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Good morning Ladies and gentlemen and thank you for rising early to come and listen

to what I have to say today. I trust I will make it worth your while.

The title of my presentation today is:

Investment Insights from Trends in Indonesian Gas MarketsWe will see how the Indonesian energy and specifically gas markets are going through

some major structural changes and we will look at the investment opportunities and

challenges induced by these changes.

Before I start however I would like to spend a few minutes introducing Risco Energy, a

company that was formed 14 months ago and is growing very rapidly.

Riscos investments have been partly driven by some of the insights derived from the

gas market trends we will talk about.

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A private Indonesian sponsored Singapore based Energy Investment Company.

Bridge between private equity and operating oil and gas company

Established July 2010 by experienced upstream oil and gas transaction specialists

Strategy to leverage capital, industry and equity market knowledge and relationships to

rapidly build a marked driven upstream growth portfolio with a premium valuation.

A lot of words here that require some elucidation

Invested US$150 million in 14 months and have secured

Major stake in Ephindo, Indonesia leading first mover CBM company with

6 PSCs and at first gas from pilot wells in two PSCs

7,500 boepd of production in Indonesia and Philippines

Operated oil and gas production and development onshore South Texas

Leverage up equity with circa US$40 million in RBL facility

On track to IPO Ephindo in 1H 2012 and Risco Energy at end 2012

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We are a Singapore company but most regional staff are located in a Jakarta

Representative Office

Differentiated from private Equity or portfolio investors by having significant in-house

upstream oil and gas capability

Core team responsible for acquiring 500 MM boe reserves over five years at EMP

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In 14 month have established offices in Singapore, Jakarta and Houston with operations

in Philippines, Indonesia and Texas

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Riscos first investment, one month after it was founded was a 28% stakein Ephindo,

Indonesias first mover CBM company.

We recognized good assets and management that needed additional capital and

operating capability.

Positioned Ephindo as the local partner of choice that is capable, well capitalized and

well positioned at the juncture of CBM resource quality, infrastructure and markets.

Grown from 3 to 6 PScswith more coming

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Significant conventional portfolio build with 19 MMstboe of 2P reserves and 7,000

boepd production

Mature assets with significant development potential

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So lets get back to looking at

Investment Insights from Trends in Indonesian Gas Markets

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To segment my message, I have the following presentation structure:

A brief overview on Indonesian Energy Supply and Demand and the role of gas

Some Specific Gas market insights

The emergence of Coal Bed Methane as a a potentially material and disruptive

supply source

A quick look at the implications of commercial success in the emerging Indonesian

CBM Industry

An overview of the key investment implications of this rapidly changing gas business

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Like many developing countries, the primary driver of energy consumption is economic

growth and this chart clearly shows the impact on energy consumption of Indonesias

dramatic economic growth since emerging from the 1998 Asian financial crisis.

The economy shows an energy intensity of around 1.0 meaning it take one unit ofenergy (a TOE in this case) to deliver one unit of GDP growth.

Energy subsidies, as we will see later, are however still pervasive in the Indonesian

economy and changes in subsidy levels also periodically impact annual energy

consumption growth.

Indonesia's 10 year CAGR in energy consumption is 3.6%.

At a forecast 6.0% economic growth rate, Indonesias energy consumption will doublein the next 12 years and gas should play a key role in meeting this demand increase.

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Indonesias economic development of the 1970s and 1980s was partly oil export

driven. However declining production and rising consumption saw Indonesia transition

to become an oil importer in 2003 and loose its OPEC membership shortly thereafter.

Indonesia remains a substantial gas exporter however.

Indonesias status as the worlds largest LNG exporter, was lost to Qatar a few years ago,

however Indonesia continues today as a net oil and gas exporter on a boe basis.

However, on a value basis, with Indonesia importing some half of its petroleum

product needs and exporting LNG and piped gas, the hydrocarbon trade account is in

balance.

Indonesias coal production and exports have skyrocketed in the last five years as it

feeds energy hungry India and China in particular with thermal coal.

Production of renewables, largely geothermal and increasing palm oil is growing

steadily from a small base however the full potential of geothermal is a long way from

being realized.

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The bottom line is that Indonesias net energy exports remain strongly positive with the

industrys historic export status being driven successively by oil, then gas and now coal.

The historic migration of exports from Oil to Gas to Coal is apparent

Will CBM follow?

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As mentioned earlier, the Indonesian energy sector is still highly distorted by the blunt

instrument of subsidies.

You cannot talk about energy in Indonesia without talking subsidies so it worth looking

at what is really happening

In the 2102 draft budget, energy subsidies make up 15% of budget expenditure, and

that assumes a 10% 2012 increase in the TDL.

