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Indonesian Oil & Gas Industry Trends, Insights, Opportunities & Challenges

© Chris Newton, March 2017, Singapore 1

© Chris Newton, 28 March 2017

The Indonesian Upstream Oil and

Gas Business

Trends, Insights, Challenges & Opportunities


Todays Discussion

Energy Overview

The Changing Role of Oil & Gas in the Economy

Major Upstream Trends

Expiring PSC and implications for all stakeholders

M&A Trends

Fiscal and Regulatory Changes

Upstream Opportunities and Challenges

The Downstream




Indonesian Energy Overview

Energy Overview




M&A Trends



The Downstream


Indonesian energy facts

4

Indonesia, a former founding OPEC member, became a net oil importer in 2004 and will potentially become a net gas importer in the early 2020’s.

Massive coal exports means Indonesia remains a net energy exporter in energy terms but not in financial terms.

Key statistics:

» World’s largest coal exporter.

» World’s fifth largest LNG exporter after 3 decades as the world’s largest before being replaced by Qatar in 2006.

» World’s largest bio fuel producer

» Largest regional (SE Asian) gas producer and exporter.

» Second largest regional oil / products importer.

IEA Synopsis

• Amid dwindling oil and gas reserves and production, a lack of exploration, and ageing refineries, Indonesia is increasingly dependent on imported oil supplies and has become the second-largest oil importer in the region.

• The country is faced with a considerable bill to finance still subsidised end-consumer prices, which are a legacy of its times as a net oil exporter and political failure.

• Indonesia’s economic success, rising living standards, population growth and rapid urbanisation have increased energy consumption rapidly. IEA projections predict this trend to continue. Hence, energy security and meeting expected energy demand growth are the key challenges for Indonesia’s energy policy.




National Energy Plan sees energy demand more than doubling between 2013 and 2025

5

NEP-14 planning basics

• Planning horizon:

» 2025 and 2050

• Economy:

» Declining population growth, strong rise in GDP/capita

• Scenarios. Two:

» Business as usual (BAU)

» Efficiency.

• Main differences. Efficiency scenario has:

» Stronger reductions in energy elasticity and intensity driving lower consumption.

» Much greater uptake of renewables, particularly biofuels.

Source: MIGAS NEP14, Risco Energy analysis

Primary Energy Consumption



Energy Overview




M&A Trends



The Downstream



© Chris Newton, 28 March 2017|

As the Indonesian economy has grown the role of oil & gas has fallen, exacerbated by declining investment attractiveness & recent oil price falls

7

Oil and Gas Contribution to National Economy Oil and Gas Contribution to State Revenue

Source: Statistics Indonesia, BKPM, BP Statistical, skkmigas


Production is now gas dominated

8

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

KB

OE

PD

Series1 Series2

Oil and Gas Production

Source: skkmigas

Oil Gas




Indonesia is a substantial net oil importer

9

0

250

500

750

1,000

1,250

1,500

1,750

1970 1974 1978 1982 1986 1990 1994 1998 2002 2006 2010 2014

KB

OP

D

Indonesian Oil Production & Consumption

Production Consumption

Source: skkmigas


Domestic gas sales now 60% of total sales

10

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

MMscfd

Gas Production and Utilization

Domestic Pipeline Gas Domestic LNG (TBTUD) LNG Export

Pipeline Export Losses & Own Use

Source: MIGAS




2016 gas utilization trends

11

Export LNG29.36%

Export Pipeline Gas

11.55%

Domestic LNG6.17%

Industry21.92%

Electricity14.61%

Fertilizer9.58%

Petrochemical1.34%

LPG2.58%

Oil Lifting2.79%

City Gas0.04%

Transportation0.05%

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2012 2013 2014 2015 2016

MM

scfd

Power Fertilizer

Petrochemical Other Industry

2016 Gas Utilization2012 - 2016

Domestic Gas Utilization Trends

Total = 6,989 BBTUD Total Domestic = 4,130 BBTUD (59.1%)

Source: MIGAS


Rising domestic demand potentially sees Indonesia become a net gas importer in the early 2020’s

12

Gas Supply and Domestic Demand Scenarios

Source: MIGAS, Risco Energy Analysis, Pertamina

0

2,000

4,000

6,000

8,000

10,000

12,000

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

MM

scfd

Existing Supply New Supply (Low)

