1Q16 results

Investor and analyst update

13th May 2016

1

2

DISCLAIMER

The views expressed here contain information derived from publicly available sources that have not been independently verified. No representation or warranty ismade as to the accuracy, completeness or reliability of the information. Any forward looking information in this presentation has been prepared on the basis of anumber of assumptions which may prove to be incorrect. This presentation should not be relied upon as a recommendation or forecast by Banpu Public CompanyLimited. Nothing in this release should be construed as either an offer to sell or a solicitation of an offer to buy or sell shares in any jurisdiction.

3

Financial summary

Power business

Coal marketing

Coal operations

Focus: shale gas

4

3

2

1

5

Looking ahead6

4

Chaffee Corners: attractive fundamentals

U.S. NATURAL GAS RESERVES BY SHALE GAS PLAYS (2014)

Unit: Tcf

OTHERS

16 Tcf

85 Tcf

24 Tcf

17 Tcf

12 Tcf

6 Tcf

Ultica

17 Tcf

24 Tcf

Marcellus

CHAFFEE

CORNERS

$112m investment for 29.4% stake in Chaffee Corners, Pennsylvania, USA

Strategic location: Northeast of Marcellus, c.200 miles from NYC

Dry gas unconventional: 156 Bcf* proved (P1) reserves; 173 future wells; 10 TcfOGIP**, average net production, target 2016 c.21mmcfd*

Gas sold via “firm” gas contract for 10 years

Positive cash flows should be self-funding, last twelve months Ebitda of c.$11m*,with low well breakeven gas price

Timing of investment: attractive valuation $0.7/Mcf (1P)

Strong operating partner

* Presented on a ‘net to Banpu’ basis verified by Rose & Associates; ** Original-gas-in-place

5

NYCPennsylvania

Chaffee

Corners

• Asset is located in the “Super Core” region of North East Pennsylvania

• Competitive costs relative to other NE Super Core, Marcellus operations

• Producers in the Marcellus field benefit from proximity to the high-demand markets along the East Coast of the United States

• A pure-play investment in a de-risked dry gas resource base with very high recovery rates – in the core of the Northeast Pennsylvania Marcellus Gas Play

Favorable location: Marcellus Supercore

6

Source : Sanchez Energy Corporation

Recap : unconventional technology

Reservoirs and conventional versus unconventional

Hydraulic fracturing

involves high pressure injection of fracking fluids, mainly water into

deep-rock formations to

enable gas, trapped in low-

permeably shale to flow more freely

for extraction

7

Conventional vs. unconventional life cycle

TYPICAL CONVENTIONAL PRODUCTION PROFILE

Unit: BOPD*TYPICAL UNCONVENTIONAL PRODUCTION PROFILE

Unit: BOPD*

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

1 11 21 31 41 51 61 71 81 91 101 111

PLATEAU

RAMP

SECONDARY

RECOVERY

(e.g. WATERFLOOD)

DECLINEPRIMARY

RECOVERY

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

1 11 21 31 41 51 61 71 81 91 101 111

UNCONVENTIONALCONVENTIONAL

SECONDARY

RECOVERY

DRILLING DEVELOPMENT

TERMINAL DECLINE

(TO ECONOMIC LIFE)

Production month

No

exploration

risks. Wells

performance

converges on

a portfolio

mean

ExplorationProduction monthExploration

High

exploration

risk before

development

• Higher exploration risk up front • Generally no upfront exploration risk (reservoir area already well understood)

• Fewer number of wells required to reach production plateau

• Wells have steep declines therefore require many wells to develop a field

• Primary recovery generally lower costs• Secondary recovery generally higher costs and required

to extend production

• Well costs and productivity generally improve as more wells are drilled due to learning curve and economies of scale

• Field is produced to economic life (where production falls below break-even threshold)

• Production as a shallow long-term (terminal) decline after initial production fall-off

* BOPD stands for barrel of oil per day

8

Reserves

TOTAL 1P RESERVES AT CHAFFEE CORNERS

156 Bcf*

67 Bcf(62 Wells)

25 Bcf(14 Wells)

64 Bcf(53 Wells)

PROVED

UNDEVELOPED

RESERVES

(PUD)

PUD are expected

to be extracted

through new wells

on undrilled

acreage, however,

this undrilled

acreage must be

"proved" to a

reasonable extent

PROVED

DEVELOPED

NON-PRODUCING

RESERVES

(PNP)

PNP are expected to

be recovered from

zones behind casing

in existing wells, or

from zones that are

shut-in for market

conditions, pipeline

connections or

mechanical reasons

and are capable of

production, but the

timing is uncertain

PDP are expected to

be extracted through

existing wells and

equipment, and are

actively being

produced

PROVED

DEVELOPED

RESERVES

(PDP)

*Verified by third party Feb 2016: Rose & Associates

9

Estimated Ultimate Recovery (EUR)

Source: USGS

Definition: sum of all oil or gas that is forecast to have the potential to be produced up to the termination point

Higher EUR implies higher reserves and higher economics, assume all else equal.

Impact: In the oil and gas industry it is important that drilling projects meet an acceptable estimated EUR threshold for a project to be considered viable and profitable.

Derivation: EUR can be calculated in many differing methods and units depending on the project or study being conducted.

0 24 48 72 96 120 144 168 192 216 240 264 288

12000

10000

8000

6000

4000

2000

0

Daily production (LHS)

10

9

8

7

6

5

4

3

2

1

0

Production month

ILLUSTRATIVE DAILY PRODUCTION AND EUR

BcfMscfd

Accumulated

production (RHS)

EUR

10

Source: John Staub, EIA conference in June 2015

0

1

2

3

4

5

6

7

8

9

10

Barnett Fayetteville Haynesville Marcellus

EUR COMPARISON

Unit: Bcf per well

25th to 75th percentile

Average EUR*

Avg. EUR of Chaffee

Corner’s South wells

0

1

2

3

4

5

6

7

8

9

10

2008 2009 2010 2011 2012 2013 2014

EVOLUTION OF EUR SINCE 2008

Unit: Bcf per well

Haynesville

Barnett

Fayettevile

Marcellus

EUR increased with improved production techniques; Marcellus, start-up in 2008, shows strongest growth

EURs vary significantly based on reassessed reserves, estimates, and associated recovery factors

Avg. EUR of Chaffee

Corner’s South wells

* Data points in 2014 for Barnett, Fayetteville and Haynesville; 2013 for Marcellus

EURs vary through differing time and locations

11

Cost improvement in low gas price

DRILLING AND COMPLETION COSTS

Unit: U$M/well

In lower gas price environment since early 2014, operators have been working on reducing costs. As a result Henry Hub breakeven was down by over $1/Mcf or 20% across sub-plays from 2014 to 2015

6.0

6.2

6.4

6.6

6.8

7.0

7.2

Nort

heas

t PA

Bra

dfo

rd

South

west

ric

h g

as

Centr

al P

A

Susq

uehan

na

core

Ric

h g

as c

ore

2015

2014

AVERAGE OF

CHAFFEE CORNERS

SOUTH WELL

FULL-CYCLE BREAKEVEN (HENRY HUB)

Unit: U$/Mcf

8

6

4

2

0

2014 average

2015 average

Ric

h G

as C

ore

Susq

uehan

na

Core

Bra

dfo

rd A

rea

WV

Ric

h G

as

Gre

ene D

ry G

as

Pitts

burg

h A

rea

Lyc

om

ing

Are

a

WV

Dry

Gas

Alle

gheny

Mounta

ins

Nort

heas

t Pennsy

lvan

ia

South

west

Ric

h G

as

2014

2015

Source: Wood & Mackenzie

ILLUSTRATIVE ONLY

12

Gas sale process and off-take

Chaffee Corners JEA

JEA owns all aspects of gas production and distribution to this point− Operator handles all gas marketing on

behalf of JEA− Committed off-take to Banpu's

position is c.15Mmcf/day, from operator, backstopped by a specific gas sales contract on TGP to wholesalers/end-users

Kinder Morgan distributes gas to wholesalers and end-users on its interstate pipeline network− Chaffee Corners uses

Tennessee Gas Pipeline (TGP) to evacuate gas directly out of Chaffee Corners area

− The gas flows through other pipelines to end markets

Silvers gas sales point on TGP leg 300

Wholesalers/End-users

Operator sells gas to a variety of wholesalers and/or end-users. The exact parties are not disclosed to JEA partners.