These subsidies distort consumption, investment, BOPs and tax revenues.

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Petroleum products consumption has grown at a CAGR of 3.3% p.a. driven by

transportation fuels but offset by negative growth in Kerosene and fuel oil. The former

has been displaced by LPG and the latter by gas for power generation

Growth in consumption was fairly steady until 2005, interrupted however by the 1998Asian financial crisis and then the doubling of domestic fuel prices in late 2005.

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Post the major price increase in end 2005, the governments main tool to manage

subsidies has been limiting the availability of subsidized petroleum products,

particularly Kerosene for households and Diesel for industry.

This has been quite effective however there is a strong underlying 7.0% p.a. CAGR ingasoline usage driven by the increasing number of cars and motorbikes on the roads.

The acceleration of gasoline and diesel consumption in the last few years, is way

beyond GDP growth rates, suggests smuggling. This has accelerated as the price

differential to do so (differential between subsidized and market price) has risen.

Subsidies at the current level are unsustainable and rising domestic fuel prices are

inevitable, only the political will is lacking.

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Now lets derive some insights from trends in the natural gas market

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Indonesia's gas production is still rising although the rate of increase has moderated

substantially since the growth of LNG export expansion came to an end in the early

1990s.

Pipeline exports boosted export growth in the 1990s and more recently the TangguhLNG plant in Papua came on stream as Indonesia third LNG export facility.

The most striking long term trend is now the rise of domestic gas consumption.

This is driven by the pricing benefits of natural gas and government policy to replace

expensive petroleum product imports (which are subsidized) with domestically

produced gas.

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So how is the gas production utilized?

In 2010 some 83% of Indonesian gas production was sold, with the rest being either

consumed in production operation or lost through flaring and shrinkage.

Of the gas that was sold some 38% was consumed in the domestic market and the

remainder was either exported as LNG, largely to Japan, Korea or Taiwan or through

pipelines to Singapore and Malaysia.

PLN (State Electricity Company) and PGN (State Gas Company) and Fertilizer Producers

(State owned) were the largest domestic consumers responsible for over 70% of

consumption between them.

All were supply constrained in 2010.

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Unlike oil reserves, proven gas reserves have continued to grow in Indonesia as

exploration has more than replaced production.

A leveling off in proven reserves is however evident in recent years and a decline in

potential reserves is also evident, driven by declining exploration investment andsmaller exploration find sizes.

The decline of exploration investment is a subject in itself however it clear the

upstream business in Indonesia is increasingly mature and gassy. It important to

understand that oil drives the industry cost structure and we remain in a US$100 bbl

price and cost environment while domestic prices at say US$6.0 mmbtu mean we only

have a $36.0 / boe revenue environment.

This is a disincentive for exploration investment.

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While Indonesia is gas resource and reserve rich most fields are undeveloped and

distant from the major markets in Java with supply constrained by a lack of

transportation infrastructure.

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Beyond upstream gathering pipelines, the major gas transportation infrastructure

centers around South & Central Sumatra - West Java and Natuna SeaSingapore

and Malaysia

Plans for pipelines from Kalimantan to Java have not been realized and are rapidly beingovertaken by lower cost, quicker and more flexible LNG import terminals or Floating

Storage and Re-gassification units (FSRUs) planned to address critical gas supply

shortfalls in Java and North Sumatra.

Mini LNG regassification plants are also being planned in Eastern Indonesia as shown on

this map (Bali, Halmahera and Polema)

Pertamina and PGN are major players in this new infrastructure development with PLNbeing the major customer, especially where it has CCGT facilities burning expensive

imported diesel fuel.

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Indonesia remains undersupplied with gas as pipeline and LNG exports emanate mostly

from fields distant to the Java gas demand centers

This diagram shows that even with the development of LNG regasification terminals in

Java and Sumatra, domestic market supply constraints are expected to remain.

This demand forecast is also typical of many developed in Indonesia, where demand

growth is fundamentally supply constrained and not reflective of the unconstrained gas

demand potential.

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West Java is Indonesias largest gas market with strong power, fertilizer and industrial

markets and here the supply demand imbalance is most apparent.

The solution is the 2-4 LNG import terminals being developed over the next five years

delivering supply potentially > 1,250 MMSCFD.

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The result is PLN planning for LNG being an increasingly important fuel, that displaces

high cost diesel and fills the gap that gas has failed to fill.

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A long history of low domestic gas prices, certainly lowered than export prices as this

graphic shows, is one of the reasons behind the current domestic supply constraints.