New Supply (High) Domestic Demand (BaU Case)

Domestic Demand (Efficiency Case)

ExportsExports




Combined oil and gas production outlook

13

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

0

500

1000

1500

2000

2500

3000

3500

195

0

195

3

195

6

195

9

196

2

196

5

196

8

197

1

197

4

197

7

198

0

198

3

198

6

198

9

199

2

199

5

199

8

200

1

200

4

200

7

201

0

201

3

201

6

201

9

202

2

202

5

202

8

203

1

203

4

203

7

204

0

% G

as

KBOE

PD

Gas Oil Oil & Gas % Gas

Domestic Oil and Gas Production History & Outlook (From Existing Discoveries)

Source: skkmigas


Imports put the trade account under pressure

14

Oil & Gas Exports and Imports

US$ - RP Exchange Rate

Source: Bank Indonesia, MoF. Statistics Indonesia




Policy changes and lower oil price means lower energy subsidies

15

0

20

40

60

80

100

120

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Indo

nesi

an C

rude

Pric

e (U

S$/

Bbl

)

Sub

sidy

(U

S$

Bill

ions

)

Fuel Electricity ICP

Energy Subsidies

Source: Bank Indonesia, MoF. MIGAS

LPG now the main subsidised fuel although many x-subsidies remain



Energy Overview




M&A Trends



The Downstream




Licensing activity has fallen to historic lows as investors shun new blocks

17

Energy Subsidies

0

10

20

30

40

50

60

1966 1969 1972 1975 1978 1981 1984 1987 1990 1993 1996 1999 2002 2005 2008 2011 2014

Nu

mb

er o

f B

lock

s

Indonesian Upstream Licensing Activity

KSOShaleCBMPertamina CC'sSCPSCJOBExtensionEORTAC

Source: MIGAS, Risco Energy Analysis


Number of active blocks is in decline and will contunue

18

5976 79 80

110132 141 155

172 179 187 183 170143

110

5154 57 59

59

6467

7375 75

79 8084

85

85

0

50

100

150

200

250

300

350

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Number of Blocks

Active Blocks At Year End

Conventional Exploration Blocks Exploitation Blocks Non Conventional Blocks

Current

Source: skkmigas




Exploration activity and investment, the industry’s future, at decade lows

19

0

20

40

60

80

100

120

0

10,000

20,000

30,000

40,000

50,000

60,000

Wells Drilled

2D Line Km and 3D Km2 &

Exploration Expen

diture ($M x10)

Exploration Activity Vs Expenditure

2D Km 3D Km2 Wildcat Wells Appraisal Wells Exploration Expenditures (X10)

Source: skkmigas, Risco Energy Analysis


Development drilling is at 30 years lows

20

0

20

40

60

80

100

120

140

160

180

200

0

200

400

600

800

1,000

1,200

1,400

Exploration W

ells Drilled,O

il Price

& Active Exploration Blocks

Dev

elo

pm

ent

Wel

ls D

rill

ed

Exploration and Development Wells Drilled

Development Wells E&A (Conventional) Wells (Conventional)

ICP US$/ bbl Active Conventional Exploration PSC's





Indonesian exploration continues to under perform and is loosing global capital allocation share

21Source: Wood Mackenzie, Indonesian Petroleum Association


Both oil and gas reserves and resources are in decline. Proven gas nearly 5x proven oil

22

0.0

2.0

4.0

6.0

8.0

10.0

12.0

1980 1985 1990 1995 2000 2005 2010 2015

Billions of Barrels

Oil & Condensate Reserve & Resource History

Proven Potential

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

1980 1985 1990 1995 2000 2005 2010 2015

Billions BOE

Gas Reserve & Resource History

Proven Potential

Source: skkmigas, MIGAS




New developments declining, getting smaller and are gas dominated

23

0

500

1000

1500

2000

2500

3000

3500

4000

0

20

40

60

80

100

120

140

160

2003 2005 2007 2009 2011 2013 2015

Total A

dditions (M

MBOE)