UPSTREAM

Natural gas

production

at well head

GATHERING

SYSTEM

PIPELINE

TRANSPORT

WHOLESALERS END-USERS

Gas gathering,

processing and

compression

Interstate gas pipeline

transmission (regulated)

• Wholesaler distribution

points

• Storage if required

• Power generation

• Heating (commercial/

residential)

• Export (pipe, LNG)

• Industrial/

petrochemical

GAS MARKETINGNatural gas marketing providers and hedgers matching supply with demand

13

Benchmark price and differential

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

2012 2017 2022 2027 2032

HENRY HUB AND RELATIVE NETBACKS

Unit: $/MMBtu (2014 real term)

HENRY HUB

NETBACK: FIRM TO

PLANT (HENRY HUB)

Source: IHS Energy

Discount is based on transportation cost and marketing fee for pipeline transportation to end markets

With over 20 Bcfd of new pipe capacity entering service within a 2.5 year period ending in 2018, basis may narrow significantly across Appalachia

Notes: the spot netback is a straight basis calculation to TGP Z4 313/Marcellus;

the firm netbacks assume a constant real $.365 transport rate (assuming pipe rates

increase with inflation), provided by Kalnin, from either the Henry Hub or

Dominion S Pt, since the delivery point is unknown.

NETBACK: SPOT TO TGP

Strong discount on

Tennessee is

expected to persist

through (2016-17)

Higher prices enable and

ongoing build-out, and

basis narrows even more

Lower discount

once buildout is

completed

(2018-20)

ILLUSTRATIVE ONLY

14

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

1Q16 operating performance

BENCHMARK

PRICES

(HENRY HUB)

Differential

to

Henry Hub

1

Operating

expenses

3

ACTUAL

SELLING

GAS PRICES

OPERATING

NET BACK

G&A

4

Corporate

tax

5

NET PROFIT

AFTER TAX

EBITDA

DD&A

6

Based on transportation

cost and marketing fee for

pipeline transportation to

end markets; can be

varied by projects

(1) Economics of Global Shale Gas Development, CWC school(2) Asset retirement obligations

$3.4/MCF NYMEX

FUTURES PRICES BY 2021

A fee charging third-party

well interests for using

owned gas gathering system

and compressor station;

project-specific (might not

be applicable with future

projects)

Midstream

revenue

2

All costs charged by the

Operator to manage the

assets (covering lease, well

workover cost, production

facility, pipeline, processing

plants, etc.)

Allocated portion of

overhead costs

associated with

managing the asset

(including payroll,

research, rent, office

expenses, etc.)

No tax in 1Q16

given potential tax

deductions from

the acquisition

Calculated

on developed

properties (PDP

and PDNP)

including ARO(2)

and related

estimated reserves

Majority of

impact from

price increase

goes to the

bottom line

CHAFFEE CORNERS’ 1Q16 OPERATING PERFORMANCE

Unit: $/McfNOTE: FIGURES COULD VARY

MONTH BY MONTH; MIGHT

NOT BE APPLICABLE TO

FUTURE PROJECTS

1 2 3 4 5 6

15

Requires drilling only ~6 wells per year to maintain production

Asset has significant additional drilling inventory and can maintain current production levels for 20-30+ years

Operating costs are low driven by

(i) modular facilities design

(ii) operator capability

(iii) current commodity price environment

Source: Fund team analysis

ILLUSTRATIVE TARGET PRODUCTION (NET TO BANPU)

Unit: Mcfd

Chaffee Corners output targets

0

5,000

10,000

15,000

20,000

25,000

30,000

ม.ค.-16

ม.ิย.-16

พ.ย.-16

เม.ย.-17

ก.ย.-17

ก.พ.-18

ก.ค.-18

ธ.ค.-18

พ.ค.-19

ต.ค.-19

ม.ีค.-20

ส.ค.-20

ม.ค.-21

ม.ิย.-21

พ.ย.-21

เม.ย.-22

ก.ย.-22

ก.พ.-23

ก.ค.-23

ธ.ค.-23

พ.ค.-24

ต.ค.-24

ม.ีค.-25

ส.ค.-25

16

Concluding thoughts

Drivers of current opportunities available in the market

Long-term global markets (for both oil and gas) affected by developments in the USA

Continue to actively explore synergistic opportunities

Low commodity price environment for both oil & gas

Big changes in midstream infrastructure (e.g., pipelines, petrochemicals, LNG, etc.)

Changing player landscape and potential for consolidation (due to economies of scale)

US to become a leading exporter of natural gas (to Europe and Asia)

US to become marginal producer for oil as unconventional projects lower breakeven costs ahead of other sources of supply

17

Financial summary

Power business

Coal marketing

Coal operations

Focus: shale gas

5

4

3

2

1

18

2016e OUTPUT (ROM EQUITY BASIS)

Wollongong

PKCT

Airly

NeubeckAngus Place

Clarence

Springvale

Mandalong Myuna

Newstan

Sydney

PWCS

Newcastle

Inglenook

Project

Underground mine

Port

Power station

RoadRail

C&M 4

WESTERN OPERATIONS: 2016e: 5.7 Mt

NORTHERN OPERATIONS: 2016e: 7.8 Mt

NCIG

2016e output: 13.5 Mt

KEY UPDATES

Production

1Q16 Equity ROM: 3.6 Mt (down 17% YoY). (Note: 1Q15 included production from Angus Place and Charbon).

Following the 2014/15 decision to focus on higher margin operations, the group continues to deliver cost improvements, production and productivity records.

ASP

1Q16: ~A$63/t vs 4Q15: ~A$63/t – with ASP maintained through a focus on domestic markets.

1Q16 Sales volume up 22% QoQ (as Mandalong returned to full production after its 4Q15 LW changeover).

Domestic: export split 70%:30% (2015: 62%:38%) –responding to continued export price weakness.

Note 1: Mannering placed on “Care & Maintenance” November 2012 – benefiting from new production sharing arrangement with neighbouring mine.

Note 2: NCIG = Newcastle Coal Infrastructure Group; PWCS = Port Waratah Coal Services; PKCT = Port Kembla Coal Terminal.

Note 3: Newstan (1 August 2014) and Angus Place (February 2015 ) placed on care & maintenance.

Australia coal: operational and financial summary

1Q16 YoY QoQ

Sales revenue A$216M ▼ 8% ▲ 22%

EBITDA A$40M ▼ 12% ▲ 514%

PBT A$(4)M ▼55% ▲86%

NPAT A$(3)M ▼55% ▲86%

Gearing(Net debt to net debt + book value of equity)

39%

FINANCIAL SUMMARY

19

Australia coal: Northern operations quarterly output

COAL OUTPUT (Mt)1

CV: 6,700 kcal/kg2

2.0

1.1

1.8

0.8

1.8

1.2

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16e

0.5 0.5 0.4 0.3 0.4 0.5

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16e

Mandalong

Quarterly production up 134% QoQ, but down 12% YoY, with 4Q15 production impacted by a known dyke and a planned longwall changeover.

1Q16 – Production recommenced in early January, 10 days ahead of budget, with the mine also benefitting from a record ramp-up.

Myuna

Quarterly production up 18% QoQ, but down 23% Y0Y.

Restructured Myuna in late 2015 – to maintain production levels and provide greater flexibility utilising less resources.

1Q16 – While production has improved, Myuna continues to be impacted by variable conditions. The return of two continuous miners from overhaul in April should lead to further improvement.

COMMENTS

Decision made to return mine to care and maintenance – effective 1 August 2014

8Mt Northern Coal Services state approval received, underpinning the Newstan extension project for when coal industry economics improve.

Note: 1 ROM output on an equity basis2 CV figures are air-dried basis3 Longwall

LW3 MOVE SCHEDULE

Mth 1

Mth 2

Mth 3

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16e 3Q16e

3 wks

3 wks

MYUNA

COAL OUTPUT (Mt)1

CV: 6,700 kcal/kg2

NEWSTAN EXTENSIONMANDALONG

3 wks

20

Springvale:

Production up 29% QoQ and 25% YoY - achieving a new quarterly and monthly record.

Legal challenge to Springvale approval process.

Clarence:

1Q16 production down 23% QoQ and 17% YoY, with the mine on development activities.

A new daily production record was achieved in March.

Following the return of the recently overhauled FCT, the introduction of a new FCT operating regime, a new daily FCT development record was also achieved in the quarter.

Airly: Production up 7% QoQ and 21% YoY – achieving new daily and weekly production records.

