Financial results for the six months ended September 30, 2013
Appendix

November 8, 2013

Subsidiaries and Affiliates
61 consolidated subsidiaries
Major subsidiaries

Country/region

OwnershipStage

Accounting term

Japan Oil Development

UAE

100%

Production

March (provisional
settlement of account)

INPEX Natuna

Indonesia

100%

Production

March

INPEX Sahul

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

Azerbaijan

51%

Production

March (provisional
settlement of account)

INPEX North Caspian Sea

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

18 equity method affiliates
OwnershipStage

Accounting term

MI Berau B.V.

Major affiliates

Indonesia

44%

Production

DecemberAngola Block 14 B.V.

Angola49.99%

Production/
Development

December

INPEX Offshore North Campos

Brazil

37.5%

Production

DecemberDevelopment

March (provisional
settlement of account)

Ichthys LNG Pty Ltd

1Country/region

Australia

66.07%

Segment Information

For the six months ended September 30, 2013(April 1, 2013 through September 30, 2013)(Millions of yen)
Reportable segments

Sales to third parties

Eurasia(Europe &NIS)

52,099238,430

54,106300,879

4,961

650,478－

650,478

6,340

117,026

26,258203,715(4,145)349,195(4,961)

344,234

Segment income (loss)

MiddleEast &
AfricaAdjustments Consolidated*1*2

Asia &
Oceania

Japan

Americas

Total

Note: 1. Adjustments of segment income of ¥(4,961) million include elimination of inter‐segment transactions of ¥113 million and corporate expenses of ¥(5,074)
million. Corporate expenses are mainly amortization of goodwill that are not allocated to a reportable segment and general administrative expenses.
2. Segment income is reconciled with operating income on the consolidated Statements of Income.

2

LPG Sales
Apr.‐Sep. ‘12

Change%Change

Net Sales (Billions of yen)

14.4

10.8

(3.6)

(25.1%)

Sales volume (thousand bbl)

2,154

1,462

(692)

(32.1%)

Average unit price of overseas
production ($/bbl)

80.80

75.74

(5.06)(6.3%)

Average unit price of domestic
production(¥/ kg)

119

93

(5)

(21.7%)

Average exchange rate (¥/$)

79.40

97.84

18.44 yendepreciation

23.2% yendepreciation

Change%Change

Sales volume by region(thousand bbl)

Apr.‐Sep. ‘12

Apr.‐Sep. ‘13

Japan

131
( 12 thousand ton)

4
(0thousand ton)

(127)(‐12.1 thousand ton)

(97.2%)

Asia/Oceania

2,023

1,459

(565)

(27.9%)

Eurasia (Europe/NIS )

‐

‐

‐

‐

Middle East/Africa

‐

‐

‐

‐

Americas

‐

‐

‐

‐

2,154

1,462

(692)

(32.1%)

Total

3

Apr.‐Sep. ‘13

EBIDAX
Apr.‐Sep. ‘12

Apr.‐Sep. ‘13

111,382

80,080(31,301)

P/L

Minority interests

4,152

207

(3,944)

P/L

Depreciation equivalent amount

55,65258,241

2,589

Depreciation and amortization

25,96823,958(2,009)Amortization of goodwill

3,380

3,380

‐

Recovery of recoverable accounts(capital expenditure)

26,30430,903

4,598

9,580

17,714

8,134

Exploration expenses

4,090

16,678

12,587

P/L Exploration expense under concession agreements

Provision for allowance for recoverable
accounts under production sharing

3,239

416

(2,822)

P/L Exploration expense under PS contracts

Provision for exploration projects

2,251

620

(1,630)P/L Exploration expense under PS contracts

10,791

48,62437,833

Deferred income taxes

12,031

42,58430,553

P/L

Foreign exchange loss

(1,240)

6,040

7,280

C/F

Net interest expense after tax(1,686)(5,121)(3,435)EBIDAX

189,871

199,7459,876(Millions of yen)
Net income

Exploration cost equivalent amountMaterial non‐cash items

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

P/L After‐tax interest expense minus interest income

4

Analysis of Recoverable Accounts
under Production Sharing(Millions of yen)

Apr.‐Sep. ‘12

Balance at beginning of period
Exploration costs

568,318
7,143

590,565
15,462Development costs

61,196

84,414

Operating expenses

25,47235,242

Other

2,265

6,340

Balance at end of period

26,30450,141
26,678561,271

30,90364,158‐
636,963

Allowance for recoverable accounts under production sharing at end of
period100,801

