Financial results for the year ended March 31, 2017
Appendix

INPEX CORPORATION
May 15, 2017

Subsidiaries and Affiliates
64 consolidated subsidiaries
Major subsidiaries

Country/region

OwnershipStage

Accounting term

Japan Oil Development Co., Ltd.

UAE

100%

Production

March (provisional
settlement of account)

JODCO Onshore Ltd.

UAE

51 %

Production

December

INPEX Sahul, Ltd.

Timor Sea Joint Petroleum
Development Area

100%

Production

December

INPEX Ichthys Pty Ltd

Australia

100%

Development

March (provisional
settlement of account)

INPEX Southwest Caspian Sea, Ltd. Azerbaijan

51%

Production

March (provisional
settlement of account)

INPEX North Caspian Sea, Ltd.

Kazakhstan

45%

Production

March (provisional
settlement of account)

INPEX Oil & Gas Australia Pty Ltd

Australia

100%

Development

December

INPEX Gas British Columbia Ltd.

Canada45.09%

Production/
Evaluation

December

20 equity method affiliates
Major affiliates

1

OwnershipStage

Accounting term

MI Berau B.V.

Indonesia

Country/region

44%

Production

DecemberAngola Block 14 B.V.

Angola49.99%

Production

December

INPEX Offshore North Campos,
Ltd.

Brazil

37.5%

Production

DecemberIchthys LNG Pty Ltd

Australia

62.245%Development

March (provisional
settlement of account)Segment information
For the year ended March 31, 2017 (April 1, 2016 through March 31, 2017)(Millions of yen)Japan
Sales to third
parties
Segment income(loss)
Segment assets

Asia &
Oceania

Reportable segments
Eurasia
Middle East
(Europe &Americas& Africa
NIS)

Total

Adjustments *1 Consolidated *2

102,659

218,099

60,191

482,182

11,290874,423‐

874,423

18,03351,565

12,112276,870(9,360)349,221(12,769)

336,452

320,852

1,997,494

600,854446,791

137,119

3,503,111

809,062

4,312,174

Note:
1. (1) Adjustments of segment income of ¥(12,769) million include elimination of inter‐segment transactions of ¥13 million and corporate
expenses of ¥(12,782) million. Corporate expenses are mainly amortization of goodwill that are not allocated to a reportable segment andgeneral administrative expenses.
(2) Adjustments of segment assets of ¥809,062 million include elimination of intersegment transactions of ¥(2) million and corporate assets of¥809,064 million. Corporate assets are mainly goodwill, cash and deposit, investment securities and assets concerned with theadministrative divisions not attributable to a reportable segment.
2. Segment income is reconciled with operating income on the consolidated statement of income.

2(Billions of Yen)

Analysis of Net Sales Decrease
for the year ended March 31, 2017

1,200

Crude Oil

(22.9)

Crude Oil

(67.9)Natural Gas (including LPG)

(62.9)Natural Gas (including LPG)

(17.1)

34.8
1,000

1.0

(85.9)(85.1)

800

600

Crude Oil

+28.8

Natural Gas (including LPG)

+5.9

1,009.5
874.4

400

200

0
3

Net Sales
Increase in
Apr. ‘15 ‐ Mar. ‘16 Sales Volume

Decrease in
Exchange rate
Unit Price (Appreciation of Yen)

OthersNet Sales
Apr. ‘16 ‐ Mar. ’17

LPG Sales
Apr. ‘15 ‐ Mar. ‘16

Apr. ‘16 ‐ Mar. ‘17

Net sales (Billions of yen)

10.5

6.7

(3.7)

(35.8%)

Sales volume (thousand bbl)

2,361

1,860

(501)

(21.2%)

Average unit price of overseas
production ($/bbl)

36.97

33.93

(3.04)(8.2%)

Average unit price of domestic
production (¥/kg)

66.34

56.51

(9.83)(14.8%)

Average exchange rate (¥/$)

120.79107.3413.45 yenappreciation

11.1% yenappreciation

Apr. ‘15 ‐ Mar. ‘16

Apr. ‘16 ‐ Mar. ‘17

Change%ChangeJapan

7(0.6 thousand ton)5
(0.5 thousand ton)(1)(‐0.1 thousand ton)

(20.6%)

Asia & Oceania

2,354

1,855

(500)

(21.2%)

Eurasia (Europe & NIS)

‐

‐

‐

‐

Middle East & Africa

‐

‐

‐

‐

Americas

‐

‐

‐

‐

2,361

1,860

(501)

(21.2%)

Sales volume by region(thousand bbl)

Total

Change%Change

4

EBIDAX(Millions of yen)

Apr. ‘15 –Mar. ’16

Apr. ’16 –Mar. ‘17

Note

Change16,777

46,16829,391

P/L

Net income (loss) attributable to non‐controlling interests(42,282)

9,963

52,245

P/L

Depreciation equivalent amount

157,750

177,792

20,042

Depreciation and amortization

86,791

91,1594,368

Amortization of goodwill

6,760

6,760

‐

Recovery of recoverable accounts under
production sharing (capital expenditures)

64,19979,873

15,674

Net income attributable to owners of parent

C/F Depreciation under concession agreements and G&A
C/FC/F Depreciation under PS contracts

31,527

21,108(10,419)

Exploration expenses

6,166

6,734

568

Provision for allowance for recoverable
accounts under production sharing

25,026

14,374(10,652)

P/L Exploration expense under PS contracts

335

‐

(335)

P/L Exploration expense under PS contracts

58,777(21,965)(80,742)

Income taxes‐deferred(2,192)(33,227)(31,035)

P/L

Foreign exchange loss (gain)

15,085

4,896(10,189)

C/F

Impairment loss

45,884

6,366(39,518)

P/L

Net interest expense after tax(4,653)(3,767)886

EBIDAX

217,896229,299

11,403

Exploration cost equivalent amount

Provision for exploration projects
Material non‐cash items

5

P/L Exploration expense under concession agreements

P/L After‐tax interest expense minus interest income

Analysis of Recoverable Accounts
under Production Sharing(Millions of yen)Mar. ‘15

Mar. ‘16

Mar. ‘17

Balance at beginning of the period

685,990

703,291

727,771

Exploration costs

41,23630,9699,461

Development costs

131,984

104,518

39,928Operating expenses

98,25070,36555,514

Other

7,331

9,745

6,969

Cost recovery (CAPEX)

75,58564,19979,873

Cost recovery (non‐CAPEX)

146,929

107,133

73,414Other

38,986

19,785

27,156

Balance at end of the period

703,291

727,771659,201

Less allowance for recoverable accounts under
production sharing at end of the period

121,707

131,765

120,543

Add:

Less:

6

Valuation Indices

EV/Proved Reserves*

PBR**

20.0

2.0

15.0

1.5
21.1

10.0
5.0
0.0
US$

1.0
14.9

3.4
INPEX

Average of
Independents

Average of Oil
Majors

2.1

0.5
0.4

0.0
x

INPEX

•

**

7

1.4

Average of
Independents

Average of Oil
MajorsEV (Enterprise Value) / Proved Reserves= (Total market value + Total
debt ‐ Cash and cash equivalent + Non‐controlling interests) / Proved
Reserves. Total market value as of 31/03/2017. Financial data andProved Reserves for INPEX as of 31/03/2017. Financial data andProved Reserves for Independents and Oil Majors as of 31/12/2016.
Sources based on public data.
PBR = Stock price / Net asset per share. Total market value as of
31/03/2017. Financial data for INPEX as of 31/03/2017. Financial data
for Independents and Oil Majors as of 31/12/2016. Sources based on
public data.