OTHER OPERATIONS

COAL OUTPUT (Mt) 1

CV: 6,700 kcal/kg 2

0.6 0.60.0

0.6 0.70.4

COAL OUTPUT (Mt) 1

CV: 6,700 kcal/kg 2

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16e

1 ROM output on an equity basis: Angus Place and Springvale 50%, Clarence 85% and Charbon 95% 2 CV figures are air-dried basis3 Longwall4 Flexible Conveyor TrainNote: Following material overflow in reject emplacement area at Clarence in July, authorities were notified and actions were taken in compliance with NSW Environmental Protection Agency Clean-up Notice

COMMENTS

Mth 1

Mth 2

Mth 3

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16e 3Q16e

LW 3 MOVE SCHEDULE

12 wks

SPRINGVALE CLARENCE

0.7 0.6 0.7 0.80.5 0.7

COAL OUTPUT (Mt) 1

CV: 6,700 kcal/kg 2

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16e

0.50.2 0.3 0.1 0.2 0.2

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16e

2 wks

Australia coal: Western operations quarterly output

5 wks

21

Continued focus on cost control and productivity, driven by step-change in productivity programme and increasing LW automation.

On a like-for-like basis, productivity continues to improve, with several production records achieved across the group.

1Q16 over 4Q15 cost improvement driven by increased volumes (primarily from Mandalong and Springvale).

Targeting a further reduction in unit cost on a full-year basis.

AVERAGE PRODUCTION COSTS COMMENTS

0

10

20

30

40

50

60

FY14

General expenses

Open-cut contractor cost

Repairs & maintenance

Stores & supplies

Labour

Depreciation

* These figures do not include selling, distribution and royalty costs; based on ‘sold’ production

$49

A$/t

Cash overhead

$50$49

1Q 2Q 3Q 4Q

2015

FY15 1Q FY16E

$46 $45

$54

$48

2016

$52

Coal handling & preparation

1 Flexible Conveyor Train

Australia coal: operating costs

FY13

$52

22

Indonesia coal: operational and financial summary

PRODUCTION OUTPUT 2016

FINANCIAL SUMMARY

East Kalimantan

Bunyut Port

Balikpapan

Palangkaraya

Banjarmasin

Central Kalimantan

South Kalimantan

Kitadin -Embalut1.1 Mt

Indominco16.0 Mt

Trubaindo6.2 Mt

Bharinto2.4 Mt

Jorong1.2 Mt

Samarinda

Jorong Port

Bontang Coal Terminal

Captive coal-fired power project

KEY UPDATES

2016 target: 26.9 Mt ● Indominco : 1Q16 production was higher than plan

due to exposed coal inventory from end of 2015 and good weather condition at Indominco area.

● Trubaindo: 1Q16 production output was slightly lower than target due to rainy days affecting mine production.

● Bharinto: 1Q16 production is according to target● Kitadin Embalut : 1Q16 production is according to

target● Jorong: 1Q16 production is according to target

1Q16 YoY QoQ

Sales revenue US$331M ▼ 23% ▼ 14%

EBITDA US$50M ▼33% ▼ 25%

NPAT US$23M ▼ 39% ▲ 216%

Gearing(Net debt to net debt + book value of equity)

n.a.

CAPEX US$5M

23

0.3 0.3 0.3 0.3 0.3 0.3

0.3 0.3 0.3 0.3 0.3 0.3

CV: 5300 kcal/kg**

STRIP RATIOS (bcm/t)

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16e

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16e

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16e

5.5

10.9

5.4

10.5

4.6

13.8

Indonesia coal: quarterly output

Note: *Output figures are 100% basis**CV figures are air-dried basis

JO

RO

NG

EMBALUT AND JORONGINDOMINCO - BONTANG TRUBAINDO - BHARINTO

E B

LO

CK

TD

MY

W B

LO

CK

IND

OM

INC

OT

DM

Y

TR

UB

AIN

DO

BH

AR

INT

OT

RU

BA

IND

OB

HA

RIN

TO

EM

BA

LU

TJ

OR

ON

GE

MB

AL

UT

EA

ST

WE

ST

COAL OUTPUT (Mt)*CV: 5950 - 6250 kcal/kg**

COAL OUTPUT (Mt)*CV: 6550 - 6700 kcal/kg**

COAL OUTPUT (Mt)*

CV: 5800 kcal/kg**

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16e

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16e

3.2 3.2 2.9 2.8 3.1 3.4

0.2 0.30.3 0.4

0.80.60.6 0.7

0.6 0.6

4.04.2

3.8 3.8 3.9 4.0

STRIP RATIOS (bcm/t)

20.7

7.3

10.4

14.0

8.3

6.6

17.1

9.5

3.8

14.4

11.4

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16e

1.8 1.9 2.0 1.71.2 1.2

0.50.7 0.7

0.9

0.5 0.6

STRIP RATIOS (bcm/t)

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16e

2.72.3

2.6

8.8

6.7

8.2

5.3

2.6

7.8

9.0

7.8

3.6

4.6

12.6

1.7

13.8

7.88.3

6.4

3.9

13.2

1.8

13.6

6.3

9.0

6.4

4.1

11.0

24

-

10

20

30

40

50

60

70

FY13FY14 1Q 2Q 3Q 4Q FY15 1Q FY16

Indonesia coal: total costs

* Repair and maintenance, salaries and allowances, etc.

COMMENTS

Continue to implement cost reduction programs:

- Optimize strip ratios, reduce overburden distance, overhaul parts, IPCC optimization

- Lower explosive cost, ship-loading cycle time, barging negotiation

The fall in oil price has also helped ITM to reduce cost further

INDICATIVE AVERAGE TOTAL COSTS

Mining cost

Other production costs*

Depreciation & amortisation

SG&A expenses

Royalty

$52

$59

$52

$42

U$/t

$48$46

2015

FY16

$49

$43

2016

$62

25

CHINA COAL 2016 PRODUCTION

2.7

1.92.1

2.7 2.6

2Q15 3Q15 4Q15 1Q16 2Q16E

BEIJING

Hebi(40%),Henan1.2 Mt

Gaohe(45%),Shanxi

9 Mt

Note: * Output figures are ROM output (100% basis)** CV figures are air-dried basis*** Exchange rate of 1Q156is RMB 6.55/USD

Gaohe

1Q16 production increased from 4Q15 due to good miningconditions.

Market is stabilizing going into 2Q16, but temporarydemand softening due to long Spring festival holiday.

Central Government issued policy to address the oversupplysituation on both short term and long term perspective

Selling price declined due to weak market demand andaddition of low price for low CV coal in Gaohe product mix

Hebi

Underground working area improvements: enhance dustcontrol in underground working areas; closely monitoringthe gas and CO2 conditions in development areas adjacent togoaf(1) and increase safety management on gas control.

OPERATIONAL UPDATES

Summary 2Q15 3Q15 4Q15 1Q16

Sales (Mt) 2.2 1.9 2.2 1.9

ASP (US$/t) 55 49 41 37

Revenue (US$ M) *** 107 87 91 69

COGS (US$/t) 39 40 42 36

EBITDA (US$ M) 44 9 12 21

OperationProject

OperationProject

POWER

COAL

Gaohe

CV: 6500-8000 Kcal/kg**

2Q15 – 1Q16 COAL OUTPUT (Mt ROM)

2Q15 3Q15 4Q15 1Q16 2Q16E

China coal: operational summary

Hebi

CV: 5300-6800 Kcal/kg**

0.3 0.3 0.3 0.3 0.3

Note: (1)Part of a mine from which the mineral has been partially or wholly removed

26

UNST KHUDAG AND ALTAI NUURS PROJECTSTSANT UUL PROJECT

* Mineral Resources Authority of Mongolia

Unst Khudag Project

Received MRAM* approval of the coal mining Feasibility Study

Continuing water resource modeling and development

Currently conducting preliminary feasibility program for coal conversion and power facility scenarios including technical and market related studies

Altai Nuurs Project

Completing preparations to apply for the mining licenses.

Product testing results have been favorable which indicates suitability for certain market segments in China.

The technical pre-feasibility study and market study for commercial-scale development will be conducted in 3Q16

OVEN PLANT INSTALLATION

Mongolia coal: project developments

27

Financial summary

Power business

Coal marketing

Coal operations

Focus: shale gas

5

4

3

2

1

Looking ahead6

28

SUPPLY TRENDS DEMAND TRENDS

-27 Mt-20 Mt

+5 Mt +2 Mt

-1 Mt

+1 Mt

-13 Mt -1 Mt

Indonesia Australia RussiaColombia S.Africa Others India OthersOther

N.Asia

EuropeChina*

Uncertainty of demand in China and falling demand in India and

Europe continues depressing market. A headline Japanese thermal

contract price was settled at US$61.60/t, around US$10/t premium over

spot price, should lead to a change in price setting process in Asia.

