

Laith Albehacee Accounts Admin & PRO

Azhar Ahsan Accounts Administrator

Daniela GarradSnr Geophysicist

Mick McNaneyProduction Manager

Gracia ValladianExecutive Secretary& Office Co-ordinator

Joseph YueOffice Assistant

Ramsey CabunocOps & Maint Tech

Manuel Del RosarioOps & Maint Tech

Hamid Al HajriOps & Maint Tech

Halima Al Balushi Admin Secretary

Khaled Al HashmiPRO

Jacob PhilipOffice Assistant

Employees: 26*Contractors: 6


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CORPORATE GOVERNANCE

BOARD GOVERNANCE

AUDIT C OMMITTEE

The Audit Committee will be chaired by Barry Goldberg. The Audit

Committee will be responsible for monitoring the quality of internal controls

and for ensuring that the financial performance of the Company is properly

monitored, controlled and reported on.

R EMUNERATION C OMMITTEE

The Remuneration Committee will be chaired by Tim Eggar. The

Remuneration will review the performance of the executive Directors and

set the scale and structure of their remuneration and the basis of their

service agreements with due regard to the interests of Shareholders.

N OMINATION C OMMITTEE

The Nomination Committee will be chaired by Tim Eggar. The Nomination

Committee will be responsible for reviewing the structure, size and

composition of the Board, preparing a description of the role, capabilities

required for a particular appointment, identifying and nominating

candidates to fill Board positions, as and when they arise.

T H E C O M P A N Y


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HEALTH, SAFETY AND THE ENVIRONMENT

Indago has inherited safety attitudes and operational documentation from

its original Australian parent. Prudent operating practices along with

fit-for-purpose, current oil spill contingency plans and environmental

assessments will continue to be implemented in excess of existing

government requirements. These procedures will be updated to reflect

changing operational needs and industry practice.

In addition, following Admission, the Company intends to adopt practices

to comply, so far as practicable and appropriate for a company of its size,with the main provisions of the Combined Code.

The Company has adopted a share dealing code, based on the Model

Code for Directors and relevant employees in accordance with the AIM

Rules and will take proper steps to ensure compliance by the Directors

and those employees.

CONTRACTING AND PROCUREMENT

In Oman there is an oversight committee with the Ministry of Oil and Gas

(MOG) which requires a tender exercise for all contract awards over

US$100,000.

Following a pre-qualification phase, separate, sealed technical and

commercial bids are sought and subsequently assessed by the

committee. An evaluation is made by the operator and submitted for

approval to the MOG.

This process provides good transparency and accountability. The

committee has been flexible when confronted with logical justification.

A similar internal procedure is carried out in jurisdictions which do not have

prescribed government controls.


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U NITED ARAB EMIRATES

POLITICAL STRUCTURE

The UAE is a federation of seven emirates - Abu Dhabi, Dubai, Sharjah,

Ajman, Fujairah, Ras Al-Khaimah and Umm Al-Quwain. Political power

is concentrated in Abu Dhabi, which controls the vast majority of the UAE's

economic and resource wealth. The two largest emirates - Abu Dhabi and

Dubai - provide over 80% of the UAE's income.

There is a high level of political and economic autonomy within the

individual emirates. Each emirate has its own ruler, controls its own natural

resources and regulates much of its own commercial activity. The rulers

of the emirates each serve as members of the Federal Supreme Council

of the UAE incorporating both legislative and executive powers.

The Council ratifies federal laws and decrees, and plans general policy.

The Council of Ministers or Cabinet is described in the Constitution as "the

executive authority" of the federation is headed by the Prime Minister who

is chosen by the President in consultation with his colleagues on the

Supreme Council. In June 1996, the UAE's Federal National Council

approved a permanent constitution for the country.

The current head of state, Sheikh Khalifa bin Zayed Al-Nahyan, took office

in November 2004, following the death of his father Sheikh Zayed bin

Sultan Al-Nahyan.

T H E U N I T E D A R A B E M I R AT E S A N D O M A N

The United Arab Emirates (UAE)

and The Sultanate of Oman

(Oman), enjoy a reputation for

peace, prosperity and economic

development. Unlike many of

the nations in the region,

political risk and major

acts of terrorism have been

non-existent for decades.


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ECONOMY

The overall performance of the UAE's economy is heavily dependent

on oil exports, which account for over 30% of total gross domestic product

(GDP). Growth in real GDP was 6.4% in 2004, partially due to higher crude

oil prices. For 2005, real GDP growth is projected to reach 6.5 %. The

non-oil segment of the UAE's economy also is experiencing strong growth,

particularly the petrochemicals and financial services sectors.

The UAE is the 3rd largest economy in the Middle East with GDP of US$

85.5 bn in 2004. The UAE's GDP has risen by 55% over the past 5 years,giving a growth rate of 10.9% per annum. The UAE has the highest per

capita income after Qatar in the Arab world largely due to its oil and gas

reserves. Since the early 1970's, the UAE has transformed itself into

a highly prosperous economy.

The UAE is mid-way through a 20 year economic diversification plan away

from primary oil production. Currently, there are several major projects

underway throughout the Emirates in various sectors including refinery

and petrochemicals, tourism, aviation and airports, re-export commerce,

and telecommunications.


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OMAN

POLITICAL STRUCTURE

Oman has been ruled by Sultan Qaboos bin Said Al Busaidi since 1970,

when he deposed his father in a bloodless coup. All power is concentrated

in the hands of the Sultan, who also holds the top positions in the finance,

defence, and foreign affairs ministries.

Rules governing the succession to the throne were formalized in the 1996

Basic Law. There is no Omani legislative assembly, though there are two

consultative bodies called the Majlis Al-Dawla and the Majlis Al-Shura.

Together, the two chambers form the Council of Oman. The Majlis

Al-Dawla is appointed, while the Majlis Al-Shura is elected. The last

election was held in October 2003.

Constitutional reforms in Oman have been part of the ongoing process

of modernisation. The Basic Statute of the State, announced in November

1996, deals with every aspect of State legislation and human rights.

It guarantees equality of all citizens before the law, freedom of religion,

freedom of speech, the free press, the right to a fair trial and the right

to form nationally based associations. It lays down the framework for all future legislation and provides for the succession. The Basic Statute

also barred ministers from holding interests in companies doing business

with the government.

T H E U N I T E D A R A B E M I R AT E S A N D O M A N


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ECONOMY

Oman's macroeconomic environment currently is strong, despite recent

declines in oil production. Real GDP growth was 3.3% in 2004 and

is projected to rise to 3.5% in 2005. Inflation was only 0.8% for 2004.

Oman is heavily dependent on oil revenues, which account for around

75% of the country's export earnings and almost 40% of its GDP.

Due to the maturation of its oil fields and the volatility of oil prices, the

Omani government has made diversifying the country's economy a toppolicy priority. In the 1980s, this effort hinged on developing a domestic

manufacturing base, but more recent initiatives have focused on the

exploitation of Oman's other natural resources, particularly its natural

gas reserves.