Average Size (M

MBOE) & % Gas

New Development Approvals

Total Reserve Additions Average Size % Gas

Source: skkmigas,


1H 2016 new development statistics

24

1H 2016 Development Approvals

New POD's Approved Number 18Oil Reserves MMboe 45Gas Reserves MMboe 45Total Reserves MMboe 90Average Size MMboe 5.0Total Capital Investment US$M $1,500.0Average Investment US$ / Boe $16.64





Top 10 of 57 producing blocks responsible for 85% of oil production

25

0 50,000 100,000 150,000 200,000 250,000 300,000

37 Other BlocksPertamina - P. China Tuban

Citic SeramSaka Pangkah

Petrogas SalawatiMedco South Sumatra

Pertamina - Medco TomoriPertamina West Madura

Medco RimauBSP Central Sumatra

Petrochina JabungVico East Kal

Petronas KetapangConoco Phillips South Sumatra

Cevron NatunaCNOOC SE Sumatra

Pertamina ONWJTotal East KalPertamina EP

Exxon - Pertamina CepuCaltex Sumatra

BOPD

Oil Production By Block

Source: skkmigas,


Top 10 of 54 producing blocks responsible for 81% of gas production

26

0 200 400 600 800 1000 1200 1400 1600 1800

34 Other Blocks

Santos Madura

Medco Lematang

Santoa Sampang

Mubadela ‐ Ruby

Pertamina ‐ Talisman Jambi Merang

Petronas Muriah

Chevron Natuna

Pertamina West Madura

Pertamina NSO/ NSB

CNOOC SE Sumatra

Pertamina ONWJ

Vico East Kal

EMP Kangean

Premier Natuna

Petrochina Jabung

Pertamina ‐ Medco Tomori

Conoco Philips South Sumatra

Pertamina EP

BP Tangguh

Total Mahakam

MMscfd

Gas Production by Block

Source: skkmigas,




Oil price fall exacerbated by ICP – Brent differential increase

27

Brent and ICP Prices and Differentials

-5.0

-4.0

-3.0

-2.0

-1.0

0.0

1.0

0

20

40

60

80

100

120

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

Diff

eren

tial (

ICP

-Bre

nt)

US

$/B

bl

Brent and ICP (US$/ Bbl)

ICP Dated Brent ICP-Brent

Dis

cou

nt

Pre

miu

m

Source: MIGAS


Falling oil prices have narrowed the gap between domestic and export gas and LNG prices

28

0

20

40

60

80

100

$0.0

$2.0

$4.0

$6.0

$8.0

$10.0

$12.0

$14.0

$16.0

$18.0

$20.0

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

ICP

(U

S$

/ BB

L)

US

$/ M

Mbt

u

Indonesian Gas Price Trends

Domestic Pipeline Export Pipeline Domestic LNG Export LNG ICP

Source: skkmigas,




Declining investment plus cost cutting now driving down total expenditure

29

0

500

1000

1500

2000

2500

3000

3500

-

5,000

10,000

15,000

20,000

25,000

1980

1981

1982

1983

1984

1985

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

Production (KBOEPD)

Exp

endi

ture

(U

S$

Mill

ions

)

Expenditure by Production Sharing Contractors

Exploration Development Production Administration Production



Government and contractor revenues have plummeted with oil prices

30

20

40

60

80

100

120

0

10

20

30

40

50

60

70

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

ICP

(U

S$

/ B

bl)

Ree

nue

(US

$ B

illio

ns)

Oil Prices and Revenue Split

Cost Recovery (CR) Net Contractor Share Indonesia Share Gross Revenue (GR) ICP





With cost largely fixed and revenue falling, cost recovery has become a political polemic

31

0

10

20

30

40

50

60

70

0%

10%

20%

30%

40%

50%

60%

70%

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

Gro

ss &

Ind

ones

ia R

eve

nue

(U

S$

Bill

ions

)

Rev

enue

Spl

it

Revenue Split

Gross Revenue (GR) Indonesia Share

Cost Recovery % of GR Contractor Share (post CR)

Indonesia Share / Gross RevenueSource: skkmigas, Risco Energy Analysis


2016 cost recovery by 15 largest producers

32

$9.4

$11.6

$16.1

$19.5

$19.8

$22.0

$22.0

$23.6

$26.6

$28.0

$30.2

$30.4

$31.9

$34.4

$36.0

0.00 5.00 10.00 15.00 20.00 25.00 30.00 35.00 40.00

Exxon Cepu

COPI Corridor

Total Mahakan

Petrochina Jabung

Premier Natuna

Pertamina EP

Vico Sang Sanga

Caltex Rokan

Pertamina ONWJ

CNOOC SES

Chevron East Kal

EMP Kangean

Petronas Ketapang

Pertamina Madura

COPI Natuna

Cost Recovery (US$/ Boe sales)