Note: *includes anthracite and lignite

-15 Mt -10 Mt -10 Mt

+9 Mt

-9 Mt

+5 Mt

(-5 to -15 Mt)

USA : low gas prices; production cuts deepen; coal company bankruptcy; thermal exports mostly uneconomic.

Russia : exporters boost coal export to Asia due to higher prices; strengthened Rouble cuts producer profitability

Indonesia : continues to suffer from China

and India declines; loss significant market share

in China as they respond to changes

slower than Australia; huge oversupply on

LCV coal, bad weather

Australia : bad weather, maintenance and negotiation tactics

tighten supply; take-or-pay continues to force producers to export

more coal; cost reduction and currency

depreciation assist

Colombia : lowest cost supplier in Europe; depreciation of local currency improves competitiveness; wage negotiation with labourunion, more shipments to Asia

South Africa : depreciation of local

currency improves competitiveness;

production problem and bad weather tighten

supply; limited rail capacity; uncertain

expansion

Supply tightness in the first quarter comes from various issues included

bad weather, rail and port maintenance, price negotiation tactics but

production capacity cuts still move slowly.

Europe : low gas

price; gas-switching;

growing environmental

pressures; coal plant

retirements and

increased renewable

energy will lower

import demand

China : weak power demand; rationalizing overcapacity in coal and steel; reduced work days; continued protectionist policy; stabilizing coal prices

India : import declines due to weak power demand and increased domestic coal production; financial loss of power distributor companies limits their ability to buy/deliver power; high coal stocks; tightening environmental norms on ash disposal and water scarcity

Other Asia :

Philippines, Malaysia,

South Korea and

Taiwan are expected

to add around 14 Mt

of coal demand in

2016

GlobalGlobal USA

Global thermal coal market trends: 2016 vs 2015

29

COMMENTS

Note: *includes anthracite and lignite imports/exports

CHINA ANNUALIZED ACTUAL IMPORT 1Q13-1Q16*

CHINA THERMAL COAL IMPORTS/EXPORTS*

137178

235 252229

156 151

18 11 8 6 5 4 10

2010 2011 2012 2013 2014 2015 2016F

Import

Export

Sources: Banpu MS&L Estimates

Unit: Mt

Unit: Mt

CHINA

Government stimulus package to boost property sector, helps to boost demand

Strengthened Chinese demand through March seems to be temporary due to extreme cold wave in March, followed by good rains

Tight domestic supply seems to continue to May/June as stricter government safety/policy measures prevented several mines from resuming operations after Chinese New Year

Limiting of domestic coal output had helped prices hold steady

UN’s sanction on North Korea will reduce anthracite shipment to China, effective early April

» Results in additional import requirement

Oversupplied conditions will continue. Although there was central government announcement of significant production cuts, it’s expected to move slowly in the local government level due to social stability concern

Source: www.sxcoal.com/cn 11 April 2016

CHINA DOMESTIC COAL PRICES

Unit: RMB/t

251 242 244 270 284232 199 201

153 160 167 145 148

7 7 6 5 7 4 4 5 2 5 5 4 10

1Q13 2Q133Q134Q13 1Q14 2Q143Q144Q14 1Q15 2Q153Q154Q15 1Q16

Import

Export

China thermal coal market review

200400600800

1,000

Ma

y-1

2J

ul-

12S

ep-1

2N

ov

-12

Ja

n-1

3M

ar-

13M

ay

-13

Ju

l-13

Sep

-13

No

v-1

3J

an

-14

Ma

r-14

Ma

y-1

4J

ul-

14S

ep-1

4N

ov

-14

Ja

n-1

5M

ar-

15M

ay

-15

Ju

l-15

Sep

-15

No

v-1

5J

an

-16

Ma

r-16

> 5,800 kcal/kg> 5,500 kcal/kg> 5,000 kcal/kg

416382

343

30

India thermal coal market review

COMMENTS

INDIA THERMAL COAL IMPORTS*

INDIA ANNUALIZED ACTUAL IMPORT 1Q13-1Q16

Sources:: Salva Report India, Banpu MS&L Estimates

131

159

135120 126

163 168

197

171 180

142161 157

1Q13 3Q13 1Q14 3Q14 1Q15 3Q15 1Q16

Unit: Mt

Unit: Mt

Still weaknesses in the economy as industrial production growth continues sluggish

Impressive domestic coal production and increasing protectionism reduces coal import in 2016

Indian inland power plants under government control seem to stop using imported coal for blend following government guidance to consume domestic coal

Coal India Limited (CIL) announced price cuts of 10-40% for domestic coal in an attempt to compete with imports

The Indian government raised the clean energy tax to Rupee 400/mt from Rupee 200/mt starting April 2016

» Clean energy tax reduce interest for low CV Indonesian coal import

» Petroleum coke imports will remain high as it was exempted from the clean energy tax

INDIA

Note: *includes lignite grade imports (approximately 25% - 30%)

6887

107

136

163 164154

2010 2011 2012 2013 2014 2015 2016F

31

(1) Excluding Mongolia coal

(2) Sales from Indonesia are included on 100% basis, sales from Australia and China are included on equity basis

COAL SALES(1) SOURCE – DESTINATION ANALYSIS 2016 GLOBAL COAL SALES(2) 2016 BY REGION

THAILAND

HK

CHINA

TAIWAN

ITALY

4.0

1.3

5.0

0.1

0.8

0.6 Mt

INDIA

5.4 Mt

9.1 Mt

JAPAN

1.2

5.6

6.8 Mt

2.3 Mt

MALAYSIA

0.3 Mt

INDONESIA

4.0 Mt PHILIPPINES

2.2 Mt

2.1 Mt

0.1 Mt

AUSTRALIA

9.2 Mt

OTHERS1.01.0

2.0 Mt

Indonesia coal

Australia coal

China coal

Japan, 15%

Korea5%

Taiwan, 5%

China, 20%**

Australia20%

SE Asia19%

India12%

* Illustrative target

** Include coal sales from domestic production in China

S KOREA

1.3

2.3 Mt1.0

Banpu group coal sales 2016e

46.3 Mt(2)

32

Fixed

57%

14%

7%

22%

Fixed

Indexed

28.5 Mt*

INDONESIA COAL

Indicative 2016 Banpu coal sales pricing status

Unpriced

Unsold

36%

32%

13%

6%

7%6%

Indexed

Fixed Export

Domestic: long-term export parity

13.8 Mt*

AUSTRALIA COAL

Domestic: legacy

UnsoldUnpriced

Note: *Target Sales

33

* Included post shipment price adjustments as well as traded coal** The Newcastle Export Index (previously known as the Barlow Jonker Index – BJI)

ITM ASP eased due to general market

weakness

– 1Q16 ASP was 12% down Q-o-Q

Centennial ASP firmed, weakens on

export has been protected by premium

tier domestic pricing

– 1Q16 ASP was 2% down Q-o-Q

NEX benchmark prices remain weak

ITM ASP 1Q16 $49.2* (-12% QoQ)

CEY ASP 1Q16 A$64.8* (-2% QoQ)

NEX** May 12, 2016 $50.78

Unit: $/t

0

20

40

60

80

100

120

140

160

180

200

Ja

n-0

7

Ju

l-0

7

Ja

n-0

8

Ju

l-0

8

Ja

n-0

9

Ju

l-0

9

Ja

n-1

0

Ju

l-10

Ja

n-1

1

Ju

l-11

Ja

n-1

2

Ju

l-12

Ja

n-1

3

Ju

l-13

Ja

n-1

4

Ju

l-14

Ja

n-1

5

Ju

l-15

Ja

n-1

6

Monthly NEX

Quarterly ITM ASP

Quarterly Centennial ASP

BANPU ASP VS BENCHMARK PRICES COMMENTS

Banpu ASPs vs thermal coal benchmark prices

34

Financial summary

Power business

Coal marketing

Coal operations

Focus: shale gas

5

4

3

2

1

Looking ahead6

35

Banpu Power: 1Q16 overview

BANPU POWER EQUITY CAPACITYUNIT: GW

20152010

1.0

2020e

2.5

1.4

THAILAND

BLCP strong

EBITDA: $49M

JAPAN – SOLAR

One additional

Japan project:

Yamagata to COD

in 2017 (20 MW)

Hino (3.5 MW) will

COD in May 2016

LAOS

Hongsa: $43M

EBITDA

CHINA

BIC: EBITDA

increased 24%

from last Q due to

lower coal price

SLG: completed

2nd units;

foundation

construction and

3rd batch auxiliary

equipment bidding

CHINA – SOLAR

Right to acquire

78.5 MW in

Shandong province

60 MW to COD

by June 2016

Renewable

Conventional

TARGET

36

17

13

22

-2 -1-3

1Q15 4Q15 1Q16

USD million

Energy Payment (EP)

Dispatch (%)

Q-Q : -1.5%Y-Y : 20.9%

Q-Q : 73.8%Y-Y : 24.9%

Total revenue

EBIT

EBITDA

Q-Q : -0.1%Y-Y : 18.1%

Q-Q: 72.5 %Y-Y: 38.8%

Based on Banpu’s 50% interest

Equity income

Thailand Power: BLCP in 1Q16

USD million

Availability Payment (AP)

Q-Q : 25.6%Y-Y : 18.4%

12

FX Loss

14

20

Q-Q : 77.4%Y-Y : 25.8%

124.5 133.