Reserves/Production Indices
Production
Cost per BOE Produced
原油換算1バレル当たりの生産コスト

Exploration & Development Cost per BOE (3‐year average)
70.0

17.8
18.0
12.6

11.2

12.0

11.2

7.8

9.0

6.1

6.0

50.0

US$/boe

US$/boe

15.0

Incl. royalty

3.0
Mar. ʹ15

Mar. ʹ16

Mar. ʹ15

400%
350%
300%
250%
200%
150%
100%
50%
0%

2.6
2.1

2.0
1.0
0.0
Mar. ʹ16

15.7

Mar. ʹ16

Mar. ʹ17

Reserve Replacement Ratio (3‐year average)

3.5

Mar. ʹ15

16.9

20.0
0.0

5.0

3.0

30.0

Mar. ʹ17

SG&A Cost per BOE Produced
原油換算1バレル当たりの販売費及び一般管理費

4.0

40.0

10.0

Excl. royality

0.0

US$/boe

58.2

60.0

321%
246%

100%

Mar. ʹ15

Mar. ʹ17

Mar. ʹ16

Mar. ʹ17

8

Net Production* (Apr. 2016 – Mar. 2017)
Oil/Condensate/LPG
2% 1%

10%
7
3 36
9%
32

348 thousand bbl/day

Total

Japan
Asia/Oceania

270

521 thousand BOE/day

Eurasia5%

Middle East/Africa

28 28Americas77%5%Natural Gas
13%
1%

14%

117
5

132

31%

162

923 million cf/day(173 thousand BOE/day)

270
Japan

Japan
Asia/Oceania

669

Eurasia
Middle East/Africa

72%

9

*

Americas52%

Asia/Oceania

33

Eurasia6%

Middle East/Africa
Americas

The production volume of crude oil and natural gas under the production sharing contracts entered into by INPEX Group corresponds to the net economic take of INPEX Group.

Proved Reserves by Region *
4,000
3,500

3,264

3,304

1%

1%

53%

54%

6%

7%

3,000

Million BOE

2,532
2,500
2,000
1,500

2,188

2,434

3%

3%

3%

34%

32%

9%

8%

8%

59%

49%

50%

35%

34%

6%

7%

7%

5%

4%

Mar.ʹ13Mar.ʹ14Mar.ʹ15

Mar.ʹ16

Mar.ʹ17

23%

1,000
500
0

Japan

Asia/Oceania

Eurasia

Middle East/Africa

Americas* The definition of proved reserves is listed on page 52.

10Upside Potential from
Proved + Probable + Possible Reserves*
Abadi
Shale Gas
ADMA Blocketc.

Million BOE

10,000
9,000
8,000
7,000

Contingent Resources
Possible Reserves
Probable Reserves
Proved Undeveloped Reserves
Proved Reserves

IchthysUpper Zakum
ADCO
Kashagan etc.

Ichthys etc.

6,000
5,000

540

4,000

1,389

3,000

1,680

2,000
1,000

1,680

24.7
17.4

1,624

1,624

years

27.5
years

Reserves to
production
ratio**

years

0
ProvedProvedDeveloped Undeveloped
Reserves
Reserves

11

ProvedReserves

Probable
Reserves

Possible
Reserves

Contingent
Resources****
The definitions of proved, probable and possible reserves are listed on page 52‐53.
** Reserves to production ratio= Reserves as of March 31, 2017/ Production for the year ended March 31, 2017*** Contingent Resources are estimated by INPEX. Under the SPE‐PRMS standard, contingent resources are quantities of hydrocarbons which are estimated to bepotentially recoverable from known accumulations, but which are not currently considered to be commercially recoverable due to one or more contingencies.

Project Summary

FY 2018/03 Exploration Work Programs*
RussiaZapadno‐Yaraktnskiy Block /Bolshetirskiy Block (3)Malaysia
Iraq

Block R (1)Block 10 (1)* The number in () denotes
the number(s) of drilling
wells

Exploration
Expenditure(Billions of Yen)

Exploratory
Wells(wells)Mar. ’17

16.1

4

3

406

2,328

Mar. ‘18 (E)

8.0

3

2

342

300

Exploration Well
Appraisal Well
13

Appraisal
Wells(wells)Seismic
Survey 2D(km)

Seismic
Survey 3D(km2)

Major Assets in Production & Development

Canada Shale gas projects

Sakhalin 1

North Caspian Sea Block(Kashagan Oil Field, etc)
ACG Oil Field

Minami‐Nagaoka Gas Field

ADMA Block

Lucius Fieldin the U.S. Gulf of Mexico

ADCO Onshore
Concession

Copa Macoya/Guarico
Oriental Blocks

Offshore Mahakam Block
Offshore D.R.
Congo Block

Sebuku Block (Ruby Gas Field)
Berau Block (Tangguh Unit)

Offshore Angola
Block 14

Abadi LNG Project

WA‐35‐L(Van Gogh Oil Field)

JPDA03‐12 (Bayu‐Undan Oil & Gas Field)
Offshore North Campos
Frade Block

WA‐35‐L/WA‐55‐L(Coniston Oil Field)
Prelude FLNG Project

WA‐43‐L(Ravensworth Oil
Field)In Production

Ichthys LNG ProjectIn Development

Preparation for Development

14

Production Start‐up Schedule
Australia

Indonesia

Abadi

Tangguh LNG
Expansion ProjectIndonesia

2027

Indonesia

2026
2025
2024

Americas

2023
2022

PreludeAustralia

Canada Shale
Gas *

2021

IchthysCanada2020

Eurasia

Australia

2019
2018

Coniston
Australia

2017

LuciusMiddle East /Africa

USA

2016

2015
LianziAngola2014

Umm Lulu
UAE

Production Started/Development Phase

15 * Partially in production

KairanKazakhstan

Nasr

AktoteUAE

Kazakhstan

Project Development planning underway

Kalamkas
Kazakhstan

Natural Gas

Crude Oil/Condensate

Natural Gas Business in Japan–Production volume* :•Natural gas: approx. 3.5 million m3/d (132 million
scf/d)**•Crude oil and condensate: approx. 4,000 bbl/d–Natural Gas SalesLNG•FY 2017/03: approx. 1,910 million m3**
•FY 2018/03(e): approx. 2,120 million m3**
•Distribution outlook: 2,500 million m3 per year in thefirst half of the 2020s, 3,000 million m3 per year in thelong‐term–Gas Supply Chain•Started commercial operations at Naoetsu LNG
Terminal in December 2013
•Toyama Line completed in June 2016