Oman has large mineral and metal deposits, including silica, dolomite,

copper and gold. In September 2003, the government announced that

it was reviving a five-year-old plan to build a US$ 2.5 bn aluminium

smelter, which is to begin operation in 2007.

Oman's efforts to diversify the economy also include "Omanization",

a program designed to increase the percentage of Omani citizens working

in the private sector. At present, Omani nationals constitute only 10%

of private sector employment.

The government also has continued to attempt to attract foreign

investment, particularly in light industry, tourism, and electric power

generation. Foreign investment incentives include a 5-year tax holiday for

companies in certain industries, an income tax reduction for publicly held

companies with at least 51% Omani ownership, and soft loans to finance

new and existing projects. The process of privatizing some state-owned

industries is to be accelerated under a decree issues in July 2004, which

will allow foreign ownership up to 100% in power generation and water.

Oman became a member of the World Trade Organization (WTO)

in October 2000. Movement continues towards an eventual customs union

amongst the Gulf Co-operation Council (GCC) states.


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The key factors governing the growth of natural gas demand in the region are:

• Increased use of natural gas for re-injection to boost declining

oilfield production.

• Numerous gas-export related industries such as LNG schemes and

petrochemical plants are now competing with domestic natural gas

requirements. In particular growth in LNG demand on the Indian

subcontinent is expected to underpin new gas export schemes.

• Substitution of natural gas for existing diesel-fired operations allows

a greater proportion of refined products to be freed up for export.

• Gas-intensive industries such as cement manufacture, aluminium

smelting and ceramic manufacturing have grown to take advantage

of the confluence of cheap energy, a benign tax environment, and

an abundance of cheap labour.

• Electricity demand has grown as economies have grown leading

to corresponding growth in natural gas fired generation. The harsh

climate requires extensive use of desalination and air conditioning

which are energy hungry end-use applications.

As such, despite the regions hydrocarbon resources there are

opportunities to supply gas into its markets.

There are shortfalls of natural gas supply evident today, and this

is forecast to grow.

R E G I O N A L E N E R G Y S U P P L Y A N D D E M A N D


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MEDIUM TERM OPPORTUNITIES

There is an opportunity to supply gas to the Federal Electricity and Water

Authority (FEWA) power stations in the Northern Emirates which are

burning significant volumes of liquid fuels due to a gas shortfall.

Sharjah Electricity and Water Authority (SEWA) is expected to be short

of gas by summer 2005, unless a new source materialises. This is due

to declining gas production from the Sajaa field, which has also caused

a reduction in the amount of Sharjah gas supplies to the growing Dubaimarket. SEWA is currently buying gas from Iran through a new UAE listed

company, Dana Gas.

Oman has developed its gas-based industry over the past few years and,

although new gas fields and infrastructure are being developed, Qatari gas

imports (via the Dolphin project) are required to make-up the shortfall that

would otherwise occur within 2 to 4 years.

LONGER TERM OPPORTUNITIES

In addition to these short to medium term opportunities, there

is a requirement for a project such as Dolphin to supply large volumes

of gas to the UAE and Oman by 2007.

Although the Dolphin Gas project has the potential to flood the market

in the northern emirates and Oman, actual gas deliveries are still many

years away and the cost of delivered gas will have to compete with

cheaper gas from local fields.

CONCLUSION

Oman will face difficulty in filling a 9 to 16 Tcf shortfall without importing

relatively expensive Qatari gas via the UAE.

Within the UAE gas demand is likely to grow further beyond the forecast

8.2 Tcf deficit as soon as industrial users have security of supply. The

estimated available market over the next 20 years is approximately 15 Tcf.


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NORTHERN ARABIAN GAS-CONDENSATE PLAY

Indago has created a portfolio of drilling opportunities distributed along

a trend which they call the "North Arabian Gas Condensate Play" (NAGP).

Indago believes that its NAGP prospects have the scale to contain several

Tcf of gas.

The Oman mountain range stretches from the Musandam Peninsula

in a southwards arc towards Muscat in Oman. These mountains have

been created through the collision of the Arabian plate with an Island Arccomplex, and this has created a foreland thrust belt.

Typically, mountain regions such as these, and in particular the buried

frontal deformation zone, are natural focal points for hydrocarbon migration.

The Omani mountains are to some extent an extension of the Iranian

Zagros Mountains. They formed at the same time and have many of the

same geological elements which are so productive in Iran.

The western mountain foreland area has few oil and gas fields as it has

been relatively under-explored.

In the north there are a number of gas-condensate fields such as Bukha,

West Bukha-Hengam offshore Oman/Iran, and the Saja'a, Moveyiid, Khaif,

Margham and Khubai fields in onshore U.A.E. At the south of the mountain

arc there are other gas-condensate discoveries such as Hafar, Al Sahwa,

Nadir and Hamrat Duru south-west of Muscat.

Although separated by hundreds of km these fields are similar in terms

of the geological elements that make them work. Indago believes that they

are part of a continuous geological system that stretches along the

mountain front. If the petroleum systems throughout the entire length

of the fold belt are the same, then there is likely to be more gas awaitingdiscovery in the under explored area between the proven fields in the

north and the south.

A S S E T P R O F I L E


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This geological insight is nothing new and many of the major oil

companies that explored the Middle East recognised that this was

a potentially prolific gas play. But there was no economic incentive

to explore for gas at that time and the acreage lay dormant. Recently the

economic incentives for gas exploration have changed. Many of the Gulf

countries now consume large quantities of natural gas and are prepared

to pay for the security of additional long-term supplies.



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OVERVIEW

There are 4 concessions in Oman and 1 in the UAE in which Indago holds

working interests.

Indago Oman Limited (IOL) holds a 40% working interest and

operatorship in Oman Block 8 which contains the Bukha and West Bukha

fields. Other partners in this block include LG (50%) and Heritage (10%).

LG is a large Korean company and Heritage is a Canadian listed oil and

gas company.

IOL holds a 40% working interest and operatorship in Oman Block

17. Other partners in this block include Atlantis (50%) and Heritage (10%).

Atlantis was originally formed as an E&P subsidiary of the seismic

company PGS, but is now owned by the Chinese company Sinochem.

IOL and Indago Al Khaleej Limited (IAKL) hold a 100% working interest

and operatorship in all other blocks.

LEGAL T ITLE

There are a number of agreements in place between the relevant

government authorities and the Indago group of companies.

These include:

• The Exploration and Production Sharing Agreements (EPSA's) which

detail the fiscal terms and work requirements for the Omani blocks;

• The Joint Operating Agreements (JOAs) which detail the conduct of joint

venture operations for blocks where there is more than one partner.

• A Heads of Agreement for gas sales from the West Bukha field into the

northern emirate of Ras Al Khaimah.



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EXPLORATION PORTFOLIO PROFILE

An overview of the Indago portfolio, which sets out the Expected Ultimate

Recoverable Reserves as agreed by Petronel, the independent technical

consultant, and which form the basis of our valuation of the company,

is set out below.