1 145.6

1Q15 4Q15 1Q16

53.9 50.8 63.8

1Q15 4Q15 1Q16

39.6 28.5

49.0

1Q15 4Q15 1Q16

38.8 27.5

48.8

1Q15 4Q15 1Q16

65.5 77.4 77.4

1Q15 4Q15 1Q16

80.9 99.4 97.9

1Q15 4Q15 1Q16

FX Loss

37

28.9

53.5 43.1

3Q15 4Q15 1Q16

(5.5)

9.4

1.0

(3.4)

0.4

0.3

3Q15 4Q15 1Q16

27.9

53.3 41.4

3Q15 4Q15 1Q16

35.7

84.4 76.1

3Q15 4Q15 1Q16

12.1

35.5 25.4

3Q15 4Q15 1Q16

23.6

51.4 49.9

3Q15 4Q15 1Q16

USD million

Energy Payment (EP)

Dispatch (%)

Q-Q : -9.8%

Q-Q : -19.5%

Total revenue

EBIT

EBITDA

Q-Q :-28.4 %

Q-Q: -86.4%

Based on Banpu’s 40% interest

Equity income

Laos Power: Hongsa in 1Q16

USD million

Availability Payment (AP)

Q-Q : -2.8%

(8.9)

1.3

FX Loss

FX gain

9.8

Q-Q : -22.3%

93.3 94.8100.0

3Q15 4Q15 1Q16

FX gain

38

100.890.5

102.3

41.4

51.059.9

34.333.2

36.7

1,730

1,9981,928

2,0031,766

1,516

1,820

2,122

1,743

0.420.390.42

0.35 0.310.37

0.410.37

0.42

327 315

429

417 407

512

310 302362

1Q15 4Q15 1Q16 1Q15 4Q15 1Q16 1Q15 4Q151Q16 1Q15 4Q151Q16 1Q15 4Q151Q16

1Q15 4Q151Q16 1Q15 4Q15 1Q16 1Q15 4Q15 1Q16 1Q15 4Q151Q16 1Q15 4Q151Q16

1Q15 4Q15 1Q16 1Q15 4Q15 1Q16 1Q15 4Q15 1Q16 1Q15 4Q15 1Q16 1Q15 4Q151Q16

124.9

56.5

70.6

105.0

123.6107.5

119.0

99.8 77.9

China power: BIC in 1Q16 (100% basis)

Note: *Unaudited figures, **Including transportation

LuannanHebei Province

Power 100 MW

Steam 128 tph

(Banpu 100% )

ZhengdingHebei Province

Power 73 MW

Steam 370 tph

Chilled water 35 MW

(Banpu 100%)

ZoupingShandong Province

Power 100 MW

Steam 450 tph

(Banpu 70%)

Sales*

(RMB$M)

EBITDA

(RMB$M)

Utilization

(hours)

Power tariff

(RMB/kwh)

Coal price**

(RMB/t)BIC 1Q15 4Q15 1Q16

Higher utilization hours and lower coal price helped lessen the impact on lower power tariff, thus both 1Q16 Sales and EBIDA were higher than 4Q15 and YoY.

1Q16 sales were lower than 4Q15 due to lower power tariff and utilization hours.

However, lower coal price lead to higher EBITDA.

Higher utilization hours and lower coal price helped lessen the impact on lower power tariff, thus both 1Q16 Sales and EBIDA were higher than 4Q15 and YoY.

39

Shanxi Lu Guang update

2nd units, chimney and cooling tower pile foundation construction has been completed

3rd batch of auxiliary equipment bidding has been finished.

Awaiting to short listed Lender’s internal approval to provide loan to the project

DISCLAIMER The views, information and indications expressed here including forward looking targets and indications are illustrative only, are subject to change, may be based on incorrect assumptions, and have not

been independently verified. No representation or warranty is made as to the accuracy, completeness or reliability of the views, information as indications expressed here. This slide should not be relied upon as a

recommendation or forecast by Banpu Public Company Limited. Nothing in this slide should be construed as either an offer to sell or a solicitation of an offer to buy or sell shares in any jurisdiction.

INDIRECT COOLING TOWER X PILLAR

CONCRETE CONSTRUCTION

40

Japan solar update

* Banpu effective ownership is between 40-75%

Hino

(COD 2016)

3.5 MWAC

Awaji

(COD 2017)

8 MWAC

Mukawa

(COD 2018)

17 MWAC

Nari Aizu

(COD 2018)

20 MWAC

Olympia

10 MWACTokyo

One additional project: Yamagata (20MWAC)

74.1 MWAC equity 2016-18

20-year PPA, ¥36-40/kwh tariff(c.¢29-32/kwh)

Average capex of c.US$3.5M/MWAC

In the process of adding capacity

Hino (3.5MW) to COD by 20th May 2016

Construction phase

Operation phase

Development phase

Hokkaido

Honshu

ShikokuKyushu

Yabuki

(COD 2018)

7 MWAC

Onami

(COD 2018)

16 MWAC

Yamagata

(COD 2017)

20 MWAC

41

China solar: investment rationaleS

TR

AT

EG

ICF

ITR

EG

UL

AT

ION

SR

ISK

SF

INA

NC

ING

EC

ON

OM

ICS

Banpu Power expansion in renewables in Asia-Pacific

High growth target for renewables to be achieved by 2020-25

Leverage on practical knowledge on local power industry and conducting business in local environment

Supportive regulation from >150GW installation target for solar by 2020

Part of government plan to meet with COP 21 commitment

Policy support and incentives are in place

Supportive policy implementation may face some time lag

Construction risk on quality assurance and meeting with project schedule

Enhance operation performance by engaging competent technical advisor to set proper standard

Develop sound relationship with local stakeholders to ensure smooth integration into local community

Preferable financing terms with relationship bank

One of the fastest growing solar markets in the world (from 3GW in 2011 to >17 GW in 2015)

Stable income from FIT and full dispatch

Preferential tax policy

Attractive reasonable return

17

3

2011 2015

RENEWABLE CAPACITY IN CHINA

Unit: GW

China solar: investment progress

Right to acquire 100% in four solar project by BPP

78.5 MW already approved for investment (of which 60 MW will start their CODs by June 2016)

Estimated 70:30 DE financing; total project cost RMB 604M or $93M

Approximately RMB 1.0 per kwh Feed in tariffs & subsidies

(1) Only tentative D:E ratio subject to actual refinancing at later stage

Shandong

Tianjin Liaoning

Beijing

Hebei

Henan Jiangsu

Anhui

Henan

Zouping

100 MW, 450 tph

Cangzhou

Zhengzhou

WuheXuzhou

Dalian

China solar: photos from the sites

44

Financial summary

Power business

Coal marketing

Coal operations

Focus: shale gas

5

4

3

2

1

Looking ahead6

45

EX

TE

RN

AL

E

VE

NT

SC

OR

PO

RA

TE

E

VE

NT

S

DIR

EC

TIN

DIR

EC

T

Indonesia's HBA coal price drops 15% on year to record low $57/t

BoT and ADB slash 2015 GDP growth forecast from 3% to 2.7%

3Q15 FS: THB M 72.3 net loss

3Q15 results presentation

COD of Hongsa’s 2nd

unit

Key external and corporate events

China to

reduce ratio

of coal in

primary

energy from

66% to 50%

BOT waits for signal

to increase rate

IMFpoised to admit RMB in elite currency basket

ADB expects higher GDP for China at 6.9%

Credit rating agency affirms

A+ with stable outlook

for Banpu’ssenior unsecured

debentures

Indonesia

cut

production

by 20%

missed the

target

China

cuts CFP

tariff by

CNY

0.03/kwh

Tepco

agreed with

Glencore a

floating

price for

imported

coal

4Q15 Analyst

meeting

4Q15 SET

Opportunity Day

Announced

Bt0.50/share

2H15 dividend

2015 Result

Announcement

China GDP

was 6.9% in

2015;

expected

6.7% in 2016

China

announced

no approval

of coal mines

in the next

three years

COP21

Paris’s

agreed to 2°C

temp increase

target

4Q15 1Q16 2Q16

Indonesia to relax

foreign ownership

rules in power,

e-commerce and

retail sectors

Myanmar’s

government

target coal as

main source

China’s power use

may rise mildly in

2016

HBA thermal

coal price up

1.4%

Vietnam

demanding more

Australian coal

BOT likely to

keep rates on

hold for rest

of 2016

ADB cuts

Thai

growth

forecast

Announced

US$554M

investment

plan 2016-20

Announced plan to

issue 1.29b new

shares in rights

offering (raise up

to THB 6.45Bn)