*sum of domestic crude oil and gas fields : average daily volume for the six
months ended Mar. 31, 2017**1m3 =41.8605MJ

16

Gas Prices in Japan
Price Comparison per Unit

140

120
*Conversions into unit price per 41.8605MJ(10,000kcal) by Crude Oil : 38.28MJ/L, Fuel Oil:
38.90MJ/L, LNG : 55.01MJ/kg (METI Statistics)

100*Refinement cost etc. are not included for crude oil.
Delivery cost etc. are not included for Fuel Oil.
Storage, Regasification, Distribution costs etc. are notincluded for LNG

80

60

40

20

00/4

17

01/4

02/4

03/4

04/4

05/4

06/4

07/4

08/4

09/4

10/4

11/4

12/4

13/4

14/4

15/4

16/4

17/4

Offshore Mahakam Block
INPEX CORPORATION– Participating Interest: 50% (Operator: TOTAL)– Production volume*
Bontang LNG/LPG Plant• Crude Oil and Condensate: Approximately
53,000 bbl/d• LPG: Approximately 11,000 bbl/d• Natural Gas**: Approximately 1,176 million cf/d
Attaka Unit
– PSC: Until 2017
Santan Terminal
Attaka Field– Development activities mainly in the Tunu, Peciko,
Badak Field
Sisi, Nubi and South Mahakam gas fields continue
Nilam Field
to maintain a stable supply of gas to Bontang LNG
Tambora Field
Tunu
Paciko Field
Field
plantsHandil Field
Sisi Field– LNG supply to Indonesia’s first LNG receiving
Senipah Terminal
Nubi Field
terminal (FSRU: Floating Storage andBekapai Field
Makassar Strait
Regasification Unit) in West Java started in April
Balikpapan
Offshore Mahakam Block
2012– Production at the South Mahakam Gas Field
commenced at the end of October 2012
South Mahakam Gas Fields– Signed Agreements for Transfer of Operations inMarch 2017
– Currently in discussions with Pertamina and＊ on the basis of all fields and average rate for Mar. 2017
TOTAL concerning participation in the block after＊＊ Volume not at wellheads but corresponding to the2018
sales to buyers
Gas field

Oil Field

Oil and Gas field

18

Sebuku Block (Ruby Gas Field)
INPEX South Makassar, Ltd.
Bongtang LNG Plants
Santan Terminal

Fertilizer Plant
Attaka Oil Field– Participating Interest: 15%(Operator : PEARLOIL (Mubadala))– Production volume*:• Natural Gas**: Approximately 110 million cf/d

Tunu Gas Field

Senipah Terminal
Balikpapan

Peciko Gas Field

Kalimantan– PSC: Until 2027

South Mahakam Gas Fields

Sebuku Block

Sulawesi– FOA (Farm Out Agreement) with PEARLOIL wasapproved by the Indonesian government inAugust 2010 (INPEX acquired a 15% interest).
– FID (Final Investment Decision) made in June
2011

0

50

100km

Ruby Gas Field– Offshore facilities tied in to the onshore facilitiesof the Offshore Mahakam Block by subsea
pipeline.

Kalimantan

Sulawesi

West Papua

Gas field
Oil Field

Jawa– Produced gas is mainly supplied to domestic
fertilizer plants in Indonesia.
– Production commenced in October 2013.

＊ on the basis of all fields and average rate for Mar. 2017＊＊ Volume not at wellheads but corresponding to the sales to buyers

19

Berau Block (Tangguh LNG Project)
MI Berau B.V. / MI Berau Japan Ltd.
– MI Berau B.V./MI Berau Japan Ltd.* : Joint
venture with Mitsubishi Corporation (INPEX
44%, Mitsubishi Corp. 56%)

West Papua Province(Indonesia)*MI Berau Japan owns a share of approximately 16.5% KG Berau Petroleum Ltd.

Berau Block

Kaimana

Gas field＊ on the basis of all fields and average rate for Mar. 2017＊＊ Volume not at wellheads but corresponding to the– Participating Interest:• MI Berau: 16.3% of Tangguh Unit
• KG Berau Petroleum: 8.56% of Tangguh
Unit(Operator: BP)– Production volume*:• Condensate: Approximately 6,000 bbl/d• Natural Gas**: Approximately 1,048 million
cf/d– PSC: Until 2035
– LNG production capacity: 7.6 million tons per
year– LNG sales started in July 2009
– Made FID for an expansion project to add a third
LNG train with a 3.8 million t/y production capacity
in July 2016

sales to buyers
20

JPDA03‐12 /JPDA03‐13 Block (Bayu‐Undan Gas Condensate Field)
INPEX Sahul, Ltd.
– Participating Interest: 11.378120%(Operator: ConocoPhillips)– Production volume*:• Condensate: Approximately 18,000
bbl/d• LPG: Approximately 11,000 bbl/dIndonesia
Australia

Kitan Oil Field

JPDA03‐12 Block
JPDA03‐13 Block––Gas field
Oil field

50 km

Bayu‐Undan
Gas/Condensate Field

Darwin––＊ on the basis of all fields and average rate for Mar. 2017＊＊ Volume not at wellheads but corresponding to thesales to buyers
21• Natural Gas**: Approximately 555
million cf/d
PSC: Until 2022
Sales of condensate and LPG started in
February 2004
Entered into an LNG Sales Contract
with TEPCO (currently JERA) andTokyo Gas in August 2005
(3 million t/y for 17 years from 2006)
LNG sales started in February 2006

Van Gogh, Coniston and Ravensworth oil fields
INPEX Alpha, Ltd.
Coniston Oil Field
Australia

WA‐55‐L
Block
Van Gogh Oil Field

WA‐35‐L
Block

Ravensworth Oil Field
WA‐43‐LBlock
Gas field
Oil field

Onslow

WA‐42‐L Block(No Participating
Interest)