119,248

Add:

Less:

Cost recovery (CAPEX)
Cost recovery (non‐CAPEX)
Other

5

Apr.‐Sep. ‘13

Sales and Investment planfor the year ending March 31, 2014
【Reference】

Forecasts for the year
ending March 31, 2014

Apr.‐Sep. ’13(Actual)

As of Nov. 7, 2013

Crude oil (Mbbl)1

83,74482,507(1,237)

40,578Natural gas (MMcf)2

318,915

324,304

5,389

159,671

Overseas

251,589258,290

6,701

130,276

Japan

67,326(1,804 million m3)

66,014(1,769 million m3)(1,312)(‐35 million m3)

29,395(788 million m3)

2,211

2,881

670

1,462

Development expenditure4

1,003.0

1,010.0

7.0

437.6

Other capital expenditure

37.0

47.0

10.0

17.5

Exploration expenditure

91.0

84.0

(7.0)

29.8

46.5

(4.4)

14.2

(2.8)

Sales Volume

As of May 10, 2013

LPG （Mbbl）3

Change（Billions of yen）

Exploration expenses andProvision for explorations5

Exploration Cost 32.2

Exploration Cost 36.7
Provision for allowance for
exploration 14.2

(Minority Interest Portion)6

50.9

Provision for allowance for
exploration 14.3

17.0

Exploration Cost 16.6
Provision for allowance for
exploration 1.0

17.6
7.5

Note
1 CF for domestic crude oil sales and petroleum products : 1kl=6.29bbl
2 CF for domestic natural gas sales : 1m3=37.32cf
3 CF for domestic LPG sales : 1t=10.5bbl
4 Development expenditure includes investment in Ichthys downstream
5 “Provision for allowance for recoverable accounts under production sharing” + ”Provision for exploration projects”
6 6 Capital increase from minority shareholders, etc.

Net Production* (Apr. 2013 – Sep. 2013)
Oil/Condensate/LPG
1% 1 1%

3

245Mbbl/day

19%

46
167

Total

Japan
Asia/Oceania

26

403MBOE/day

Eurasia11%

5%

Middle East/Africa

68%

19

Americas

6%24Natural Gas
13%

12%

102 110851MMcf/day(159MBOE/day)

41%

167
166
41%

Japan

Asia/Oceania

Asia/Oceania

638

Eurasia
Middle East/Africa

75%

7

*

Americas

Japan

26
7%

Eurasia
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 our group.

Project Summary

Exploration Work Programs(as of the end of September 2013)**

Japan
Onshore Niigata Chuetsu (SS)India
KG‐DWN‐2004/6 Block (1)Offshore Shimane – Yamaguchi (SS)USA
Walker Ridge 95 Block (1)EgyptSouth October Block (1)Indonesia

AngolaOnshore Cabinda
North Block (1)South East Mahakam Block (1)Suriname

Berau Block (1)Block 31 (SS)

Masela Block (1)Offshore Mahakam Block (SS)
Brazil
BM‐ES‐23 (1)Viet Nam

Mozambique

Blocks 05‐1b and 05‐1c (1)Area 2&5 (2)* Number in () is the numberof drilling wells

Uruguay

WA‐35‐L (SS)Area 15 (SS)Exploration
Expenditure(Billions of Yen)

Exploration Well

9Australia

Exploratory
Well(well)

AppraisalWell(well)

Seismic Survey
2D(km)

Seismic Survey
3D
(km2)

Appraisal Well

Mar. ’14 (E)

91.0

17

9

100

10,246

Seismic Survey (SS)Completion or
Under operation

84.0

6

5

100

8,046

Major Assets in Production & Development
Canada Shale gas projects(the Horn River, Cordova and Liard basins)

Sakhalin 1

North Caspian Sea Block(Kashagan Oil Field, etc)

Joslyn Oil Sands Project

ACG Oil Field

Projects in the shallow waters ofthe. U.S. Gulf of Mexico
Minami‐Nagaoka Gas Field

ADMA Block

Lucius Fieldin the U.S. Gulf of Mexico
South Natuna Sea Block B

Copa Macoya/Guarico
Oriental Blocks

Offshore Mahakam Block
Offshore D.R.
Congo Block

Sebuku Block(Ruby Gas Field)
Berau Block (Tangguh Unit)
Abadi LNG Project
WA‐35‐L(Van Gogh Field)