Full commercial

operation of Hongsa

Power Plant

First investment in

unconventional

shale gas

Rights offering

and warrant

issues approved

by AGM

1Q16 result

Announcement on

China solar projects

2H15 Dividend paid

Bt0.5/share

46

Note: ITM and Centennial revenues are consolidated in Banpu income statement.Australia Coal – Third party coal sales included.

*NEX = Newcastle Export Index (formerly Barlow Jonker Index or BJI) It is relevant but not linked to China Coal’s ASP

CHINA COAL

Note: Hebi and Gaohe revenues are not consolidated in Banpu income statement.

SALES (Mt)

AVERAGE SELLING PRICE (US$/t) excl. VAT

REVENUE (US$M)

52 59 48 49 38

1Q15 2Q15 3Q15 4Q15 1Q16

0.8 1.1 1.0 1.1 1.0

1Q15 2Q15 3Q15 4Q15 1Q16

AS

P 6555 49 45 39

1Q15 2Q15 3Q15 4Q15 1Q16

NE

X*

66 60 59 53 51

Equity basis

Equity basis

Domestic

Export

Banpu group Q-Q revenue analysis: coal operations

INDONESIA COAL (ITM)

6.2 5.9 5.9 6.1 5.8

7.1 6.9 6.8 7.1 6.9

1Q15 2Q15 3Q15 4Q15 1Q16

SALES (Mt) 100% basisDomestic

Export

AVERAGE SELLING PRICE (US$/t)

REVENUE (US$M)

428 397 382 383 331

1Q15 2Q15 3Q15 4Q15 1Q16

NE

X*

AS

P

66 60 59 53 51

100% basis

61 57 56 53 48

1Q15 2Q15 3Q15 4Q15 1Q16

AUSTRALIA COAL (CENTENNIAL)

2.3 1.7 2.3 1.8 2.4

3.73.1 3.4

2.83.4

1Q15 2Q15 3Q15 4Q15 1Q16

SALES (Mt)

AVERAGE SELLING PRICE (A$/t)

REVENUE (A$M)

233 198 208 177 216

1Q15 2Q15 3Q15 4Q15 1Q16

AS

P

64 64 61 63 63

1Q15 2Q15 3Q15 4Q15 1Q16

NE

X*

66 60 59 53 51

Equity basis

Equity basis

Domestic

Export

47

447 405 344

190

134 159

53

49 49

1Q15 4Q15 1Q16

Note: Revenue from others is included in Coal Indonesia.

US$ M

690

588552

-20% YoY

Coal Australia

+19% QoQ

-16% YoY

Coal Indonesia

-15% QoQ

-23% YoY

Power

+0% QoQ

-8% YoY

Power

Coal Australia

Coal Indonesia

-6% QoQ

Banpu consolidated sales revenues

48

INDONESIA COALAUSTRALIA COAL

Note: AUD exchange rate – US$ 0.721A$ (Average of 1Q16)

Coal sales Gross margin

1Q15 4Q15 1Q16

17%30%

190

159

Indonesia coal gross margin: 34%

37%34%

US$ MUS$ M Australia coal gross margin: 23%

134

23%

32%

1Q15 4Q15 1Q16

35%37%

331

430396

34%

Banpu consolidated coal gross margin 1Q16: 30%

49

73 6551

3

(9) (10)

45

26 36

32

38 42

1Q15 4Q15 1Q16

Banpu consolidated EBITDA

USD million

152

121

Power Coal Australia Coal China Coal Indonesia

Power

Coal - Australia

Coal - China

Coal - Indonesia

-30% Y-Y

-21% Q-Q

+38% Q-Q -19% Y-Y

+10% Q-Q

+34% Y-Y

120

-21% YoY

Flat QoQ

50

Banpu: 1Q16 consolidated NPAT

21

OTHERS

(5)

NON-

RECURRING

ITEMS

NPAT

FX LOSS

OPERATING

PROFIT

DERIVATIVES

(7)

POWER

33

RECURRING

PROFIT

OTHER

RECURRING

ITEMS

(33)

61

1Q16 NET PROFIT AFTER TAX

UNIT: $M

1Q15 NET PROFIT AFTER TAX

UNIT: $M

63

COAL

41

POWER

22

FX LOSS

DERIVATIVES

2

RECURRING

PROFIT

OPERATING

PROFIT

24

NON-

RECURRING

ITEMS

(6)

OTHERS

NPATOTHER

RECURRING

ITEMS

(33)

4Q15 NET PROFIT AFTER TAX

UNIT: $M

COAL

18

OPERATING

PROFIT

45

(6)

(32)

OTHER

RECURRING

ITEMS

RECURRING

PROFIT

7

(41)

NPATNON-

RECURRING

ITEMS

OTHERS

FX LOSS

DERIVATIVES

POWER

27

COAL

28

FINANCE

CHARGES

MINING PROPERTIES

(15)

(7)

(5)

(1)

(11)

(10)

(1)

(15)

(32)

+21% Q-Q

+54% Y-Y

+54% Q-Q

-33% Y-Y

Derivatives• Gas Oil ($0.5M)• FX Forward ($3.7M)• IRS* ($2.8M)

FX loss• Banpu ($12.9M)• ITM ($0.6M)• CEY ($1M)

*IRS = Interest rate swap

51

Rights offering and warrants issue

USE OF PROCEEDS

Debt repayment to

improve D/E from

1.6x to 1.2x*US$366M

(FULL SUBSCRIPTION)

RATIONALE

Strengthen Banpu’s capital structure

Short-term funding for investments

Provide room for further gearing to pursue medium to long term growth opportunities

Less dependency on market condition

* FX as of 11th May 2016 at Bt 35.25/share* Based on 31st Dec 15 balance sheet

OFFER PRICE

Bt 5/share

RIGHTS OFFERING

(EXISTING:NEW)

2:1

WARRANTS

(NEW SHARE:WARRANT)

1:1

OFFER PRICE

Bt 5/share

RO and Warrants timeline

6

June

1 -5

June

8 - 9

June

15 - 16

June

29 – 2

Aug Sep

5

Sep

25 - 1

Nov Dec

2

Dec

24 - 2

Feb Mar

2017

3

March

19 - 2

May-Jun

5

Jun

23rd – 25th MayPersonal Check/Draft /cashier check Transfer/ATS

26th – 27th May30th – 31st MayOnly Transfer & ATS

MOC Register

First trading

dayfor new

shares

Over-subscription allocation 1st Warrant

NotificationDates

2nd WarrantNotificationDates

3rd WarrantNotificationDates

4th WarrantNotificationDates

1st warrant Exercise

date

2nd warrant Exercisedate

3rd warrant Exercisedate

4th warrant Expiration date

First trading dayfor warrants

ReturnSubscription

Payment Within6th - 14th June

(Max 14 days after subscription)

15

May

10

May

Book Closing

“SP”Date

53

Financial summary

Power business

Coal marketing

Coal operations

Focus: shale gas

5

4

3

2

1

Looking ahead6

54

POWER OPERATIONS

Quarter highlights

COAL OPERATIONS

Banpu’s first investment in oil & gas, in NE Supercore, Marcellus

78.5MW already approved for investment

60MW for COD mid-2016

* Mineral Resources Authority of Mongolia

Indominco production higher than planned due to good weather

Continue to implement cost reduction programs

Operating costs down 7% QoQ

Increased volumes, primarily from Mandalong/Springvale

Sales volume increased 22% QoQ

New production record at Springvale, Clarence and Airly

Strong EBITDA: $49M

100% power dispatch

$43.1M EBITDA

Unit 3: COD ontime

BIC’s EBITDA increased 24% QoQ

Utilization increased 6% QoQ

SLG completed 2nd units foundation construction and 3rd

batch auxiliary equipment bidding

Gaohe’s production increased from 4Q15

Hebi’s underground working area improvements

Mongolia received MRAM* approval

One additional project: Yamagata to COD in 2017 (20MWAC)