Australia

Exmouth050km＊ on the basis of all fields and average rate for Mar. 201722

Van Gogh Oil Field(WA‐35‐L) / Coniston Oil Field(WA‐35‐L/WA‐55‐L)– Participating Interest: 47.499%(Operator: Quadrant Energy)– Concession Agreement: Production license granted in
October 2008
– Production volume*:• Crude Oil: Approximately 9,000bbl/d– Van Gogh Oil Field: Production started in February 2010
– Coniston Oil Field: Production started in May 2015
– Novara Structure (Coniston Oil Field): Production
started in July 2016
Ravensworth Oil Field (WA‐43‐L)– Participating Interest: 28.5% (Operator : BHPBP)– Production volume*:
Crude Oil: Approximately 6,000bbl/d– Concession Agreement: Production license granted in
November 2009
– Tied in to the production facilities of the adjacent WA‐
42‐L block– Production started in August 2010

Ichthys LNG Project
Overview– Marketing: LNG: Secured LNG SPAs covering 8.4 million t/y of LNG
 LPG: Reached an agreement in principle on the sale of the entire volume of INPEX’s share– Key permits:
 All environmental, pipeline and production licenses obtained– Project Financing: US$ 20 billion project financing agreements with ECAs and major commercial banks completed
in December 2012
– EPC work: Major EPC contracts awarded
Upstream
CPF: Samsung Heavy Industries,
FPSO: Daewoo Shipbuilding & Marine Engineering,
Subsea Production System (SPS)： GE Oil & Gas,
Umbilical, Riser and Flowline (URF)： McDermott

Kyushu Electric Power0.30 mtpa
JERA (former Chubu
Electric Power portion)
0.49 mtpa
Osaka Gas
0.80 mtpa
Kansai ElectricPower0.80 mtpa

LNG Sales
volume:8.4MTPA

CPC Corporation,
Taiwan1.75 mtpa

JERA (former Tokyo
Electric Power portion)
TOTAL
1.05 mtpa
Tokyo Gas
0.90 mtpa
1.05 mtpa
INPEX CORPORATION
0.90 mtpa
Approximately 70% of the LNG to be delivered toJapanese buyers

Downstream
Onshore LNG Plant: JGC, Chiyoda and KBR,
Gas Export, Pipeline(GEP): SaipemS.p.A, Mitsui Corporation,
Sumitomo Corporation and Metal One Corporation,
Dredging in Darwin Harbour: Van Oord,
Instrumentation and Control System: Yokogawa Electric (including upstream facilities)
23

Toho Gas
0.28 mtpa

Ichthys LNG Project
Development Concept

Central Processing Facility
Floating Production,(CPF)
Storage and Offloading
Condensate(FPSO)

LNG, LPG, Condensate
Onshore LNG Plant(Darwin)

Offtake
Tanker
Upstream Downstream

Flowlines

Gas Export Pipeline(GEP)

Subsea Production
System24

Ichthys LNG Project
Production well testing

Drilling rig ENSCO5006 conducting
production testing(Ichthys Field, January 2017)25

Ichthys LNG Project
Progress on offshore facilities

FPSO undergoing commissioning(South Korea, March 2017)26

Ichthys LNG Project
Progress on onshore facilities①

27

Construction of Combined Cycle Power Plant(Darwin, April 2017)

Ichthys LNG Project
Progress on onshore facilities②

Product loading jetty(Darwin, April 2017)28

Abadi LNG Project
Tanimbar Islands

INDONESIA

Saumlaki
EAST TIMOR

Masela Block

Arafura Sea

Abadi Gas Field

Timor Sea Joint Petroleum
Development Area

AUSTRALIA

Darwin0100■Participating Interest‐ INPEX(Operator): 65%, Shell: 35%■Current phase: Preparation for Development
29

200km

 Received notification from the Indonesian
government instructing to re‐propose aplan of development based on onshore
LNG in April 2016
 Aiming for an early realization of the
project and currently engaged inconstructive discussions with theIndonesian government on the optimal
development of the Abadi Gas Field withan eye to begin Pre‐FEED work Strategic
alliance with Shell‐ Shell provides technical and humanresources support
 PS Contract requires transfer of 10%
participating interest to an IndonesianParticipant to be designated by theIndonesian government.
 PSC: Until 2028

Prelude FLNG Project
INPEX Oil & Gas Australia Pty Ltd.
– Participating Interest: 17.5% (Operator: Shell)– Reserves: approximately 3 trillion cf of natural gas (Prelude
and Concerto gas fields)– Production volume: 3.6 million t/y of LNG, along with 0.4
million t/y of LPG and approx. 36,000 bbl/d of condensate
at peak– FID made in May 2011
– Targeting production start‐up around 10 years from when
the Prelude gas field was first discovered in early 2007.
Expecting material cash in 2018
– Reached agreements on LNG sales and purchases (for 8
years commencing in 2017) with JERA (approximately 0.56
MTPA) and Shizuoka Gas (approximately 0.07 MTPA)
respectively from INPEX’s equity portion of the project’s
LNG output (approximately 0.63MTPA)

FLNG
30

ACG Oil Fields
INPEX Southwest Caspian Sea, Ltd.
50km
Caspian Sea

Azerbaijan
Baku

ACG

Deepwater Gunashli Field
Chirag Field

Kazakhstan
RussiaAzeri Field
The Aral Sea
Uzbekistan
The Caspian Sea

Georgia

Armenia

Azerbaijan
Turkmenistan

Iran

500km

＊ on the basis of all fields and average rate for 201631

Oil field– Participating Interest: 10.9644%(Operator: BP)– Production volume*• Crude Oil: Approximately 630,000
bbl/d– PSC: Until 2024
– Started oil production in the Chirag Field
in 1997– Phase 1: Started oil production in thecentral section of the Azeri Field in
February 2005
– Phase 2: Started oil production in thewestern section of the Azeri Field in
December 2005 and in the eastern sectionof the Azeri Field in October 2006
– Phase 3: Started oil production in the
Deepwater Gunashli Field in April 2008
– Western section of Chirag Field (Chirag
Oil Project): Started oil production in
January 2014

Kashagan Oil Field, others
INPEX North Caspian Sea, Ltd.
– Production volume•

Kairan Structure
Kashagan oil field

Caspian Sea

Crude Oil: Production ramped up to acapacity of 180,000 bbl/d in February 2017.
In Phase 1, production capacity is
expected to reach 370,000 bbl/d by the endof 2017.

– Production began in September 2013, but wassuspended in October 2013 due to pipeline
gas leak.

Aktote Structure
RussiaKazakhstan

China

TurkeyIranKalamkas Structure

India

Gas field
Oil field– The pipeline was replaced and production
restarted in September 2016 with the firstbatch of crude oil dispatched in October 2016.

– Kalamkas structure undergoing studies on
potential joint development with adjacent– Participating Interest: 7.56% (Operator:
field.
NCOC (North Caspian Operating Company))– Aktote and Kairan structures undergoingevaluation studies.