Lack of Infrastructure and customer credit quality were other significant factorsimpeding supply.

Effectively, upstream suppliers were for many years being asked to subsidize largely

state owned domestic consumers and support PGNs fat profit margins. This was never

sustainable in my view and led to the current shortfalls.

This situation, driven by necessity, is now changing.

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Upstream gas prices, as measured by new domestic gas contract signings have been

trending strongly upward for a number of years, as oil prices have also trended upward

and supply constraints increased.

Years of low long flat nominal pricing has been replaced by higher starter prices with

some form of indexation now the norm. Oil linked prices paid by some customers

deliver prices in excess of US$10.0 / mmbtu at current oil prices. This is a good deal for

both producers and customers.

In 2010 the average headline price for new gas contracts was US$5.8 / MMbtu. This

however compares with an average Minas Indonesian Crude Price (ICP) of US$ 81.44/

bbl or US$14.04 / MMbtu.

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The above is self evident.

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The chart clearly shows the compelling gas value proposition for energy customers

whose alternative is market priced or for some, subsidized petroleum products.

Also shown is the expected prices of re-gassified LNG delivered from the Bontang LNGplant to customers in West Java from East Kalimantan. While this represents a 250%

increase in gas prices, the result is still very cost effective gas and environmentally

friendly energy.

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Now lets explore the potential significance of the emerging CBM industry.

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Coal Bed Methane (CBM) known as Coal Seam Methane (CSM) in Australia , like Shale

Gas is Unconventional Gas that is not found in traps like conventional gas. CBM is

generally found at less than 1,000 m depth, shallower than most conventional gas

reservoirs.

CBM is gas that is adsorbed onto the surface of coal and held there by the pressure of

water in the coals. If the water pressure is reduced by pumping the water out the gas is

liberated by desorption.

Most exploration, development and production characteristics of CBM make it more

expensive than conventional gas on a full cycle basis and its success has been where

conventional gas production is in decline and unable to meet demand.

Some characteristics of CBM gas are however more attractive than conventional gas.

These are:

Lower exploration risk

Lower drilling costs given shallower depths and lower pressures

Higher storage capacity of coal per unit rock volume

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Technology led and market driven CBM production has had a material impact on US,

Canadian and Australian gas markets.

CBMs impact in the US and Canada has however been totally eclipsed by he success of

shale gas.

In Australia, a major gas producer and exporter, CBM is currently responsible for 12% of

total gas production and this is set to increase dramatically as LNG exports from CBM

are developed.

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Indonesias CBM potential is world class, as would be expected of a major coal

producer.

The CBM resource potential has been estimated at 450 TCF. If only 30% realized this is

equal to the remaining conventional gas reserves we saw earlier.

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Three basins hold 80% of this potential.

South Sumatra

Kutai Basin

Barito Basin

However only South Sumatra and Kutai basins also have developed gas markets and

infrastructure.

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New regulations that resolved overlapping claims and provided fiscal incentives have

resulted in the signing on 39 CBM PSCs since 2008.

Many more are expected over the near term.

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Pertamina leveraged its large conventional PSC land holding to move into the CBM

business largely financed by first mover local and foreign companies

Entrepreneurial local companies are the next most significant although their business

models are different.

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The 39 PSC have committed to drill 256 core holes and 96 pilot holes over the first

three year period. What is needed is the rigs to do this as there are no fit for purpose

CBM coring or pilot rigs in the country and the conventional oil and gas rig approach is

turning out to be very expensive

Solving this is a challenge and a great opportunity for the service sector.

Import and local content regulations is certainly not helping

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East Kalimantan is the nexus of CBM Resource Quality, Markets and Infrastructure and

has been the initial focus areas for many CBM investors.

The presence of a 22. 5 MTPA undersupplied LNG plant is obviously a huge investor

draw card and stands in contrast to the billions of dollars of downstream LNGinvestment that will have to be made to commercialize Queensland LNG.

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Government and Industry have high expectations for Indonesias CBM production

potential and initial drilling results are technically very encouraging all be it generally

behind schedule.

Material exploration and pilot drilling programs are underway..

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With Indonesian connected to regional markets by LNG and pipeline infrastructure,

CBM could emerge as a major new gas supply source, material enough to impact local

and regional markets

Markets and route to market vary by basin.

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Southeast Asia for example remains a net gas exporter although this is expected to

change before 2020 as numerous countries commence gas and LNG imports.

As a post 2020 supply demand gap opens up, CBM is well positioned to step into the

gap.

CBM from East Kalimantan is especially well positioned given the infrastructure is in

place meaning the gas should be low on the supply cost curve

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