I NDAGO PETROLEUM LTD COMPETENT PERSON'S R EPORTI NDEPENDENT VOLUMETRIC ESTIMATE OF ASSETS

Risked Expected Remaining Hydrocarbon Recovery Economics (100%) Economics ( IPL share)Unrisked Unrisked Risked Unrisked RiskedRecovery 100% 100% IPL Share IPL Share NPV EMV NPV EMV

Mi d Mi d POS POS Sal es Gas Co nd +L PG Sal es Gas Co nd +L PG NPV (10%) EMV (10%) NPV (10%) EMV (10%)Block Asset (bcf) (mmb) Prospect WetGas (bcf) (mmb) (bcf) (mmb) (US$m) (US$m) (US$m) (US$m)

Block 8 Bukha 52.4 3.4 1.00 1.00 0.0 2.0 0.0 0.8 10.5 9.7 4.2 3.9

Block 8 West Bukha (Oman) 226.5 27.7 0.70 1.00 65.7 19.0 26.3 2.8 103.0 68.4 41.2 27.4

RAK Hagil 1,586.9 233.7 0.20 0.65 330.0 32.5 330.0 32.5 1,044.2 128.1 1,044.2 128.1

RAK Hagil Lias/Trias 780.1 117.0 0.12 0.65 95.5 9.5 95.5 9.5 557.6 38.2 557.6 38.2

RAK Ash Sham (part) 757.7 109.4 0.09 0.50 34.1 4.9 34.1 4.9 325.7 4.1 325.7 4.1

RAK Digdaga 0 0 0.00 0.00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Block 17 Ash Sham/Ghumdah 480.8 69.4 0.09 0.50 8.9 1.3 3.5 0.5 127.2 5.1 50.9 2.0

Block 31 Jebel Hafit (Oman) 2,058.9 310.3 0.29 0.75 283.6 28.4 283.6 28.4 1,235.4 261.5 1,235.4 261.5

Block 31 Qumaira 0 0 0.00 0.00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Block 31 Jebel Wa'Bah 0 0 0.00 0.00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Block 47 Izz 378.9 54.3 0.24 0.20 9.5 1.4 9.5 1.4 198.3 3.5 198.3 3.5

Block 47 Izz Deep 83.4 0.9 0.15 0.20 6.9 0.3 6.9 0.3 77.87 0.5 77.9 0.5

Block 47 Adam 439.9 68.0 0.19 0.70 31.1 4.6 29.5 4.3 238.5 22.1 226.6 21.0Block 47 Sadood 67.5 10.4 0.11 0.20 0.0 0.0 0.0 0.0 26.8 -6.0 26.8 -6.9

Block 47 Kabshat 54.6 7.5 0.57 0.10 19.4 0.4 19.4 0.4 33.3 0.1 33.3 0.1

Block 47 Dham 0 0 0.00 0.00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Total 6,968 1012 884.6 92.3 838.3 85.9 3,951.5 541.4 3,795.2 490.3

Source: Technical Consultant


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PRODUCTION

BUKHA


Indago is the operator of Bukha, Oman's only offshore producing field.

Bukha has produced since 1994 but is now in decline.

As estimated by Petrenel, the field contains an initial GIIP of 326 Bcf.

Petrenel estimate that proven plus probable reserves of gas remain

at 48.19 Bcf, 4.60 MMbbl condensate and 1.0 MMbbl of LPG.

The Bukha field fluids are contained in two zones known as the Thamama

and the Mauddud. Both reservoirs are fractured carbonates which

augment permeability and provide good flow rates from otherwise lowporosity-permeability rocks. The reservoir has little aquifer support and

depletes as a normal retrograde condensate field, with condensate

dropping out in the reservoir as pressure declines and hence decreasing

the condensate-gas ratio with time.



25/76


This field derives its revenue from the sale of condensate and LPG.

Bukha 1, a sub-sea completion, is connected back to the platform

by a 1,186 metre, 6-inch flexible flow line with separate service and control

umbilical. Bukha 2 is a surface completion.

Produced fluids are exported from the platform by natural drive,

via a 34km, 16 inch diameter pipeline to the Ras Al Khaimah Gas

Commission (RAKGAS) processing facility, located at Khor Khwair in Ras

AI Khaimah, UAE. No processing of produced fluids is carried out on the

platform as this is all carried out at the RAKGAS plant.

The field is mature and on a predicted decline, nevertheless it is expected

to continue producing for 5 years or more. The projected economic limit

of the field continues to be extended with the prevailing high oil price

environment. Current end of field life is expected in 2011.

Production, net to Indago during 2004 averaged 870 barrels

of condensate and LPG per day and 13.9 MMscfd of gas. It is fiscally

linked to West Bukha (in the same EPSA) and hence 90% of the liquids

revenue after operating cost is available to recover costs incurred through

the development of West Bukha.

Bukha is not material in the context of the valuation of Indago.

Nevertheless, as an asset operated by Indago it has established the

credibility of the company in the region.


26/76


DEVELOPMENT

WEST BUKHA


West Bukha is the Omani portion of the West Bukha-Hengam field that

straddles the Oman/Iran border in the Straits of Hormuz. The field

is located within Oman Block 8 which also contains the existing Bukha

field 22 km to the south-east.

The Bukha Joint Venture (BJV) has been given permission by the

government of Oman to develop the field, initially through a single well and

wellhead jacket tied in through Bukha.

The wellhead platform will have 6 available well slots to ensure that further

upside could be accessed if suitable drilling locations can be identified.



27/76


As estimated by Petrenel, West Bukha contains an estimated initial

GIIP of 525 Bcf and CIIP of 54 MMbbl.

West Bukha development is scheduled to commence as soon as possible

with drilling of phase I commencing in late 2005. First gas is scheduled for

late 2007 and phase II continuing in 2008.

Development costs are estimated at around US$ 62 m for a single well

development and US$ 88 m for 2 wells. A successful, 2 well development,

if the simulation profile is achieved, would using NPV10 have a value

of approximately US$120 m, equivalent to US$48 m net to Indagoat a WTI price of US$ 30/bbl.

It is proposed that the development costs will be two-thirds funded from

project finance, though a more conservative estimate would be 50%

project finance. The development plan for phase 1 consists of:

• Drilling and testing of 1 development well, West Bukha-2 (US$20.4 m)

• Installation of wellhead platform and pipeline tied to Bukha (US$34.8 m)

• Tie back and completion of West Bukha-2 (US$6.2 m)

The main producing formation, the Mauddud - Mishrif is expected to bea low porosity fractured limestone and hence the main risk is reservoir

effectiveness. Break even reserves are as estimated by management,

25 Bcf at an assumed WTI oil price of US$24/bbl for the initial

development of phase I.

Based on the operating expectations of management West Bukha

is considered to be a robust project.


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PROSPECTS

BLOCK 31

J EBEL H AFIT


At Jebel Hafit, Indago is targeting estimated mean reserves of 2.7 Tcf

of gas, and 344 MMboe of condensate and LPG. This is a significant prospect.