– PSC: Kashagan – Until 2021**Current PSC provides option to extend the contract period by 2
x 10 years (until 2041)

32

BTC (Baku‐Tbilisi‐Ceyhan) Pipeline Project
INPEX BTC Pipeline, Ltd.
RUSSIA

Black Sea

BTC Pipeline

TbilisiGEORGIAARMENIA

CaspianSea

Baku

AZERBAIJAN

TURKEY

CeyhanCYPRUS
Mediterranean
Sea

33

IRAN

SYRIA
IRAQ

– Participating Interest: 2.5%
(Operator : BP)– Acquired a 2.5% participating interest in
the operating company (BTC Co.) through
INPEX BTC Pipeline, Ltd. in October 2002
– Commenced crude oil export in June 2006
from Ceyhan terminal– Completed 1.2 million bbl/d capacity
expansion work in March 2009
– Cumulative export volume reached 1,000
million bbls on September 13, 2010
– Cumulative export volume reached 2,000
million bbls on August 11, 2014

ADMA Block
Japan Oil Development Co., Ltd. (JODCO)Oil Field under Production
Subsea Pipeline

Nasr Oil Field

Umm Shaif Oil Field
Das Island

Upper / Lower Zakum Oil Fields

Satah Oil Field
Zirku Island– Umm Shaif / Lower Zakum / Umm Lulu /Nasr oil fields• Participating Interest: 12.0% (Operator:
ADMA‐OPCO*)– Upper Zakum / Umm Al‐Dalkh / Satah oil
fields• Participating Interest:
Upper Zakum / Umm Al‐Dalkh: 12.0%
Satah: 40.0%(Operator: ZADCO*)

Umm Al‐Dalkh Oil Field
Abu Dhabi
Umm Lulu Oil Field*Operating company owned by companies with participating interests.
JODCO has a 12% share in both operating companies.

– Concession agreement: Until 2018 (until
2041 for Upper Zakum Oil Field)– Continuous development being
undertaken to maintain and increase
production levels
 Implementing full field development
plans for Umm Lulu and Nasr oil fields
 Implementing a redevelopment planfor Upper Zakum Oil Field using
artificial islands

34

ADCO Onshore Concession
JODCO Onshore Limited
Abu Dhabi
Al Dhabbiya Field
Jumaylah Field
Uwaisa Field
Bub Field

Bida Al‐Qemzan Field

Shanayel Field
Rumaitha Field
Arjan Field
Sahil Field

UAE

Bu Hasa Field
Huwailla Field

Asab Field

Qusahwira Field

Pipeline
Producing Oil Field
Undeveloped Oil Field

35

Shah Field
Mender Field– Participating interest: 5% (Operator:
ADCO* (Abu Dhabi Company for
Onshore Petroleum Operations))– Production volume: Approximately 1.6
million bbl/d– Concession agreement: Until 2054
– Signed the ADCO Onshore Concessionagreement with the Government of Abu
Dhabi and ADNOC in April 2015.
– Works in progress to expand production
capacity to 1.8 million bbl/d*Operating company owned by companies with participating interests.
JODCO Onshore Limited has a 5% share in the operating company

Venezuela Projects
Teikoku Oil & Gas Venezuela, C.A., other
Teikoku Oil & Gas Venezuela, C.A.

Copa Macoya / Guarico Oriental Blocks– INPEX’s share in joint ventures• Gas JV: 70%
Oil JV: 30%– Joint Venture Agreement: 2006‐2026– Production volume*:• Crude Oil: Approximately 1,000 bbl/d• Natural Gas**: Approximately 84
million cf/d

Copa Macoya / Guarico Oriental Blocks

A T L A N T I C
O C E A N

CaracasVenezuela

BRAZIL＊ on the basis of all fields and average rate for Mar. 2017＊＊ Volume not at wellheads but corresponding to thesales to buyers
36

Brazil Projects
Frade Japão Petróleo Limitada (FJPL), other
Frade Japão Petróleo Limitada (FJPL)– FJPL’s Participating interest*: 18.3%(Operator: Chevron)

BrazilVitória

BM‐ES‐23*FJPL is an equity method affiliate of INPEX.
(INPEX owns a 37.5% share of FJPL)
Atlantic Ocean –BrazilFrade Block
Campos
Macaé

Production volume**:• Crude Oil: Approximately 20,000 bbl/d• Natural Gas***: Approximately
1 million cf/d

Rio de Janeiro– Concession Agreement: Until 2025

BM‐ES‐23– Participating Interest: 15%100km– Under Exploration (Appraisal)

Oil and Gas field0** on the basis of all fields and average rate for Mar. 2017*** Volume not at wellheads but corresponding to the sales tobuyers37

Canada Shale Gas Projects
INPEX Gas British Columbia Ltd.

‐ Participating Interest: 40%*(Operator: Nexen)
Shale Gas Assets

Alberta

British Columbia* INPEX Gas British Columbia Ltd. (Equity ratio: INPEX 45.09%,
JOGMEC 44.89%, Canadian Subsidiary of JGC Corporation
10.02%).

‐ Production Volume**:Prince Rupert
Edmonton
200km
Calgary

Natural Gas***: Approximately 79 million
cf/d‐ Concession Agreement

CanadaVancouver
Victoria

Central Azeri Platform** on the basis of all fields and average daily volume for 2016*** Volume not at wellheads but corresponding to the sales to buyers
Hydraulic fracturing site

38

Gulf of Mexico Projects
Teikoku Oil (North America) Co., Ltd. , INPEX E&P Mexico, S.A. de C.V.
Shallow Water Area
(Teikoku Oil (North America) Co., Ltd.)– Concession Agreement– Participating Interest:
Ship Shoal 72: 25%
TexasLouisiana

Mexico0500

1,000km

Ship Shoal
72
CUBA

Keathley Canyon Block874/875/918/919(Lucius Field)
Perdido Area Block 3＊ on the basis of all fields and average rate for Mar. 2017＊＊ Volume not at wellheads but corresponding to the sales to buyers

39

Lucius Field(Teikoku Oil (North America) Co., Ltd.)－ Concession Agreement－ Participating Interest: 7.75309% (Operator :Anadarko)－ Production started in January 2015
－ Production volume*• Crude Oil: Approximately 48,000 bbl/d• Natural Gas**: Approximately 53 million cf/d
Block 3, Perdido Fold Belt, Mexican Gulf of Mexico（INPEX E&P Mexico, S.A. de C.V.）– License Agreement– Participating interest: 33.3333% (Operator: Chevron)– Signed a license agreement on February 28, 2017
Exploration plans are currently being developed