Offshore Angola
Block 14

JPDA03‐12 (Bayu‐Undan Oil & Gas Field)

WA‐35‐L/WA‐55‐L(Coniston Unit)
WA‐43‐L(Ravensworth Field)

In Production

In Development

JPDA06‐105 (Kitan Oil Field)

Offshore North Campos
Frade Block

Prelude FLNG Project
Ichthys LNG ProjectPreparation for Development

10

Production Start‐up Schedule (1/2)
Production Start‐up

Project/Oil & Gas Field

Operator

NCOC
PEARLOIL

370Mbbl/d100MMscf/d

7.56%
15%

ADMA‐OPCO
ApacheAnadarko‐*3
Approx. 80 Mbbl/dApprox. 450 MMscf/d

12.0%
47.499%7.2%

ConocoPhillips*3

Fiscal 2013
(April 2013 ‐ March 2014)

Kashagan Oil Field (Phase1)
Ruby Gas Field (Sebuku Block)Kazakhstan
Indonesia

Fiscal 2014
(April 2014 ‐ March 2015)

Umm LuLu, Nasr Oil Field
Coniston Unit
Lucius Field (Oil)(Gas)
South Belut Gas Field(South Natuna Sea
Block B)

UAE
Australia
U.S.

Lianzi Oil Field
Shale Gas Project (Cordova)
Ichthys LNG Project (LNG)(LPG)(Condensate)
Prelude FLNG Project (LNG)(LPG)(Condensate)
Abadi LNG Project (Stage 1) (LNG)(Condensate)
Joslyn Oil Sands Project (Mining)

AngolaCanadaAustralia

Chevron
Nexen
INPEX

Australia

Shell

Indonesia

INPEX

CanadaKalamkas, Aktote, Kairan and Southwest
Kashagan structures
Shale Gas Project (Liard)
Lucapa, Malange Oil Fields

Kazakhstan
CanadaAngolaAfter April 2015

Discovered/Production
start‐up (TBD)

*1
*2
*3
*4

11

INPEX
Share*1

Peak Production /Production Capacity

Country

Indonesia

35%
9.99%*240%
66.07%TOTAL

Approx. 20Mbbl/dApprox.1,250MMscf/d*4
8.4MMt/yApprox. 1.6MMt/yApprox. 100Mbbl/d3.6MM t/yApprox. 0.4 MM t/yApprox. 36 Mbbl/d2.5MMt/y
8,400bbl/d
200Mbbl/d

NCOC

TBD

7.56%

Nexen
Chevron

TBD
TBD

40%
9.99%*2

INPEX share is a participating interest. In the case of an equity method affiliate, multiplying the participating interest by INPEX controlling share.
INPEX share for the Lianzi Field is one‐half of the mentioned share in this table since it belongs to the unitized area between Angola and R.O. Congo.
Nondisclosure because of confidentiality agreement with project partners
Peak Production combined from both Horn River and Cordova Areas

17.5%

60%
10%

Production Start‐up Schedule (2/2)
Australia / Timor Sea JPDA

PreludeIndonesia

Australia

2022

Abadi

IchthysIndonesia

Australia

2021
Coniston

2020

Australia

Americas

2019

Kitan

JoslynJPDA

CanadaSouth Belut
Indonesia

2018

Ruby
Indonesia

Liard

2017

CanadaSouth MahakamIndonesia

2016
Bawal GasUSA

Umm Lulu

2014

UAE

UAE

Kazakhstan

kairan2012

Nasr

Kashagan

2013

12

CanadaLucius2015

Indonesia

2011

Cordova

Middle East /AfricaKazakhstan

AktoteKalamkas

Kazakhstan

Kazakhstan

Malange

LianziAngolaAngolaLucapaKashagan southwest

Eurasia

AngolaKazakhstan

Production Started/Development Phase(Production plan is settled)

Project Development Plan under being
establishedGas

Oil/Condensate

Natural Gas Business in JapanINPEX CORPORATION–Production* :•Natural gas : approx.3.0million m3/d(110 million cf/d)**LNG(from 2014 - )•Crude oil and condensate : approx. 3,000 bbl/d–Natural Gas Sales•Natural Gas Sales FY 2013/03 : approx. 1,750 million m3**
FY 2014/03(e) : approx. 1,800 million m3**
Domestic gas•Expect more than 2,500 million m3 in the first half of 2020s,
3,000 million m3 in the long‐term–Gas Supply Chain•FID on Toyama Line in May 2011
•Construction of Naoetsu LNG Terminal(Start‐up target:
January, 2014)