2016 Cost Recovery /BOE for 15 Largest Producers

2016 Weighted AverageUS$18.26 / boe

Source: skkmigas,




Expiring PSC’s

Energy Overview




M&A Trends



The Downstream


PSC’s expire after their 20 year production period and there is no automatic extension right

34

Indonesian PSC’s have a 10 year exploration period and a 20 year exploitation period. PSC’ that went into production in the 1970 and 1980’s started to expire in the 1990’s The production sharing contract gives contractors no automatic right of extension. In the 1990’s as the first blocks expired most were renewed on favourable terms. As resource nationalism increased and the value in the expiring PSC’s was

recognised, government came under pressure to change the policy. A period of political indecision and uncertainty followed that drove under investment

in expiring blocks. New regulations now make it clear that the NOC, Pertamina, will have priority access

to expiring blocks. This is consistent with Pertamina strategy to add reserves, production, cashflow and

capability at home. These producing PSC’s are the lowest cost acquisitions Pertamina can make. New policy consistent with government policy for energy security and energy

independence. The key issues for Pertamina and GoI is that there is now no incentive for contractors

to maintain investment in expiring PSC and “blow down” becomes the best strategy for contractors.

The new Gross Split terms also do nothing to stimulation exploration investment.




Over the next decade 35 PSC’s will expire currently producing over 1.0 MMstboe/d

35

Indonesian Production by PSC Expiry

34 Blocks expiring between 2017 and 2025

• 2017 – 3 blocks• 2018 – 9 blocks• 2019 – 4 blocks• 2020 – 6 blocks

Source: Wood Mackenzie


The blocks expiring pre 2025 currently hold over 4 billion boe’s of producing reserves

36

0

200

400

600

800

1,000

1,200

Ge

ban

g (

JOB

-PN

/Cos

ta)

ON

WJ

(Per

tam

ina)

Ma

ha

kam

(T

ota

l)

Lem

ata

ng

(M

edc

o)

Tu

ban

(JO

B-P

N/P

etr

oC

hin

a)

Og

an

Ko

mer

ing

(JO

B-P

N/T

alis

man

)

Sa

nga

-sa

nga

(V

ico

)

SE

S (

CN

OO

C)

B B

lock

(E

xxo

nM

obi

l)

Te

nga

h (T

ota

l)

Att

aka

(C

hevr

on

)

No

rth

Su

ma

tra

Offs

hor

e (

XO

M)

Ea

st K

alim

an

tan

(C

he

vro

n)

Jam

bi M

era

ng (

JOB

-PN

/Tal

ism

an)

Ra

ja P

en

dop

o (J

OB

-PN

/Go

lde

n S

pike

)

Se

ram

No

n B

ula

(C

ITIC

)

Bu

la (

Ka

lrez)

So

uth

Ja

mbi

B (

CoP

i)

Ma

kasa

r S

tra

it A

(C

he

vro

n)

Bra

nta

s (L

api

ndo

)

Sal

aw

ati (

JOB

-PN

/Pet

roC

hina

)

Ma

lacc

a S

trai

t (E

MP

)

Sa

law

ati

Ke

pa

la B

uru

ng

(P

etr

oC

hin

a)

Ro

kan

(C

hevr

on)

Ben

tu (

EM

P)

Se

lat

Pa

nja

ng (

Su

gih

)

Tra

raka

n (

Me

dco

)

CP

P (

PH

E-B

SP

)

Tu

ngka

l (M

on

tD'o

r)

Se

ngka

ng

(E

nerg

y E

qu

ity)

Jab

ung

(P

etr

oC

hin

a)

Rim

au

(M

edc

o)

Co

rrid

or

(Co

noco

Ph

illip

s)

Ba

ngko

(P

etr

oChi

na)

Mu

ria

h (P

etr

ona

s)