Offshore D.R. Congo
Teikoku Oil (D.R. Congo) Co., Ltd.
Offshore D.R. Congo Block– Participating Interest: 32.28%(Operator: Perenco)

MwanbeMisatoMibale– Concession Agreement: 1969‐2023

Libwa

MotobaD.R. CONGO– Production started in 1975

Lukami– Production volume*

Moko
Tshiala•MuandaGCO

BananaAtlantic Ocean

Crude Oil: Approximately
12,000 bbl/d

Soyo

ANGOLAOil field

0

5

10km

＊ on the basis of all fields and average rate for Mar. 201740

Offshore Angola Block 14
INPEX Angola Block 14 Ltd.
Rep. of
Congo

Offshore Angola
Block 14
D.R. Congo– Participating Interest: 9.99%(Operator: Chevron)– Production volume*• Crude Oil: Approximately 98,000 bbl/d– PSC: Until 2035

Republic ofAngolaAtlantic Ocean

100km＊ on the basis of all fields and average rate for Mar. 201741

Sakhalin I
Sakhalin Oil and Gas Development Co., Ltd.
05–

Sakhalin Oil and Gas Development Co., Ltd. (SODECO):INPEX owns a share of approximately 6.08% in SODECO–SODECO’s Participating interest in Sakhalin I: 30.0%–

Production volume*:

10km

Gas field
Oil Field

OdoptuStructure

Sakhalin
IslandVal•

Crude oil and condensate: Approximately 183,000 bbl/d•Natural Gas: Approximately 850 million cf/d–

Operator: ExxonMobil–

PSC: Until December 2021**–

Commenced production from Chayvo Structure in October
2005; commenced crude oil export in October 2006–

Commenced production from Odoptu Structure in
September 2010–

Commenced production from Arkutun‐Dagi Structure in
January 2015–

Currently supplying natural gas to Russian domestic market

ChayvoStructure
Arkutun‐Dagi
Structure＊**Current PSC provides the option to apply for a 10‐year contract extension
multiple times.

on the basis of all fields and average rate for 201642

Block 10, Iraq
INPEX South Iraq, Ltd.
TurkeyTurkey
Iraq

Iran

Erbil

Saudi Arabia

Iran

BaghdadIraq

West Qurna Oil Field
Gharraf Oil Field

Nasiriyah Oil Field
Basra

Block 10

Saudi Arabia

0

100km

Rumaila Oil Field

Location Map of Block10, Iraq

43

– Participating Interest: 40%(Operator: LUKOIL)– Block acquired: December 2012
(Republic of Iraq 4th Licensing Round)– EDPSC*:
Exploration Period‐5 years**(Until December 3,
2017)
Development and Production Period‐20years**– A production volume capacity of more than 8,000
barrels per day was confirmed through crude oil
production tests conducted at the first
exploratory well in February 2017.
*Exploration, Development and Production Service Contract**Current service contract provides the option to extend the
Exploration Period twice by 2 years and the Development andProduction Period by 5 years.

Key Companies and Petroleum Contracts I*
Company

Field / Project NameCountry

Contract Type Ownership StageJapan•INPEX CORPORATION

Minami‐Nagaoka Gas Field, etc. **JapanConcession‐

Producing

Asia/Oceania•INPEX CORPORATION

Offshore Mahakam BlockIndonesia

PS‐

Producing•INPEX South Makassar, Ltd.

Sebuku Block(Ruby Gas Field)

Indonesia

PS

100%

Producing•MI Berau B.V.

Berau Block (Tangguh LNG Project) Indonesia

PS

44%

Producing•INPEX Masela, Ltd.

Masela Block (Abadi LNG)**

Indonesia

PS

51.9%

•INPEX Sahul, Ltd.

Bayu‐Undan Gas Condensate Field

JPDA

PS

100%

Producing•INPEX Browse E&P Pty Ltd

WA‐285‐P**, other

Australia

Concession

100%

Exploration•INPEX Ichthys Pty Ltd.

WA‐50‐L and WA‐51‐L (Ichthys) **Australia

Concession

100%

Development•Ichthys LNG Pty Ltd.

Ichthys downstream business **Australia‐

62.245%Development

Australia

Concession

100%

Development•INPEX Alpha, Ltd.

Van Gogh Oil Field/Coniston Oil Field Australia

Concession

100%

Producing•INPEX Alpha, Ltd.

Ravensworth Oil Field

Concession

100%

Producing•INPEX Oil & Gas Australia Pty Ltd. Prelude FLNG Project

Australia

Preparation for Development

Note：* As of the end of March 2017** Operator project44

Key Companies and Petroleum Contracts II*
Company

Field / Project NameCountry

Contract Type Ownership Stage•INPEX Southwest Caspian Sea, Ltd.

ACG Oil Fields

Azerbaijan

PS

51%

Producing•INPEX North Caspian Sea, Ltd.

Kashagan Oil Field

Kazakhstan

PS

45%

ProducingEurasia (Europe – NIS)

The Middle East
•JODCOADMA Block (Upper Zakum, etc.) UAE

Concession

100%

Producing•JODCO Onshore Limited

ADCO Onshore Concession

UAE

Concession

51 %Producing•Teikoku Oil (D.R. Congo) Co., Ltd.

Offshore D.R.Congo

D.R.Congo

Concession

100%

Producing•INPEX Angola Block 14 Ltd.

Offshore Angola Block 14

AngolaPS

100%

Producing•INPEX Gas British Columbia Ltd.

Canada Shale Gas project

CanadaConcession

45.09%

Producing/Evaluation•Teikoku Oil & Gas Venezuela, C.A.

Copa Macoya** / Guarico Oriental Venezuela

AfricaAmericas
JV

100%

Producing•Teikoku Oil (North America) Co., Ltd. Lucius Field / Ship Shoal 72

USA

Concession

100%

Producing•Frade Japão Petróleo Limitada

BrazilConcession

37.5%***

Producing

45

Frade Block

Note：* As of the end of March 2017** Operator project*** Frade Japão Petróleo Limitada is a subsidiary of INPEX Offshore North Campos, Ltd. (INPEX equity‐method affiliate). 37.5% ownership refers to indirect investment
from INPEX through INPEX Offshore North Campos, Ltd.

Others

Proved Reserves*(compared to majors and global independent E&P companies)(Million BOE)

25,00020,00015,000Gas

19,974

Oil

17,81047.1%

42.0% 13,248
11,518 11,122

10,000

5,000

52.8%

53.0% 43.1% 7,490

54.6% 39.5%

52.9% 58.0%
47.2% 47.0% 56.9%

0

47

6,424
5,013

3,304
2,406 2,382
1,722 1,311
33.1%
1,080
26.1%
60.5%
45.4%
75.5%
42.8%
48.0% 66.9% 73.9%
36.4% 86.5% 485
24.5% 57.2% 63.6%
91.8%
52.0%

Source: Most recent publicly available information
Note :* All data as of December 31, 2016, except for INPEX data (as of March 31, 2017). INPEX data listed in accordance with SEC regulations. The reserves cover most INPEX Group projects including
equity method affiliates. The reserves of the projects which are expected to be invested a large amount and affect the company’ future result materially are evaluated by DeGolyer & MacNaughton,
and the others are done internally. Government‐owned companies are not included. Oil reserves include bitumen and synthetic oil.