The Jebel Hafit prospect, named after the prominent mountain that

juts out of the desert above this prospect, straddles the border between

Oman and Abu Dhabi. The geological interpretation shows that the

mountain is actually the surface expression of a deeper structure.

It is a compressional anticline beneath a prominent surface mountain.

The difficulty in readying this prospect for drilling arose from the former lack

of interest in gas and the necessity of organising co-operation between the

UAE and Omani governments to assemble the technical data, including

conducting seismic surveys, across an international border.



29/76


Nevertheless, in 2003 Indago acquired state-of-the-art seismic data which

confirmed the size and integrity of the subsurface structure. Jebel Hafit

appears to be geologically analogous to the producing Margham and

Sajaa field to the north in UAE.

The imaging from the reprocessed seismic data is fair. The main reservoir

target is in the Cretaceous (Natih/Shuaiba) carbonates at circa 5,000m

depth. A gas condensate seep has been discovered by Indago field

geologists on the mountain. Indago is targeting two working reservoirs,

Mauddud and Thamama.

Indago expects to be able to spud a US$ 24.8 well, including testing,

at Jebel Hafit in September/October 2006.


Structural Cross Section a-a’; North Jabal Hafit and the adjacent Oman (UAE) Foreland Basin

by Daniel SchellingScale = 1:50,000

(No VerticalExaggeration)

Kn

Knu

Ksk

Kl

Js

Pk

Ev

Kf

Haw

Thrust Fault

NormalFault

Seismic reflectors

25 Apparent dip inline of section

60 Apparent dip ofoverturned bedsin line of section

L E G E N D

SUB -THRUST STRATIG RA PHIC SECTIO N

Undifferentiated SumeiniGroup and Hawasina Complex (Permian-Cretaceous)

Mayhah Fm., slope facies limestones (Middle-Upper Jurassic)

JabalWasa Fm. conglomerates ? (Upper Triassic)

Fiqa Fm., including "Juweiza" Member (Upper Cretaceous)

Natih Fm. (Wasia Group) (Middle Cretaceous)

Nahr Umr Fm. (Wasia Group) (Middle Cretaceous)

Shuaiba and Kharaib Fms. (Kahmah Group) (Lower Cretaceous)

Lekhwair Fm. (Kahmah Group) (Lower Cretaceous/Upper Jurassic )

Khsr Habshan Fm., SalilFm., and Rayda Chert (Lower Cretaceous/Upper Jurassic )

Sahtan Group (Jurassic)

MahilFm. (Triassic)

Khuff Fm. and Haushigroup, undifferentiated (Permo-Carboniferous)

Evaporites (Infracambrain-Cambrian)

Undifferentiated Precambrian, including basement

Haima Group (Paleozoic)

TRm

HAWA SINA /SUM EIN I A CCRETIO NA RY WEDG E

Qal

Tf

Ts

Taj

Tdu

Tdm

Tdl

Tr

Tur

Ks

PO ST-EM PL A CEM ENT SEQ UENCES

Undifferentiated Cretaceous, SumeiniGroup "slope" sedimentsKu

Jmh

Twc

PCu

Pzh

a

S 68…

30

30

20

80 80

Sumeini Accretionary Wedge

FrontalSumeini Accretionary Wedge

SumeiniFrontalThrust

Seismicno-data zone

J.

U p p e r

L o w e r

North

SEISMICLINEIQS-54

Zone of DuctileDeformation

OMANMOUNTAINS

Note: Mesozoic stratigraphy changes across interpretedTriassic extensionalfaul t and Jurassic-Cretaceous

structuralhinge-line

Carbonate PlatformMargin?

Carbonate PlatformMargin?

a’N 68…

Js

Twc

Kn

Knu

Ksk

Kl

Js

Pk

Khsr

TRm

PCu

K n

K nu

K sk

K l

J s

P k

K hsr

T R m

K n

K nu

K sk

K sk

K l

K l

Js

P k

Khsr

K hsr

T Rm

TRm

Ev?

Ev?

Jmh

SumSum

Ku

Pk

Pzh

PCu

PCuEv?

Ev?

Kf

Kf

Kf

K f

Kf

Kf

T s n T a j

Tf

T d u

T d m

T d l Tr

K s T u r

TsnTaj

T a j

Tdu

Tdm

Tdl

Tdl

Tdu

Tr

Ks

Tur

Tdu

T d m

T d l

T r T u r

K f

Qal Qal

Tf

Qal

Pz h

P z h

Pzh

K s

Structural Cross-Section a-a’;

North Jabal Hafitby

Daniel Schelling

Scale= 1:50,000

StructuralGeologyInternational,LLC576 E South TempleSalt LakeCity,Utah 84102(801)322-1685

Str uctur al Geology of Ex plor ation B lock 3 1 ;

Centr al Oman Thr ust Belt

Enclosure # 5

O c t o b e r , 2 0 0 3


30/76


RAS AL KHAIMAH

H AGIL


Ras Al Khaimah (RAK) is the northern most Emirate of the United Arab

Emirates. Currently the Emirate has limited oil and gas fields over which it can

lay claim, and is dependent upon its neighbours for both gas and oil. However,

Indago has a very promising prospect in Ras Al Khaimah called Hagil.

The Hagil prospect contains 6 target reservoir horizons in two closures

on separate thrust sheets. In the hanging wall of the Rahaba Thrust the Lias

(Neyriz), Milaha, Upper Bih and Lower Bih (Khuff) are prospective, whereas

in the hanging wall of the Tibat Thrust only the Upper Bih and Lower Bih are

expected to be present. A well location has been chosen such that it will

intersect all of these horizons in a reasonably crestal position.

At Hagil, according to Petrenel, Indago is targeting estimated meanreserves of 2 Tcf of gas, and 294 MMboe of condensate and LPG. This

is also a significant prospect.

Seismic was acquired over Hagil in 2003 and this confirmed the presence

of a significant structure. The geological interpretation suggests that Hagil

is a faulted dip closed structure at Permo-Trias level, which is beneath the

main thrust front. The Trap imaging has been much improved by recent

specialist reprocessing of the seismic. The main reservoir target is Khuff

carbonates which will be encountered first at 2,700 m and again at 4,200 m.

The US$ 16.7 m, including testing, Hagil well is expected to spud at the startof October 2005.



31/76


ASH S HAM


Ash Sham is located 4 km north-east of the Hagil prospect. It is a dip closed

anticline above a thrust fault. The anticline is exposed at surface and

2 seismic lines located over the crest confirm its subsurface expression.

The well will target lower Permian clastic reservoirs at 2 km. Although

these reservoirs have not been tested locally they are important

hydrocarbon bearing reservoirs in offshore Abu Dhabi and onshore Oman.

The younger reservoirs in the exposed surface anticline were once

gas condensate bearing. Due to uplift and exposure the hydrocarbons

have dissipated.