2P R

eser

ves,

MM

BO

E 2nd Ext

1at Ext

2015 2017 2018 2019 2020 2022 2023 20252021

PSC Expiring Pre 2025 and 2015 Reserves





Current value in PSC’s expiring over the next decade exceeds US$10 billion

37

Current Value in Expiring PSC’s

ONWJMahakam

SESSanga Sanga

Rokan

JambiMerang

Makassar

Muriah

CorridorJabung

Pangkah

Sengkang

Source: Wood Mackenzie


Status of PSC expiries to date

38

Pertamina Priorities

• Material reserves, production and cashflow

• Operating capability• Growth• Synergies with existing

operations

Less Attractive

• Lacks materiality• Cashflow negative

/development Capex• Limited development

capability• No clear synergies

Source: skkmigas, Petromindo, Risco Energy Analysis

Block Partners Expiry StatusDate Oil (KBOPD) Gas (KBOEPD)

ONWJ Pertamina

EMP

Kufpec

Jan‐17 36 26 Awarded 100% to Pertamina.

Other JV partners could negotiate with

Pertamina on a B2B basis.

First Gross Split PSC

Parners unlikely to participate

Mahakam Total

Inpex

Dec‐17 63 285 Awarded 100% to Pertamina.

Other JV partners could negotiate with

Pertamina on a B2B basis.

Transition arangements and Pertamina pre

investing

Parners unlikely to participate

Lematang Medco Apr‐17 11 Awarded to Medco

Lack materiality for Pertamina

Sanga Sanga BP eta al Aug‐18 15 39 BP, major shareholder and operator sold out

to PGN in 2017

PGN Ppsitioning for PSC extension

Aceh Block B and

NSO

Exxon Oct‐18 19 Exxon sold out to Pertamina in 2015

Sanga Sanga &

East Kalimantan

Saka and

Chevron

Aug 18

& Oct 18

15 & 19 39 & 83 To be awarded to Pertamina and integrated

with Mahakan Block Operations

Tuban, SES, Ogan

Komering, NSO

block, Attaka &

Tengah.

Petro

China,

CNOOC,

Chevron,

Pertamina

2017 ‐

2018

> 30 >150 To be awarded to Pertamina

2016 Production




M&A Trends

Energy Overview




M&A Trends



The Downstream


Upstream M&A activity remains subdued

40

0

5

10

15

20

25

30

35

1966 1970 1974 1978 1982 1986 1990 1994 1998 2002 2006 2010 2014

Nu

mb

er in

Yea

r

Assets Changing Ownership

Number of Deals

Transactions Involving Indonesian Oil & Gas ReservesAnnual Deal and Asset Frequency

Source: Chris Newton Indonesian M&A Transactions Database




Volumes transacted remain gas dominated

41

0%

20%

40%

60%

80%

100%

0

500

1,000

1,500

2,000

2,500

3,000

1966 1970 1974 1978 1982 1986 1990 1994 1998 2002 2006 2010 2014

% G

as in

Tra

nsac

ted

BO

E's

(3

year

mov

ing

aver

age)

MM

BO

E's

Tra

nsa

cted

Indonesian Oil and Gas 2P Reserves Transacted

Oil & Condensate (MMSTB) Gas (BOE) %Gas


Aggregate transaction values off 2015 lows

42

0.0

20.0

40.0

60.0

80.0

100.0

120.0

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$4,500

$5,000

1966 1970 1974 1978 1982 1986 1990 1994 1998 2002 2006 2010 2014

Dat

ed B

rent

oil

Pric

e (U

S$/

BB

l)

US

$ M

illio

ns

Annual Aggregate Transaction Values

Dated Brent





Transaction metrics driven by oil prices and asset life cycle

43

$0

$20

$40

$60

$80

$100

$120

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

$9.0

$10.0

1969 1972 1975 1978 1981 1984 1987 1990 1993 1996 1999 2002 2005 2008 2011 2014

Bre

nt

US

$ / B

bl

US

$ 2P

/ B

OE

Weighted Average Annual Tranaction Metrics US$/2P BOE

US$/2P Boe Oil Price ($/Bbl)Source: Chris Newton Indonesian M&A Transactions Database