Hino to COD later this year (3.5MWAC)

NEW INVESTMENTS

FINANCE

Rights offering and warrants issue: US$366M (full subscription)

55

Horizontal integration: key themes

EX

IST

ING

DOWNSTREAMMIDSTREAMUPSTREAM

COAL RESOURCE

DEVELOPMENT, MINING

COAL LOGISTICS,

TRADING, MARKETING

COAL-FIRED POWER

GENERATION

GAS-FIRED & RENEWABLES

BASED POWER

FUEL PROCUREMENT,

CHEMICALS MARKETING

UNCONVENTIONAL

SHALE GAS

NE

W

UN

DE

R

EV

AL

UA

TIO

N

SMART ENERGY SYSTEMSREGIONAL ENERGY &

CHEMICAL MIDSTREAM

OTHER STRATEGIC

ENERGY RESOURCES

NEW ENERGY RESOURCES SUPPLY CHAIN MANAGEMENT SMART ENERGY

BA

NP

U P

OW

ER

Appendices

58

* Drilling, completion & tie-in costs; ** Estimated ultimate recovery; *** The New York Mercantile Exchange (NYMEX) strip is the average of the daily settlement prices of the next 12 months’ futures contracts on natural gas; **** Estimated based on historical prices for Jan-Mar 2016 and Nymex Henry Hub strip as of April 20, 2016;

ACQUISITION PRICE OPERATING METRICS

EV/1P Reserve

~$0.71/Mcf

EV/ Daily production

~$5,300/Mcf/day

EV/Netundeveloped acre

~$4,300/net acre

EV/Lasttwelve months EBITDA

~10x

Avg. NYMEX gas price 2015

$2.63/Mmbtu

Avg. differential to Henry Hub

$0.53/Mcf

Last twelve months EBITDA

~$11 million

Avg. daily production (2016e)

21 Mmcf/day

Operating net back****(2016e)

c. $1.25/Mcf

SINGLE WELL

ECONOMICS (SOUTH)

Average cost per well (DC&T*)

$6.2 million

Average EUR** per well (South)

~10 Bcf

Avg. well operation breakeven gas price

$0.78/Mcf

Full cycle single well IRR at 04/20/16 NYMEX*** strip

17.4%

Chaffee Corners key metrics

59

Attractive valuation good timing

Source: IHS Transaction Analysis database, as of March 10, 2016

* Based on share price as of 12 April 2016, 1P reserves as of 12/31/2014, shown in Mcf equivalent (@ 1 BOE = 6 MCF)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

Appal

achia

(Mar

-16)

Gulf-c

oas

t onsh

ore

(Aug-

15)

Appal

achia

(Feb-1

6)

Appal

achia

(Dec-

15)

Mid

-continent

(May

-15)

Mid

-continent

(Jun-1

5)

Gulf-c

oas

t onsh

ore

(Jul-15)

ACQUISITION PRICE PER PROVED RESERVES

Unit: $/Mcf

CHAFFEE

CORNERS

AVERAGE

AT $1.2/Mcf

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

Chesa

peak

e E

nerg

y

Cab

ot

Oil

and g

as

Ran

ge R

eso

urc

es

South

west

ern

Energ

y

Ultra

Petr

ole

um

Ric

e E

nerg

y

Rex E

nerg

y

EV/Mcf

EV/MCF MULTIPLE* OF LISTED COMPANIES

Unit: $/Mcf

AVERAGE

AT $1.6/Mcf

60

59

Capex

30

PlanActual

* Capex figures exclude maintenance capex

CAPITAL EXPENDITURES*

Unit: US$ M

•Tsant Uul development•Altai Nuurs exploration

•Limited to committed project capex for time being

• IPCC and BunyutExpansion

• Includes Hongsa, SLG, and Japan Solar

2012-2015

400

124

554193

150

170

201

717

2016-2020

POWER

MONGOLIA

AUSTRALIA

INDONESIA

INDICATIVE ONLY

60

Indonesia coal gross margin 1Q16 : 34%

1Q15 4Q15 1Q16

34%

35%37%

331

Indonesia Coal

1Q15 4Q15 1Q16

Indominco

33%37%

30%

174163

194

1Q15 4Q15 1Q16

41%40%

41%

93

Trubaindo

139

117

1Q15 4Q15 1Q16

Jorong

36% 42% 48%13 12

1652%

1Q15 4Q15 1Q16

13

28% 27% 17%

Kitadin

14 17

430

396

1Q15 4Q15 1Q16

Bharinto

3452

36%35% 52%

1Q15 4Q15 1Q16

TandungMayang

128%

16%

27%

35 3635

37%

US$M

61

NPAT IMPACT 1Q2016

(US$m)

APPROXIMATE FX EXPOSURE (US$m)

NPAT 5% SENSITIVITY 2Q2016

(US$m)

-14

-1

-0.6

-12

NET

AUD

ID R

THB & O THER

Banpu: THB bond and others

3

60

AUD

ID R

THB & O THER

24

0.2

-3

27

NET

AUD

ID R

THB & O THER

NET LIABILITY NET ASSET

Moderate growth

Moderate growth

RBA cut rates 25 bps in May

Slowly recovery GDP

Assuming 5% depreciation of local currencies against USD

CURRENCY EXPOSURE

ITMG: IDR asset and liabilities

CEY: USD asset

Net

-550

FX impact analysis guidance on P&L

62

GEARING RATIOS

Banpu gearing and foreign exchange structure

DEBT FX STRUCTURE

Note: 1 Net debt to book value of shareholders' equity

2 Net debt to enterprise value (enterprise value = net debt + market capitalization as at 31 March 2016)

USD Fixed29%

USD Float23%

AUD Fixed

2%

AUD Float7%

THB Float8%

THB Fixed31%

Total gross debt: US$3.7 billionAs of 31 March 2016

1.18 1.40 1.52

Net debt / Equity1 (x)

54% 58% 60%

Net market gearing2 (%)

Net debt / EBITDA (x)

4.4 5.9

2014 2015 1Q162014 2015

63

Banpu group EBITDA breakdown

Note: all ownership 100% unless otherwise shown.*BIC = Banpu Investment China

43 9 11 22

-4 -2 -4 -2

2 1 3 4

13 12 5 1

3 6 3 3

16 25 25 18

22 21 35 23

Jorong

13 29 55 42

52 37 31 49

4

-1 -2 -3

55 65 71 50

50%

40%

Power & New energy

40%

45%

70%

Gaohe

Hebi

BLCP

HONGSA

BIC*

Zouping

6 6 5 6

Zhengding

4 4 9 10

Luannan

4 3 8 9

& holding companies

65%

Indominco

Trubaindo

Kitadin

AACI OVERHEAD

Unit: US$M

100%

32 34 7 40

Consolidated NOT consolidated

-1 -1 -1 -1

13 13 21 23

Unit: AUD Mil

All figures are 100% basis except for Centennial which is equity basis

112 106 121 120

Bharinto

2Q15 3Q15 4Q15 1Q16

2Q15 3Q15 4Q15 1Q16 2Q15 3Q15 4Q15 1Q162Q15 3Q15 4Q15 1Q16 2Q15 3Q15 4Q15 1Q16

2Q15 3Q15 4Q15 1Q16

2Q15 3Q15 4Q15 1Q16

2Q15 3Q15 4Q15 1Q16

2Q15 3Q15 4Q15 1Q16

2Q15 3Q15 4Q15 1Q16

2Q15 3Q15 4Q15 1Q16

2Q15 3Q15 4Q15 1Q16

2Q15 3Q15 4Q15 1Q16

2Q15 3Q15 4Q15 1Q16

2Q15 3Q15 4Q15 1Q16

2Q15 3Q15 4Q15 1Q162Q15 3Q15 4Q15 1Q162Q15 3Q15 4Q15 1Q16

64

Banpu group net debt breakdown

Note: all ownership 100% unless otherwise shown.