At Ash Sham, Indago is targeting an estimated gas recovery of 655 Bcf, and

80 MMbbl condensate. Indago expects to start drilling the US$ 5.4 m,

including testing, Ash Sham well in August 2006 and will use the same drill

team as used at Izz.


32/76


BLOCK 47

A DAM & I ZZ




33/76


A DAM

Adam is 40 km from the PDO Cambrian discovery at Kauther-1 which

flowed at 49 MMscfd/4,000 bpd.

This prospect is a Cambrian closure beneath small Cretaceous gas pool.

The reservoir target is Cambrian Amin sandstone formation at circa

4,200 m depth.

Indago expects to spud a US$ 11.4 m well, including testing, at Adam

in May 2006.

I ZZ

Further to the south in Block 47 are a number of prospects where

2D seismic was acquired in 2003.

One of these is the Izz prospect which has a more subtle surface

expression which is best seen on satellite imagery. The acquisition

of 2D seismic has confirmed the presence of a large buried structure.

Izz is a Cretaceous closure over a salt pillow updip from the Khatmah

gas discovery.

The reservoir target is Cretaceous Natih/Sabsab carbonates at circa

2,500m depth.

There are secondary targets in the Jurassic Hafina and Permian Khuff carbonates.

Indago expects to spud a US$ 10.2 m well, including testing, at Izz either

before or after drilling starts at Hafit.



34/76


LEADS

Indago has an inventory of Leads some of which are nearly advanced

to Prospect status; others are still in the early phase of definition. These

Leads are briefly described below.

RAK

U NRISKED R ECOVERABLE

D IGDAGA

This Lead is a Hagil analogue. It is of comparable size and focused on the

same reservoirs. There is a weak methane seep on top of it. It is located

30 km from Sajaa, the largest gas condensate field in the region. There

is seismic covering the west side. This lead has been worked up to the

stage where seismic now needs to be shot on the eastern limb to complete

the definition of the Lead.

As the seismic over the this lead is not complete, it has not been included

in the valuation.

Depth Gas (bcf) Cond (mmb)

Digdaga 2,500 565* 19*

Source: M. Horn & Co.


* Management's preliminary estimates.


35/76




36/76


BLOCK 31


QUMAIRA

This Lead is 30 km east-south-east of Jebel Hafit. It is cored by Cambrian

salt which has associated bitumen and condensate bearing rocks. Indago

has seismic on this Lead, which is currently being processed. Surface

geology indicates a large closure. Seismic processing has proven

challenging because of image problems derived from the signal/noise

ratio. Results, however, are due in the next 3 months. If the seismic does

not clearly define the crest of the structure, then alternative methods

of definition will be required.

It has not been included in the valuation.

J EBEL W A B AH

This Lead is a very large surface anticline cored by an undoubted deeper

structure. There is currently no seismic for this Lead, though the seismic

scouting is complete. A decision now needs to be made as to whether

to shoot seismic. The decision to shoot seismic at Jebel WaBah will be

driven by the experience at Qumaira. If the problem with the signal/noise

ratio can not be satisfactory resolved, then the expense of seismic will not

be justified and other techniques of definition will be considered.

As there is no seismic over this Lead, it has not been included in the valuation.


Qumaira 2,000 716* 37*

Jebel WaBah 2,500 835* 44*

Yanqul 2,500 871* 45*





37/76


Y ANQUL

This Lead is located north-east of WaBah. There is structural relief

at a depth of circa 2km. What is required is a determination of the extent

of the closure.




38/76


BLOCK 47


S ADOOD

This Lead is located 10km north-east of the Hamrat Duru gas field. The

surface geology indicates that there is a sub-surface structure, and this

is supported by the reconnaissance seismic. Several new seismic lines

are now required to map the closure. This is expected to be a dry gas lead.

K ABSHAT

Indago believes that Kabshat is a satellite to the Hamrat Duru gas field.

It is covered by seismic. It could be drilled now and therefore technically

is a prospect, but Indago wants to shoot one seismic line to determine the

position of any saddle between it and Hamrat Duru. As such, it has been

valued as a Lead.

D HAM

The surface geology indicates the presence of a large sub-surface

structure. Offset seismic 20 km to the south indicates that this is good

sub-surface imaging terrain. The seismic line scouting has finished, and

a decision to shoot seismic is pending. The signal to noise issue

is mitigated somewhat by benign surface conditions.



Sadood 2,200 395* 0*

Kabshat 900 50* 0*

Dham 2,500 575* 0*

Izz Deep 3,900 260* 0*





39/76


I ZZ D EEP

This Lead is covered by seismic. The seismic is currently being

reprocessed for a better image at deeper horizons. It is a Khuff play, one

of the main gas bearing reservoirs in the Middle East. Two nearby wells

have gas and bitumen in the Khuff. The Yibal Khuff field is some 40 km

to the south-west.



40/76


OPPORTUNITY

COMMERCIAL ACTIVITIES AND MARKETING

Indago, in parallel with its exploration and development activity,

will undertake several commercial initiatives:

• Negotiation of a Gas Sales Agreement (GSA) for West Bukha gas with

RAKGAS.

• Negotiation of a cost sharing Memorandum of Understanding for Jebel

Hafit with the Abu Dhabi National Oil Company (ADNOC).



41/76


NEW VENTURE OPPORTUNITIES

Indago is also currently pursuing several possible new venture

opportunities within its area of focus.

The Board has agreed to date expenditure of US$ 2.37 m. However, if any

of the new projects identified below come to fruition, further expenditure

proposals will need to be put to the Board and they will need to be

appraised in the light of available funds.

There are four possible new ventures which have been identified and include:

• Acquisition of a block contiguous with Indago's existing acreage.

If Indago were to acquire this asset, it would expect to spend US$ 5 m

in the next 2 years on its development. This spend will cover signature

bonus, seismic reprocessing and ancillary studies. At this stage, from

what is known of this asset, a 75% probability of a drillable structure

is predicted.

• Acquisition of a 2nd contiguous block* from a competitor. This block

has proven reserves. The cost of acquisition and the drilling of one well

is estimated to cost up to US$ 4.5 m. The block has sunk costs

of US$ 34 m which can be recovered when development and

production from a field commences.

• In joint venture with the Ras Al Khaimah government, Indago intends

to spend approximately US$ 750,000 to reprocess seismic and

to produce a development plan for a discovered field that already has

3 wells drilled in it. A well on structure has already tested for oil and gas

condensate. Indago expects to be a 40% joint venture partner if any

development subsequently were to take place. The fiscal terms

as outlined are attractive.

• Evaluation of a "farm-in". This will cost US$ 100,000. The budgeted

"farm-in" evaluation is one of several evaluation opportunities.

* Indago is in the process of concludingan agreement with Anadarko for thepurchase of their interests in Block 30,which lies immediately to the south-westof Block 47. This block has not beenassigned any value. The block containsfour comparatively small gasdiscoveries in Cretaceous carbonates.