Production Volume*(compared to global E&P companies)(Thousand BOE/d)

5,000
4,500

Gas
Oil

4,053

4,000

3,668

3,500
3,000

3,268
41.6%
49.9% 37.3% 2,594 2,452

2,500

33.7%

2,000

48.2%

1,500
1,000

1,839
43.8%

58.4%

50.1% 62.7%

66.3%

500

51.8% 56.2%

048

1,671 1,569
47.5% 41.0%

792

690

630
522
521
26.3%
64.8%
168
52.5% 59.0%
35.2% 33.2% 259
55.9% 35.2% 73.7% 64.8% 66.8% 80.7% 79.8%
19.3% 20.2%
44.1%

Source: Most recent publicly available information*
All data for the year ended December 31, 2016 except for INPEX data (for the year ended March 31,2017). INPEX data listed in accordance with SEC regulations. Amounts
attributable to the equity method are included. Government‐owned companies are not included. Oil production include bitumen and synthetic oil.

Factor Analysis of Change in Proved Reserves*(Million BOE)
4,000

25

3,500

197

3,000

(2)

2,500

(181)

2,000
1,500

3,304

3,264

1,000
500
0
Mar. ’16

Extensions andRevisions of
Discoveries** previous estimates* The definitions of proved reserves are listed on page 51.
** Including acquisitions and sales

49

Impact of
Change in
Oil Prices

Productionin the Year ended
March 31, 2017

Mar. ‘17

Factor Analysis of Change in Probable Reserves*(Million BOE)

5

1,800
1,600
1,400

(313 )

1,200

(8)

1,000
800

1,705

1,389

600
400
200
0
Mar. ’16

Extensions andDiscoveries**

Revisions ofprevious
estimates

Impact of
Change in
Oil Prices

Mar. ’17* The definitions of probable reserves are listed on page 52.
** Including acquisitions and sales.

50

Definition of Proved Reserves51– Our definition of proved reserves is in accordance with the SEC Regulation S‐
X, Rule 4‐10, which defines proved reserves as the estimated quantities of oil
and gas, which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically producible—from agiven date forward, from known reservoirs, and under existing economic
conditions, operating methods, and government regulations—prior to thetime at which relevant petroleum contracts providing the right to operate
expire.
– To be classified as a proved reserve, the SEC rule requires that extraction of
the hydrocarbons must have commenced or the operator must be reasonably
certain that it will commence extraction within a reasonable time . Thisdefinition is known to be conservative among the various definitions ofreserves used in the oil and gas industry.
– When probabilistic methods are employed, there should be at least a 90%
probability that the quantities actually recovered will equal or exceed theestimated proved reserves.
– The SEC rule separates proved reserves into two categories; proved
developed reserves which can be recovered by existing wells, infrastructure
and operational methods, and proved undeveloped reserves which require
future development of wells and infrastructure to be recovered.

Definition of Probable and Possible Reserves– Probable reserves, as defined by SPE/WPC/AAPG/SPEE, are those
unproved reserves which analysis of geological and engineering datasuggests are more likely to be commercially recoverable after the proved
reserves.
– In this context, when probabilistic methods are used, there should be atleast a 50% probability that the quantities actually recovered will equal or
exceed the sum of estimated proved plus probable reserves.
– Possible Reserves, as defined by SPE/WPC/AAPG/SPEE, are thoseadditional reserves which analysis of geoscience and engineering data
indicates are less likely to be recoverable than Probable Reserves.
– In this context, when probabilistic methods are used, there should be atleast a 10% probability that the quantities actually recovered will equal or
exceed the sum of estimated proved plus probable plus possible reserves*Probable reserves and possible reserves do not offer a guarantee of the
production of total reserves during a future production period with the samecertainty of proved reserves.

52

Medium‐ to Long‐Term Vision*
Three Growth Targets and Key Initiatives
1. Continuous Enhancement of E&P Activities→Achieve a net production volume of 1 million boe/d by the early 2020s

2. Strengthening of Gas Supply Chain→Achieve a domestic gas supply volume of 2.5 billion m3/yearin the early 2020s

3. Reinforcement of Renewable Energy Initiatives→Promote efforts to commercialize renewable energies and reinforce R&D
activities for the next generation

Three Management Policies and Our Vision
1. Securing / Developing Human Resources and Building
an Efficient Organizational Structure
2. Investment for Growth and Return for Shareholders
3. Responsible Management as a Global Company*

53

Announcement in May 2012Investment Plan and Financing Measures
Approximately 3.5 trillion yen
For investment in Ichthys, Abadi and other E&P projects etc.
during the 5‐year period* until Ichthys start‐up

Available Funds
Approximately 663.0
billion yen in available
funds (As of March 31,
2017)Cash FlowOperating cash flow
(275.8 billion yen in
the fiscal year ended
March 31, 2017)
Cash and other liquid
investments on hand

54

Bank Loans
Sizeable lending fromJBIC** together withcommercial banks
Guaranteed by
JOGMEC*** for a certain
portion of loans fromcommercial banks
Project finance*
From FY 2013 to FY 2017** JBIC : Japan Bank for International Cooperation*** JOGMEC : Japan Oil, Gas and Metals National Corporation

Finance Strategies
Advantage of low‐cost funding
Maintain strong balance sheet
to achieve financial stability
and secure further debt capacity

Leverage relationships withgovernmental financial
institutions, such as JBIC andJOGMEC, to fund developmentcosts Maintain funding capability to ensure necessary investments for
major projects such as Ichthys and Abadi
 Maintain strong balance sheet to enable continuous investments
in potential projects in the future Long‐term target financial leverage Equity Ratio : 50% or higher
 Net Debt / Total Capital Employed Ratio: 20% or less55

Annual Dividends, Payout Ratio
（yen）

180%

20.00
17.50

18.00

18.00

17.50

18.00

18.00

18.00

18.00
160%

16.00

140%
13.75

14.00

157%

120%

12.00

100%

10.00
80%

8.00

60%

6.00
34%

57%

4.00
13%

15%

2.00

56%

14%

14%

40%
20%
0%

0.00
2011/3

2012/3

2013/3

2014/3

Dividends

2015/3

2016/3

Payout Ratio (right axis)