LNG(regasified)*sum of domestic crude oil and gas fields : average daily volume (for the six
months ended Sep. 30)**1m3 =41,8605MJ

13

Gas Prices in Japan
Price Comparison per Unit

140

120
*Conversion into unit price per 41.8605MJ (10,000kcal) by*Conversion
into unitFuel
price
per39.10MJ/L,
41.8605MJLNG(10,000kcal)by
Crude
Oil : 38.20MJ/L,
Oil::
Crude Oil(METI: 38.20MJ/L,
Fuel Oil: 39.10MJ/L, LNG :54.50MJ/kg
Statistics)
54.50MJ/kg (METI Statistics)*Refinement cost etc. are not included for crude oil. Delivery*Refinement
etc. arenot
includedfor crude oil. Delivery
cost
etc. are notcost
includedfor
Fuel
Oil. Storage,
cost etc. are notincluded for
Fuel
Oil.
Regasification,
Distribution
costs
etc.
areStorage,
not included forRegasification, Distribution costs etc. are not included for
LNG
LNG

Price[Yen／41.8605MJ]

100

80

60

40

20

99/4

00/4

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

Offshore Mahakam
INPEX CORPORATION
Bontang LNG/LPG Plant

Attaka Unit
Santan Terminal
Attaka Field
Badak Field
Nilam Field
Tambora Field
Paciko Field

Tunu
Field

Handil Field

Sisi Field

Senipah Terminal

Nubi Field
Bekapai Field

Balikpapan

Makassar Strait

Offshore Mahakam

South Mahakam Gas Fields
Gas field
Oil Field
Oil and Gas field＊ on the basis of all fields and average rate of Sep., 201315

– Participating Interest: 50% (Operator: TOTAL)– Production*• Crude Oil and Condensate: Approximately
69,000 bbl/d• LPG: Approximately 9,000bbl/d• Gas: Approximately 1,370 million cf/d
– PSC: Until 2017
– Development activities continue to keep stable gas
supply to Bontang LNG plant• Phased development of the Tunu / Peciko fields• Development of the Sisi‐Nubi fields• Development of the South Mahakam fieldongoing– LNG supply to the Indonesia’s first LNG receiving
terminal (FSRU: Floating Storage andRegasification Unit) in West Java started in April
2012.
– Production at South Mahakam gas field started in
the end of October 2012.
– Negotiation continues on PS contract renewal withIndonesian governmental authorities in cooperation
with TOTAL .

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

Fertilizer Plant
Attaka Oil Field– Participating Interest: 15%(Operator : PEARLOIL (Mubadala))

Tunu Gas Field– PSC: Until 2027

Senipah Terminal
Balikpapan

Peciko Gas Field– POD (Plan of Development) for the Ruby Gas Field
was approved by Indonesian Government in July
2008.

Kalimantan
South Mahakam Gas Fields

Sebuku Block

Sulaewesi– FOA (Farm Out Agreement) with Pearl Energy wasapproved by Indonesian Government in August2010 (INPEX acquired a 15% interest).
– FID (Final Investment Decision) in June 2011

50

0

100km

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

Kalimantan

Sulavesi

West Papua

Gas field– Production commenced in October 2013.

Jawa

Oil Field– Produced gas is mainly supplied to domestic
fertilizer plant in Indonesia.

16

South Natuna Sea Block B
INPEX NATUNA LTD.
AA

Natuna Sea

South Natuna Sea Block

B
Tembang
BuntalBelidaSembllang

Keong

North Belut

Hlu

KerisiSouh Belut

Bawal

Natuna Island

Bintang LautMalongKijing– Signed a gas sales contract for 22 years from2001 with SembCorp (Singapore) and for 20
years from 2002 with Petronas (Malaysia)

B

Hiu

Tembang
Kerisi
BelidaBawal

North Belut
South BelutWest Belut

Keong

BelenakGas field

Semblang

Bintaug LautMalongKijingOil field
Oil & Gas field＊ on the basis of all fields and average rate of Sep., 201317

– Production*:• Crude Oil: Approximately 30,000 bbl/d• LPG : Approximately 11,000 bbl/d• Gas: Approximately 330million cf/d
– PSC: Until 2028

West Belut
Belanak

Buntal– Participating Interest: 35.0%(Operator : ConocoPhillips)– Production at the Bawal gas field started inJuly 2012– Production at the South Belut gas field is
expected to commence in 2Q 2014

Berau (Tangguh LNG Project)
MI BERAU B.V. / MI BERAU JAPAN LTD.
West Papua Province– MI Berau B.V./MI Berau Japan Ltd.* : Joint
venture with Mitsubishi Corporation (INPEX
44%, Mitsubishi 56%) *MI Berau Japan owns approximately(Indonesia)

16.5% share of KG Berau Petroleum Ltd.