Anadarko has stated that thediscoveries have potential to holdaround 300 Bcf of sales gas reservesin total, though this is probablyan over-optimistic estimate. Thereis some uncertainty as to whether thediscoveries might be commercialas they stand currently. Indago mayseek to commercialise this modest gasresource through integration withpotential future gas discoveries in thearea. Evaluation of this opportunitywill require a detailed re-evaluationof the discoveries.


42/76


WORK SCOPE

Key objectives of the Budgeted Work Programme until the end of 2007 include:

• Phase 1 development of the West Bukha field.

This is currently underway. The cost of drilling the well is circa US$ 20 m

with further development costs of US$ 40 m, giving a total cost

of approximately US$ 60 m. Indago's share is 40% of these costs. Indago

believes that it can project finance 50% of its share of the costs, giving

a cash requirement of US$ 12.0 m.

• Drilling 5 wells in the Northern Arabian Gas-condensate Play.

HAGIL

This well is due to spud at the start of October 2005. Drilling will be for

82 days plus 1 month testing. Drilling costs are US$ 11.8 m, and testing

is expected to cost US$ 4.9 m, giving a total cost for the well

of US$ 16.7 m. Hagil is being drilled first is due to contractual

commitments and the prospect location being located only 2.5 km from the

RAKGAS plant. In the event of success, Hagil could be brought on-stream

through the currently underutilised RAKGAS facilities in as little as a year.

It is conservatively estimated that first gas could be achieved in 2007.

ADAM

Indago aims to spud Adam in May 2006. Drilling and testing will take

4 months. Drilling costs are US$ 8.4 m, and testing is expected to cost

US$ 3 m, giving a total cost for the well of US$ 11.4 m.

JEBEL HAFIT

Indago aims to spud Jebel Hafit in September/October 2006. Thisis a deep well and the intention is to use the rig used at Adam. Drilling and

testing will take 6 months. Drilling costs are US$ 17.2 m, and testing

is expected to cost US$ 7.6 m, giving a total cost for the well of US$ 24.8 m.

W O R K S C O P E & F I N A N C I N G


43/76


IZZ

Indago may start Izz in April 2006 or in the period between the spudding

of Adam and Jebel Hafit. Drilling will take 30 days and testing will take

5 days. Drilling costs are US$ 6 m, and testing is expected to cost

US$ 4.2 m, giving a total cost for the well of US$ 10.2 m.

ASH SHAM

Indago expects to start drilling Ash Sham in August 2006 and will use the

same rig as used at Izz. Drilling will take 30 days and testing will take5 days. Drilling costs are US$ 3.5 m, and testing is expected to cost

US$ 1.9 m, giving a total cost for the well of US$ 5.4 m.

The gross budgeted value of the Exploration drill programme is therefore

US$ 69.1 m including roll-up testing.

In addition, an appraisal well for Hagil is expected to be drilled

at an estimated cost of US$ 16.9 m.

If this appraisal well is taken into account the total prospect drill budget

is US$ 86 m.

• Shoot seismic over leads so as to turn them into mature prospects

ready to drill, by late 2006, early 2007.

The total budgeted cost of this programme is US$ 5.5 m.

• New ventures: secure additional prospective acreage in the United

Arab Emirates and Oman.

As discussed in the previous section, the objective is to acquire acreage

which form part of the same play fairway. Indago will also target existing

discoveries of a marginal nature that might be commercialised through

applied technology or synergies with its existing portfolio.

The total budgeted cost of this programme is US$ 10.3 m.


44/76


FINANCING

WORK SCOPE BUDGET

The gross value of the work programme as currently budgeted

is approximately US$ 125 m. This will be reduced by US$ 23 m of cash

derived from the Burkha assets, giving a net capital required of approximately

US$ 102 m at the time of the IPO for the budgeted Work Scope.

Indago will also require financing for general corporate purposes, including

the evaluation of other opportunities, which has been provisionally estimated

at US$ 2.4 m, giving an estimated financing need of approximately US$ 105 m.

Meridian provided a bridging facility to cover inter-company debt owed

to Medco at the time of the acquisition. This facility will need to be repaid

at the time of the IPO. There is also a contingent loan facility provided

by Meridian, which has been used to fund exploration expenditure and

general corporate purposes since the acquisition, which will also need

to be repaid. The total amount to be repaid is US$ 34 m.

As such, the total amount of money that Indago may need

is approximately US$ 139 m.

PROBABILITY ADJUSTED BUDGET

The Work Scope Budget is one that assumes that all drilled prospects are

successful, and that all exploration work results in a decision to proceed

to the next phase. It also assumes that all new venture negotiation,

are successfully concluded.

This result is unlikely.

Therefore, the Work Scope Budget has been adjusted to reflect a "most

likely" cash requirement in terms of drilling. It has postponed the decision

on the Hagil appraisal well until a more informed decision can be taken.

A similar approach has been taken to the new venture opportunities,

where the budget reflects that spend which has current Board approval.

As such, the Probability Adjusted Budget shows a capital requirement

of US$ 87.45 m.

As there is a reasonable probability that Indago may need additional

capital to complete its Work Scope, Meridian has agreed to provide

a 3 year "back-up" loan facility of US$20 m, at a 10% interest rate, with

a 1% commitment fee on the undrawn amount.

W O R K S C O P E & F I N A N C I N G


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Work Scope Probability

Project Budget Adjusted Budget

West Bukha - Phase 1 US$ 23.53 m* US$11.73 m**

Exploration US$ 69.1 m US$54.76 m†

Hagil US$ 16.7 m

Adam US$ 11.4 m

Jebel Hafit US$ 24.8 m

Izz US$ 10.2 m

Asham US$ 5.4 m

Hagil appraisal well US$ 16.9 m††

Leads - seismic shoots US$ 5.5 m US$5.0 m‡

New Ventures US$ 10.3 m US$2.37 m‡‡

Gross Budget US$ 125.33 m US$ 73.86 m

- Bukha revenue US$ 22.92 m. US$ 22.92 m•

Net Budget US$ 102.41m US$ 50.94 m

+ General Corporate US$ 2.41 m US$2.41 m

+ Debt Repayment US$ 34.10 m US$ 34.10 m

Capital Required: US$ 138.92 m. US$ 87.45 m


* Not assuming any financing.Net, after contribution first half 2005.

** Assuming 50% financing.

† Not all the wells will be successful. As such, not all will be tested.The budget has been adjusted on aprobability basis.

†† The decision to drill an appraisal wellin Hagil is still dependant on theoutcome of further appraisal work. If adecision is made to proceed itsfinancing will be covered by theMeridian back-up loan facility.

‡ As approved by the Board.

‡‡ As approved by the Board.

• Revenue is based on the forwardcurve. It is US$ 11.15 at a flat WTIUS$ 30/bbl.


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The risk factors listed below are some important risks, however the list

is not exhaustive, and investors must assure themselves that taking these

risk factors into account, that Indago is an appropriate investment

considering their specific requirements.

POLITICAL RISK

The countries of Oman and the UAE are considered to be the most stable

in the region. Nevertheless, there are the political risks associated with

any developing economy. In addition, there are well known regional

political risks.