2649 2502 25622122

193 85 225 226

& holding companies

2,776 2,727 2,893 3,241

AUSTRALIA COAL INDONESIA COAL CHINA COAL MONGOLIA COAL

THAILAND POWER

LAOS POWER CHINA POWER

Gaohe Hebi

HONGSABLCP BIC*

100% 65% 45% 40% 100%

50% 40% 100%

720 730 739 709-284 -344 -268 -295

-21 -15 -90 -85 -2 -2 -1 -1

365 323 315 275

-8

0

-9 -15

Unit: AUD Mil

Unit: US$M

Consolidated

NOT consolidated

Net debt

Net cash

2Q15 3Q15 4Q15 1Q162Q15 3Q15 4Q15 1Q16

2Q15 3Q15 4Q15 1Q16

2Q15 3Q15 4Q15 1Q16 2Q15 3Q15 4Q15 1Q16

2Q15 3Q15 4Q15 1Q16 2Q15 3Q15 4Q15 1Q16 2Q15 3Q15 4Q15 1Q16

2Q15 3Q15 4Q15 1Q16

Unit: USD million

Sales revenues – Power (BIC)

Cost of sales

Gross profit*

GPM

Sales revenues – Coal

Total sales revenues*

Gross profit - Coal

Gross profit – Power (BIC)

GPM – Power (BIC)

GPM - Coal

-27%

YoY%

-20%

-21%

-33%

-8%

8%

Note: * Including other businesses

-1%

QoQ%

-6%

-7%

-7%

0%

19%

49

(374)

179

32%

1Q16

552

497

151

24

49%

30%

53

(445)

245

36%

1Q15

690

631

226

22

42%

36%

Banpu consolidated : operating profit

49

(407)

180

31%

4Q15

588

536

163

20

41%

30%

65

66

Unit: USD million

Gross profit

GPM

SG&A

Royalty

Other income

EBIT

EBITDA

EBIT - Coal

EBIT - Power

Income from associates

EBITDA - Coal

EBITDA - Power

-27%

-25%

-21%

YoY%

Other expenses - Operations

179

32%

(67)

(52)

8

78

120

1Q16

-

-1%

16%

-1%

QoQ%

245

36%

(91)

(69)

4

103

152

1Q15

75

28

14

120

32

-

Banpu consolidated : operating profit

180

31%

(89)

(48)

9

67

121

4Q15

32

35

14

83

38

-

11

19%14%

-49%43%

38

40

78

42-6%10%

-35%

34%

67

Note: * Income from non-core assets and other non-operating expenses

Unit: USD million

EBIT

Interest expenses

Financial expenses

Minorities

Non-recurring items*

Income tax (non - core business)

Net profit before FX

Income tax (core business)

Net profit before extra items

FX translations

Net Profit

EPS (US$/share)

-25%

YoY%

-21%

n.m.

-43%

Deferred tax income (expenses)

78

1Q16

(31)

(2)

(9)

(5)

(7)

(6)

(17)

19

15

9

(15)

(7)

16%

QoQ%

n.m.

n.m.

10%

Banpu consolidated : net profit

67

4Q15

Mining property

Gain (Loss) on Derivatives Transactions

(30)

(2)

6

(32)

(16)

(40)

(24)

17

(1)

(41)

(0.016)

12

(6)

(15)

103

1Q15

(31)

(2)

(14)

(1)

(13)

12

(24)

33

(10)

2

0.001

11

(7)

(11)

(5)

(0.002)

68

Unit: USD million

Cost of sales

Gross profit

GPM

Royalty

SG&A

EBIT

Sales revenue

Sales volume (Mt)

Other income

Interest expenses

Financial expenses

Gain (loss) on exchange rate

Net profit

Gain (loss) on derivative

Other expenses

Centennial : income statement

YoY%

-34%

-34%

-22%

-39%

-7%

-16%

12%

n.m.

QoQ%

68%

-15%

20%

n.m.

22%

19%

4%

n.m.

Deferred tax income

1Q15

(132.9)

56.7

30%

(13.2)

(31.2)

14.5

3.7

189.6

2.3

(7.0)

(0.7)

(2.5)

(2.2)

(6.5)

.

-

1Q16

(122.1)

37.4

23%

(10.3)

(20.7)

8.8

3.4

159.4

2.5

(6.3)

(0.8)

(1.0)

(3.0)

(3.7)

-

-

4Q15

(111.5)

22.2

17%

(8.6)

(24.3)

(8.2)

2.8

133.7

2.4

(6.1)

(0.9)

(0.2)

(10.5)

(6.2)

-

11.1

69

Note: 1. Bar width is indicative of the equity production contributions to Centennial2. Production generally responds to the timing of longwall changeovers (i.e. lower production results during a longwall changeover period) 3. Angus Place was put on care and maintenance from February 2015.

Normal production Bolt-up/commissioning

1.81.4

1.01.4 1.4 1.2 1.6 1.5

2.5

1.6 2.2 1.1

2.11.7

2.3

1.7

3.0 3.2

2.5 2.9 3.2

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16e 3Q16e 4Q16e

4.3

Total equity ROM (Mt)

WE

ST

ER

NN

OR

TH

ER

N

LW relocation

2015 2016e

LW move Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Mandalong

(100%)

Springvale

(50%)

3 wks

6 wks

Awaiting Approvals

3wks

ACTUAL

3 wks

3 wks

5 wks

3.53.9

Australia coal: quarterly equity ROM output

PLANNED (INDICATIVE ONLY)

Barrel (Bbl)This is the standard measurement for quantities of oil. One barrel of oil is equal to 42 gallons.

McfGas is measured in number of cubic feet. Thousands of cubic feet, or Mcf, is the standard measurement for quantities of gas. Production can be measured in Mmcfd, meaning million cubic feet of natural gas produced per day

ReservoirA reservoir is defined by four features. These four features are the accumulation of hydrocarbons via a present source rock, organic material that is "cooked" into hydrocarbons, porosity and permeability, and an impervious cap rock.

PorosityPorosity is defined as the pore space within the rocks.

PermeabilityPermeability entails the connections between pore spaces within the rock.

DrillingThis process entails using a drilling rig to drill the vertical or horizontal wellbore for the future extraction of hydrocarbons.

CompletingThe activities that take place after the initial drilling of a well, and are used for bringing a well on to production. This involves cementing, perforating, fracking, and more. Together, in the Chaffee Corner area, drilling and completion costs average ~$6.0MM.

O&G GLOSSARY

70

O&G GLOSSARY

Hydraulic FracturingThe process of pumping water, sand and chemicals into a drill wellbore in order to fracture impermeable rock. This fracturing then allows hydrocarbons, previously considered inaccessible, to flow towards the wellbore for production.

Vertical WellA well drilled directly above the producing target, straight down.

Horizontal WellA well drilled vertically to a given depth, then gradually curved until the wellbore is horizontal, so as to intersect a producing formation across thousands of horizontal feet.

OperatorThe operator is the company whose name is on the well and manages the day-to-day operations. The operator is one and only one of the joint working interest owners.

Non-operatorNon-operators pay their proportionate share to the operator. This involves all of the rest of the joint working interest owners, other than the operator.

Joint Working InterestTwo or more parties each own an undivided fraction of the working interest in a single lease.

Lease Operating Expenses (LOE)Lease Operating Expenses are measured as a function of costs per thousand cubic feet (mcf) of gas produced.

71

Oil and Gas LeasePrior to drilling activities, an Oil and Gas Lease must be retrieved from the mineral owner. Mineral owners are paid an upfront Lease Bonus, in addition to a royalty percentage from any productive well.

Held By Production (HBP)Acreage is HBP when there is a producing well on the underlying Oil and Gas Lease. In this event, the Oil and Gas Lease will not expire, as long as the well continues to produce hydrocarbons.

Economic ReservesThe quantity of reserves that are technically and economically recoverable under existing conditions and operating methods are deemed to be Economic Reserves.

Proved Developed Reserves (PDP)Proved Developed Reserves are expected to be extracted through existing wells and equipment, and are actively being produced.

Proved Undeveloped Reserves (PUD)Proved Undeveloped Reserves are expected to be extracted through new wells on undrilled acreage, however, this undrilled acreage must be "proved" to a reasonable extent.

Estimated Ultimate RecoveryThe estimated cumulative amount of oil or gas forecasted for a single well. Typically, this production will occur over 40 to 50 years.

Single Well EconomicsSingle Well Economics measure the economics of a single oil or gas well. These economics account for relevant acquisition costs, drilling and completion costs, and production over the 40 to 50 year life of the well.

O&G GLOSSARY

72