2017/3

2018/3(Forecast)
Beginning of term

56

CSR Topics
 INPEX engages in a variety of CSR activities focused on the following 6 material issues＜CSR Material Issues＞


Governance

HSE

ClimateChangeDevelopment of a governance framework
Appropriate information disclosure and
improvement of transparency
Development of a risk management
CompliancesystemSafety management in operations
Prevention of major incidents
Mitigation of environmental impacts
Conservation of biodiversityManagement of greenhouse gas emissions
Promotion of renewable energy businesses
Promotion of new technology R&D




Local
Communities 

Employees

Observance of laws, regulations, andsocial norms
Prevention of bribery and corruption
Respect for human rights
Evaluation and reduction of
impact on local communities
Contribution to local economies
Consideration for the indigenous
community
Development of globally competenthuman resources
Promotion of diversity
Creation of employee‐friendly workplaceenvironments

INPEX announced that it has published its
Modern Slavery Act Statement FY2015 (theStatement) on its website in order to clarify its
initiatives to address human rights violations
such as slavery and human trafficking in thebusiness and supply chain of the INPEXGroup as well as the risks thereof.

＜External evaluation of INPEX CSR activities and the major SRI indexes＞

57

Dow Jones
Sustainability World Index

INPEX has been listed on the Dow Jones Sustainability World Index (DJSI World), an index thatexemplifies socially responsible investing produced by Dow Jones Inc. in the U.S. and RobecoSAM in
Switzerland.

FTSE4Good
Global/Japan Index

FTSE Russell confirms that INPEX has satisfied the requirements to become a constituent of the
FTSE4Good Index Series. We are the member of the FTSE4Good Global and Japan Index.

CDP

INPEX achieved a rating of A‐ in the CDP Climate Change Report. In 2013 and 2014, INPEX wasselected for inclusion in the CDP Climate Disclosure Leadership Index (CDLI) as a company
demonstrating excellent climate change disclosure practices.

Morningstar Socially
Responsible Investment Index(MS‐SRI)INPEX has been selected as a component of the ʺMorningstar Socially Responsible Investment Indexʺ
(MS‐SRI) since 2013. MS‐SRI is the first SRI index in Japan produced by Morningstar Japan K.K.

MSCI Global Sustainability
Indexes

INPEX are constituent of the MSCI Global Sustainability Indexes, a leading set of indexes in theselection of outstanding companies in ESG developed by Morgan Stanley Capital Investment (MSCI).

ECPI Ethical Index Global

INPEX has been selected by ECPI for inclusion in the following SRI Index: ECPI Global Carbon Equity
Index, ECPI Global Megatrend Equity Index and ECPI World ESG Equity Index

Production Sharing Contracts

Cost Recovery Portion

1. Cost Recovery Portion Non‐capital expenditures recovered
during the current period
 capital
expenditures
recoveredduring the current period Recoverable costs that have not been
recovered in the previous periods

Host Country Profit Oil

Contractor
Profit Oil

2. Equity Portion (Profit Oil)

Host Country
Share

Contractor
Share: Host Country Take
: Subject to Tax

Contractor Take

: Not Subject to Tax
58

Accounting on Production Sharing Contracts
Cash Out

Assets on Balance Sheet

Income Statement

Project under exploration phase
Exploration Expenditures

Recoverable accounts under
production sharing

Project under development andproduction phase
Development Expenditures
Recoverable accounts under
production sharing
Production Costs(Operating expenses)

Project under development andproduction phase
Acquisition Costs

59

Exploration and development
rightsProvision for allowance forrecoverable accounts under
production sharing

Cost of sales Recovery of recoverable accounts
under production sharing (Capital
expenditures)

Cost of sales Recovery of recoverable accounts
under production sharing (Non‐Capital expenditures)

SG&A Depreciation and amortization
Other Expenses
 Amortization of exploration anddevelopment rights

Accounting on Concession Agreements
Cash Out

Assets on Balance Sheet

Income Statement

All exploration costs are
expensed as incurred
Exploration Expenditures

Exploration expenses

Development Expenditures

Production Costs(Operating expenses)

Tangible Fixed Assets

All production costs are
expensed as incurred

Acquisition Costs

Mining Rights

Cost of sales(Depreciation and amortization)

Cost of sales(Operating expenses)

Cost of sales(Depreciation and amortization)

60

Summary of Australian Taxation※Content may change due to tax revisions
Sales
Operating expense⇒(Oil/Gas sales price)×(Sales volume)

・・・・・・・・・①⇒OPEX incurred in relevant year (+Exploration cost)+CAPEX tax depreciation

・・・・・・・・・②

PRRT(Petroleum Resource Rent Tax)=(Upstream Revenue－Upstream Capex & Opex－ Expl. Cost－Abandonment Cost－ undeducted
PRRT expenditure carried forward)×40%
・・・・・・・・・・・・・・③
・PRRT deductions are made in the following order: Upstream Capex, Opex, Expl. Cost,
Abandonment Cost.
Note: Exploration cost is subject to mandatory transfer between Projects/members of the same group ofentities.

Corporate Tax(In Australia)
・Undeducted PRRT Expenditure: non‐utilized deductible PRRT expenditure can be carriedforward to the following year(s), subject to augmentation at the rates set out below;
Development cost: LTBR+5%; Expl. Cost: LTBR+15%;*GDP Factor applies to all expenditure incurred more than 5 years before the Production License
application is made.
*LTBR = Long Term Bond Rate
*GDP Factor = GDP Deflator of Australia

Corporate Tax＝ (①－②－③－Interest paid)×30％

61

Crude Oil Price Movements(US$/bbl)
120
Brent

110

WTI

Dubai

100
90
80
70
60
50
40
30
20
10
0
Apr. May Jun. Jul. Aug. Sep. Oct. Nov. Dec. Jan. Feb. Mar. Apr. May Jun. Jul. Aug. Sep. Oct. Nov. Dec. Jan. Feb. Mar. Apr. May Jun. Jul. Aug. Sep. Oct. Nov. Dec. Jan. Feb. Mar.

2014

Brent
WTI
Dubai

62

Apr. 2015‐Mar. 2016
Average
48.73
45.00
45.54

2015

2016

2017

2016
Apr.
43.34
41.12
39.03

2017
May
47.65
46.80
44.27

Jun.
49.93
48.85
46.26

Jul.
46.53
44.80
42.46

Aug.
47.16
44.80
43.70

Sep.
47.24
45.23
43.33

Oct
51.39
49.94
48.98

Nov
47.08
45.76
43.86

Dec
54.92
52.17
52.10

Jan
55.45
52.61
53.72

Feb
56.00
53.46
54.44

Apr. 2016‐Mar. 2017
Mar
Average
52.54
49.88
49.67
47.93
51.20
46.95