Asian and local companies the dominant acquirers

44

0%

20%

40%

60%

80%

100%

1977 1980 1983 1986 1989 1992 1995 1998 2001 2004 2007 2010 2013 2016

% o

f Tot

al D

eals

by

Asi

an a

nd L

ocal

Acq

uire

rs

Indonesian Transactions by Acquirer

Asian Acquirers (Includes Local) Local Acquirers





Existing industry participants are dominating the M&A market

45

0%

20%

40%

60%

80%

100%

1966 1970 1974 1978 1982 1986 1990 1994 1998 2002 2006 2010 2014

% of Total Indonesian Acquisitions by New Entrants



Buyers geographically concentrated while internationals exiting

46

Major5% Foreign NOC

6%

IOC7%

NA Indi5%

Eur Indi7%

Regional Oil & Gas Co

21%

Local Company (Includes

NOC)49%

Acquirers - 2010-2016

Major7%

Foreign NOC5%

IOC12%

NA Indi11%

Eur Indi16%

Regional Oil & Gas Co

21%

Other5%

Local Company (Includes

NOC)23%

Sellers - 2010-2016





Oil-gas mix and development status are key value drives next to margins and upside

47Source: Chris Newton Indonesian M&A Transactions Database

Indonesian 2P/ BOE Transaction Values by Product Type and Asset Maturity(2010- 2016


Fiscal & Regulatory Changes

Energy Overview




M&A Trends



The Downstream




Lack of regulatory clarity, consistency & certainty remains an impediment to investment

49

Key recent regulator changes

Introduction of Gross Split PSC

• An effective “Tax-Royalty” regime with no cost recovery to replace PSC in expiring and new blocks.

Multiply changes to Domestic Gas Pricing Policy

• With falling oil prices and infrastructure constraints, gas has become less competitive and government is trying to increase gas affordability.

Changes to abandonment / restoration obligations

• Old contracts have no abandonment obligations as the State owns the assets. Retrospective changes to old PSC’s being drafted.

Changes to GR79 (2010) on cost recovery and other taxes

• Changes planned as GoI recognizes tax impositions impeding investment. • MoF remains the problem, and changes likely to dissapoint.

Pending New Oil & Gas Law

• Long awaited and now being drafted by parliament for promulgation in 2018. Needs to balance populism, contract sanctity and need for foreign investment.


The gross split PSC terms are applicable to new contracts and contract extensions

50

Changes Investor Pros Investor Cons

• Cost recovery and production sharing replaced by what is effectively a regressive tax royalty regime.

• Base revenue split to Contractor is Oil 43% and Gas 48%.

• Incremental additional splits of up to 16% available based on field costs / complexity.

• Incremental split based on oil price realisations. +/- 7.5% based on oil price above of below base of US$70-85 / bbl

• No cost recovery could mean lighter handed regulation and greater contracting flexibility leading to lower cost structure

• Potentially greater operating and procurement flexibility will drive efficiency and lower costs

• Greater incentive for cost effectiveness.

• Terms adjust with oil price• DMO oil priced at market.• 20-30% cost savings for

offshore oil exploration potentially improve full cycle exploration economics

• Regressive fiscal system that taxes revenue and not profits.

• High “royalty rate” means contractors have to lower cost structure in existing producing assets by 30% to achieve the same outcome as existing fiscal terms.

• Tax royalty regime where there remains material uncertainty on a host of tax issues

• Increased fiscal deterrence means more fields will remain undeveloped.

• Onshore and Deepwater exploration unattractive even with deep costs cuts as revenue share and payouttimes just too long.

• Is a regulatory shift from micro management to light handed regulation achievable!

Terms very unlikely to attract investors or stimulate reinvestment in expiring PSC’s




Domestic gas pricing controls increased and are way short of the market driven pricing necessary to promote supply

51

Changes Investor Pros Investor Cons

Presidential decree 40/ 2016• Adjusted priorities for gas

allocation into downstream value add such as fertilizer, petrochemicals and steel.

• Cap gas price a US$6.0 MMbtu for priority industries by adjusting government share and keeping contractors whole

• Improved competitiveness of domestic gas should drive demand

• Implementation uncertainty and complexity frustrating all participants

• Not always achievable• Investors are not being left whole• Erosion of the value of a long term

GSA given ministerial price ”reviews”

• MEMR regulation 11/2017• Regulates domestic gas and

LNG prices for power generation, prioritises domestic gas over imports and regulates when and how imports can be done

• Move towards oil price indexation

• Increasingly linkage of domestic markets to international markets

• Gas price can exceed caps if import prices higher than 11.5% FOB

• Gas price capped at 8.5% of ICP at wellhead or 11.5% of ICP at plant.