OIL & GAS INDUSTRY

The Oil & Gas Industry is subject to operating hazards, economic

changes, industry competition, and operating cost variations. Indago's

activities are speculative by their nature and involve a high degree of risk.

The Oil and Gas business is subject to a number of factors beyond

Indago's control. An adverse change in any of these factors could result

in the Indago not meeting its business objectives.

REGULATION

Indago may become subject to burdensome Governmental regulation and

permit requirements. Exploration, development and the extraction of oil

and gas are subject to extensive laws, regulations and permitting.

No assurances can be given that any licenses, permits or approvals that

may be required will be given or that existing ones will not be revoked.

RESERVE QUANTITIES

Success of the company will depend on the discovery of reserves

in commercially viable quantities. Substantial expenditures are required

to establish reserves through drilling and analysis. No assurance canbe given that the contained minerals will be discovered in sufficient

quantities to justify commercial operations or that the funds required for

development can be obtained on a timely basis.

R I S K S


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EXPLORATION RISK

From a technical perspective exploration risk can be broken down into

separate geological components. The main categories of geological

risking are reservoir, seal, source/timing and trap. Of these, source/timing

represents the lowest risk as there are at least 3 documented source rocks

throughout the fold belt and numerous fields and discoveries. Seal and

reservoir presence has been addressed through extensive stratigraphic

and structural work. The 2D seismic acquisition programme conducted

in 2003 and early 2004 aimed to address the uncertainties with trap

definition. The programme has returned highly promising results in whatis a very difficult seismic acquisition environment.

The greatest risk common to all prospects is that of reservoir quality.

It is very difficult to predict the porosity and in particular permeability of the

reservoir ahead of drilling. Reservoir quality will remain a risk that

is a challenge to reduce. However, all offset discoveries in the different

reservoirs produce sufficient volumes per well to suggest that the

prospects should be equally effective.

INERT COMPONENTS IN THE GAS COMPOSITION

The Tibat discovery by Indago contained a high proportion of nitrogen

which increased the potential development costs to a level that rendered

it sub-commercial. These prospects as they are significantly larger, will not

necessarily be sub-commercial if they contain a similar volume of inert gas.

DEVELOPMENT RISK

Many aspects of development risk are similar to exploration risk but are

commensurately lower due to the well control that is available. With West

Bukha the main risks is again reservoir quality and effectiveness. At West

Bukha, reservoir quality has been addressed using a combination

of geological facies modelling and 3D seismic attribute analysis.Development well locations have been chosen not simply on the basis of

structural location but where reservoir development is predicted to be best.


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PRODUCTION RISK

The Bukha field has been producing steadily for over a decade and there

have been no major surprises in the production performance to date.

Material balance calculations are regularly carried out, and actual well

performance has always closely matched the predicted performance.

Thus there is a negligible risk associated with continued production. Well

performance is continually monitored should the need to take remedial

action ever arise.

RESERVE CALCULATION

Calculation of reserves is subject to uncertainty. Until reserves are

processed, the quantity of reserve data must be considered as estimates.

FINANCIAL RISK

Indago has had limited revenues to date and has consolidated

accumulated net losses. Indago intends to invest in developing its

business, as such; further losses and negative cash flows will be incurred.

Indago will require a significant amount of cash to pursue its business

strategy, to meet its liquidity needs and to service its debt obligations.

If Indago can not raise additional finance it may be forced to reduce

or delay its capital expenditure programme, to refinance all or a portion of

its existing debt, to sell some of its assets or to obtain additional financing.

The ability of Indago to arrange additional financing and the cost

of financing depends upon many factors, including, amongst others,

economic and capital markets conditions, investor confidence in both the

oil and gas industry and in the company, regulatory developments and

credit availability from banks and other lenders.

If Indago is unable to comply with the restrictions and covenants under certain terms of the existing financing instruments, there could be a default

under the terms of these instruments, which could result in the

acceleration of repayments of funds that the Group has borrowed

or termination of such instruments.

Indago has partially offset some of its financial risk by agreeing the

US$ 20 m "back-up" loan facility.

R I S K S


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EQUITY DILUTION

There is significant risk of dilution as Indago will require further capital in future.

'GOING CONCERN' ASSUMPTION

Indago's consolidated financial statements have been prepared assuming

the Company will continue on a "going-concern" basis; however unless

additional funding is obtained this assumption will have to change and

Indago's assets may have to be written down to asset prices realizable

in insolvency or distress circumstances.

CONFLICT OF INTEREST

Directors and Officers may serve on Boards of other exploration

companies and situations may arise where these directors and officers will

be in direct competition with the Company.

In addition, Indago has two significant shareholders, and their interests

may conflict with the interest of minority shareholders.

ATTRACTION AND RETENTION OF KEY EMPLOYEES

The Group is dependent upon the industry contacts and expertise

of a limited number of its senior management team and accordingly the

loss of the services of any of the senior management team could affect the

business and profitability of the Group. There is no assurance that the

Group will be able to retain such key executives or senior management.

The Company has entered into service contracts with the relevant

individuals to minimise this risk.


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PROFIT & LOSS

The main source of revenue for the foreseeable future will be the Bukha

field, and in due course the West Bukha field will contribute to revenue.

At the end of 2004 the Bukha field had largely exhausted its cost recovery

pool. In early 2005 Bukha exited cost recovery and is now into a profit

sharing arrangement with the government.

The West Bukha well would add to the cost recovery pool in Block 8 andin the event of failure all drilling costs could be cost recovered against

Bukha production. Thus the economic impact of a failure is much lower

than if no cost recovery were available.

Net G&A costs of US$1.5 m per annum are forecast going forward.

On the basis of actual revenues and expenditures the business is currently

breaking even.

However, the current forecast anticipates that expenditure on NAGP

exploration and West Bukha development will commence towards the end

of 2005.

F I N A N C I A L A N A LY S I S

Indago's 2005 interim accounts

are presented hereafter. They

reflect the position of Indago

just prior to its management

buy-out, supported by Meridian.

Though Indago has prepared

three year historic accounts,

it must be recognised that these

accounting statements will be

of limited use as a guide to thefuture performance of the

business.

Though revenue from Bukha

and West Bukha will cover

operating expenses going

forward, Indago is an

exploration and development

company, and it will need to

raise further funds in due course

to finance its activities.