• Pipeline gas price discount vs domestic LNG

• Gas prices always capped at a regulated return on individual field development economics

Unnecessarily complex, bureaucratic & prejudicial to domestic pipeline gas vs domestic LNG but ultimately exposes domestic market to international prices



Energy Overview




M&A Trends



The Downstream




Multiple opportunities for those with the skills, insight, patience and relationships to manage the challenges.

53

Opportunities Challenges

• Upstream oil and gas supply imperative to support economic growth, energy security and energy independence.

• Mid and downstream infrastructure investment for petroleum product, crude gas / LNG import, storage, transmission, processing & distribution.

• Growing demand for CNG and LNG infrastructure in transportation sector to replace imported petroleum products.

• Funding of undercapitalised local and regional companies, with good assets.

• Counter cyclical upstream investment leveraging declining service sector costs and diminishing buy-sell spread in M&A.

• Massive investment needs for gas in power generation and crude oil refining.

• Low cost operators to exploit late life production and opportunities with new gross split PSC’s

• Low cost abandonment specialists

• Investing with a government that recognises the necessity of enhanced investment competitiveness while often doing the opposite in the face of competing priorities around short term revenue needs and resource nationalism.

• Pervasive regulatory uncertainty and more to come until new oil and gas law and regulations finalised .

• Poor coordination between Ministries regulating oil and gas activities.

• Navigating the over regulated domestic gas market problems while positioning for international gas market convergence.

• Downward pressure on gas prices, even in signed contracts.

• Will upstream regulator really relinquish command and control and micro management mind set for promised flexibility and efficiency in new fiscal regime?


The Downstream

Energy Overview




M&A Trends



The Downstream




0

200

400

600

800

1,000

1,200

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

Mst

b/d

Kl *

100

0

Consumption by Fuel & Total Imports

Gasoline Automotive Diesel Kerosene Fuel OilIndustrial Diesel Aviaton LPG Total Imports

With 50% of petroleum product consumption imported there is a strong desire for additional refining capacity and storage

Source: MIGAS

Petroleum product consumption falling after subsidy removal eliminates smuggling incentive


Downstream petroleum investment requirements

Operational Storage

• Increase operational storage to 30 days from current 22 days

• Products, LPG and crude oil storage investment needed

• US$8 billion needed asap

Energy Buffer Reserve

• Add 30 day reserve buffer from zero currently to enhance supply security

• Products, LPG and crude oil storage investment needed

• US$9 billion needed by 2025

Additional Oil Refining Capacity

• Petroleum products consumption >2x current refining capacity

• Additional 1.2 Million bopd refining capacity• 2 new grass roots

mega refineries• Expansion of excising

5 refineries• New mini refineries• US$20 + billion

Source: Migas, Synergy, QEnergy




Gas infrastructure road map sees US$48 billion investment needed by 2030

Total Investment NeedsPipelines

12.0Liquifaction

26.0CNG2.0 Total

US$ 48.7BillionRegas

6.1Distribution

2.2LPG0.4

Source: MIGAS


Cumulative Infrastructure Investment Requirement (2016 – 2030)

Gas infrastructure road map detailed requirements

Source: MIGAS




Backup

Where are we in the Oil Price Cycle?


-80%

-70%

-60%

-50%

-40%

-30%

-20%

-10%

0%

10%

20%

30%

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35

Cha

nge

from

sta

rt o

f pric

e co

llaps

e

Months from Start of Price Collapse

Brent Oil Price Cycles 1986, 1997, 2008, 2014-16

1986-1988 1997-2000 2008-2011 2014-2016

We are 32 months into a major supply side shock

Cycle Supply Side

Shock

Supply Side

Shock

DemandSide

Shock(AFC)

DemandSide

Shock(GFC)

Source: EIA, Risco Energy




Documents

The Indonesian Upstream Oil and Gas Business - Risco Indonesian Upstream Oil and Gas Business Trends, Insights, ... Petrochina Jabung Pertamina ‐ Medco Tomori Conoco Philips South