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CONSOLIDATED PROFIT AND LOSS ACCOUNTS*

6 months ended Year ended Year ended Year ended

US$ 30/06/05 31/12/04 31/12/03 31/12/02

Turnover 1,975,002 15,754,771 7,696,871 9,798,216

Cost of sales (686,077) (7,305,506) (2,671,369) (4,578,405)

Exploration costs written off (1,240,929) (4,845,864) (19,165,948) (4,407,748)

Gross profit/(loss) 47,996 3,603,400 (14,140,446) 812,063

General and administration expenses (1,628,814) (3,137,135) (2,340,162) (1,732,797)

Other income - - 1,127,192 1,947,772

Other expenses (882,014) (2,619,579) (39,858) (100,187)

Operating profit/(loss) (2,462,832) (2,153,313) (15,393,274) 926,851

Debt forgiveness - - - 2,750,723

Operat ing prof it /(loss) af ter except ional i tems (2,462,832) (2,153,313) (15,393,274) 3,677,574

Interest payable and similar charges (2,552) (3,134) (2,285) (2,433)

Profi t/(loss) on ordinary activi ties before taxat ion (2,464,384) (2,156,447) (15,395,559) 3,675,141

Tax on profit/(loss) on ordinary activities (228,000) - - -

Profi t/(loss) on ordinary activi ties af ter taxat ion (2,692,384) (2,156,447) (15,395,551) 3,675,141

Retained pr ofit/(loss) fo r the period (2,692,384) (2,156,447) (15,395,559) 3,675,141

* Management Accounts still subject to Audit review



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BALANCE SHEET

Indago had Current Assets of US$ 5.9 m as at the 30th June 2005,

reflecting the contribution of Bukha and short-term loans drawn to fund

current financial commitments.

The US$ 2.5 m from related parties refers to loans due from its former

parent Medco.

US$ 5.58 m of the Fixed Assets relates to Oil and Gas properties.

The total Assets of Indago as at the 30th June 2005 were US$ 12.1 m.

Indago has current liabilities of US$ 1.8 m, excluding the inter-company

loan made by Medco.

The US$ 28.5 million reflect a loan extended by Medco. That loan was

repaid to Medco by Meridian at the time of the management buy-out, and

is now due to Meridian.



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CONSOLIDATED BALANCE SHEETS*

US$ 30/06/05 31/12/04 31/12/03 31/12/02

Fixed assets

Intangible fixed assets 568,922 - - -

Tangible fixed assets 5,582,628 6,234,588 7,829,836 9,818,432

Total Fixed Assets 6,151,550 6,234,588 7,829,836 9,818,432

Current assets

Inventories 908,282 6,570 1,317,754 -Trade & other receivables 1,065,547 151,308 200,349 1,971,720

Due from related parties 2,552,834 961,953 2,987,331 13,066,620

Other current assets 143,018 1,321,186 901,229 589,375

Prepayments and accrued income 115,085 2,739 74,353 92,012

Cash at bank and in hand 1,208,945 1,069,365 309,032 345,291

Total Current Assets 5,993,711 3,513,121 5,790,048 16,065,018

Total Assets 12,145,261 9,747,709 13,619,884 25,883,450

Creditors - amounts falling due within one year

Trade creditors and other payables 1,379,700 1,953,165 3,336,842 561,629

Accrued expenses and other liabilities 478,470 199,420 35,730 28,000

Tax payable - - - -

Due to related parties 28,486,916 23,489,783 23,985,524 23,636,474

Total Creditors 30,345,086 25,642,368 27,358,096 24,226,103

Provision for l iabilities and charges

Employee gratuities (388,218) - - -

Capital and reserves

Called up share capital 6,889 6,889 6,889 6,889

Additional paid in capital - - - -

Profit and loss account (18,594,932) (15,901,548) (13,745,101) 1,650,458

Equity shareholders' funds (18,588,043) 15,894,659 (13,738,212) 1,657,347

Total Liabilities 12,145,261 9,747,709 13,619,884 25,883,450




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CONSOLIDATED STATEMENT OF CASH FLOWS*

6 months ended Year ended Year ended Year ended

US$ 30/06/05 31/12/04 31/12/03 31/12/02

Net cash (outflow)/inflow from operating activities (3,208,179) 1,870,568 (11,533,740) (575,844)

Capital expenditure and financial investment

Additions to property, plant and equipment (380) - (58,051) (96,879)

Additions to oil and gas properties (58,113) (54,062) - -

Net cash provided/(used) in investing activities (58,493) (54,062) (58,051) (96,879)

Net cash outflow before liqu id resources & financing management (3,266,272) 1,816,506 (11,591,791) (672,723)

Financing

Receipts from related undertakings 3,740,295 11,868,911 24,169,474 8,037,298

Payments made to related undertakings (334,043) (12,925,479) (12,613,940) (7,152,273)

Net cash provided/(used) by financing activities 3,406,252 (1,056,568) 11,555,534 885,025

Net increase/(decrease) in cash & cash equivalents 139,580 759,938 (36,257) 212,302





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PROBABILITY PORTFOLIO VALUATION

When valuing Indago, you are valuing a portfolio of assets. The assets

include a producing field, an advanced development, a portfolio of drillable

Prospects, and an inventory of Leads.

A conventional Net Present Value of Discounted Cash Flows methodology

can be applied to the producing field of Bukha and to the development

at West Bukha.

The overwhelming value attributable to Indago, however, is to be found

in its exploration portfolio of Prospects and Leads.

The valuation of Prospects and Leads is technically more challenging than

the valuation of a producing or late development project.

The methodology deployed to value Prospects and Leads is probability

based. The valuation of and the investment in exploration portfolio's using

probability should be done only by experienced and sophisticated investors.

This valuation methodology depends on the input of data from a number

of professionals. Most notably it is derived from data provided by the

geologists and other technical consultants who calculate in the first

instance the size of the "target" structure and an estimate of recoverable

oil, gas, condensate and other liquids. For the sake of clarification, these

are not "proved" nor are they "probable" reserves, these are "target"

reserves. That is to say, these "reserves" are what it is hoped will

be established in due course as "proven" or "probable", but until then

these "reserves" are merely "best estimates" by someone who

is recognised as being technically competent to make such an estimate.

Despite a significant amount of money spent on these technical reports,

it must be recognised that they are only a "best guess". Until a hole hasbeen drilled into the reservoir you do not know if there is anything down

there, whether it is oil, gas or simply water. You do not know whether

it is sweet or sour. You do not know whether it is commercial or not. Even

if it flows, it is still uncertain as to how much will be extractable. You do not

know the price you will get, nor do you know your costs. As such, oil

exploration and development is a very high risk activity. You can, and most

explorers do drill "dry holes", that is to say despite the extensive geological

reports they do not find anything. Even when they do they often have

to shut-in and plug the hole for a variety of reasons, and the money spent

drilling that hole is therefore wasted.

VA L U AT I O N


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Recognising these difficulties and limitations, having established

an estimate of recoverable oil, gas, condensate or other liquids, the next

step is to calculate an estimate of "net back". Briefly, this is another "best

guess" which seeks over the life of field to estimate after capital,

development, operating, royalty and tax costs the dollars returned

to an investor for every barrel of oil produced at different price levels.

In effect it the net margin per barrel of oil.

With a target recoverable reserve estimate and an estimated "net back",

a gross value for each field is then calculated. By its self this gross value

is meaningless; it assumes a 100% success rate which never occursin an exploration portfolio.

Each asset is then risk appraised, and a probability value is assigned

to reflect varying degr

Horn Indago Petroleum Report 201005 - Final

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