Berau Block

Kaimana

Gas field– Participating Interest in the Berau PSC:
• MI Berau : 16.3% Tangguh Unit
• KG Berau Petroleum : 8.56% Tangguh Unit
• Operator : BP
– Production*:• Condensate: Approximately 6,000 bbl/d• Gas: Approximately 1,110 million cf/d
– PSC: Until 2035
– Scheduled Production: 7.6 million tons of LNG
per year– First cargo of Tangguh LNG delivered in July2009

＊ on the basis of all fields and average rate of Sep., 201318

JPDA03‐12 (Bayu‐Undan)
INPEX SAHUL, LTD.
– Participating Interest: 11.378120%(Operator: ConocoPhillips)– Production*:• Condensate: Approximately 37,000
bbl/d• LPG: Approximately 23,000 bbl/dIndonesia

Joint Petroleum
Development Area

Australia

Kitan Field

JPDA03-12

–
–

Gas
Oil

50 km

Bayu Undan Gas
Condensate Field

Darwin––＊ on the basis of all fields and average rate of Sep., 201319

• Gas: Approximately 560 million cf/d
PSC: Until 2022
Sales of condensate and LPG started in
February 2004
Entered into LNG Sales Contract withTEPCO and Tokyo Gas in August 2005
(3 million t/y for 17 years from 2006)
LNG sales started in February 2006

JPDA06‐105 (Kitan Oil Field)
INPEX TIMOR SEA, LTD.
– Participating Interest: 35% (Operator:
Eni)– PSC: Until April 2035 (Kitan Oil Field)– Declaration of commercial discoveryof the Kitan Oil Field in May 2008
– National Petroleum Authority
approved the Final Development Planfor the Kitan Oil Field in April 2010
– Production started in October 2011
– Production*:

Joint Petroleum
Development Area

JPDA06-105
Kitan Field
Bayu Undan
Gas Condensate Field

Gas• Oil: Approximately 12,000bbl/d

Oil

50 km

＊ on the basis of all fields and average rate of Sep., 201320

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
ExmouthWA‐42‐L Block(No Participating
Interest)

Onslow

Australia

050km＊ on the basis of all fields and average rate of Sep., 201321

Van Gogh / Coniston Oil Fields (WA‐35‐L/WA‐55‐L)– Participating Interest: 47.499% (Operator: Apache)– Concession Agreement: Production License was
granted in October 2008
– Van Gogh Oil Field
Production Start : February 2010
Production* : Oil : Approximately 13,000bbl/d– Coniston Oil Field: Production Start: 2Q 2014
(planned), the average rate during the first year is
projected to be approximately 19,600 bbl/d.
Ravensworth Oil Field (WA‐43‐L)– Participating Interest: 28.5% (Operator :BHPBP)– Concession Agreement: Production License was
granted in November 2009
– Tie‐in development to the Production Facilities in
WA‐42‐L, next to WA‐43‐L– Production started in August 2010
– Production*:
Oil: Approximately 10,000bbl/d

Ichthys LNG Project(1/6)– January 13, 2012, Announced FID– Production start target： by the end of 2016

JPDA03‐12/13
JPDA03‐13

WA‐44‐L(Prelude FLNG)
Shell
72.5%
INPEX 17.5%
KOGAS 10.0%

WA‐274‐P
WA‐274‐P
SANTOS30% 30%
SANTOSCHEVRON50%
CHEVRON
INPEX 50%20%
INPEX
20%

WA‐44‐L(Prelude FLNG)
Shell 82.5% AC/P36
INPEX 17.5%
AC/P36INPEX 50%
Murphy 50% WA‐343‐P
INPEX 50%
Murphy 50%
INPEX
60%
WA‐343‐P
TOTAL 40%
INPEX 60%
WA‐341‐P
WA‐341‐P
TOTAL 40%

WA‐410‐P
WA‐410‐P
SANTOS30%
CHEVRON 50%
SANTOSINPEX 30%20%
CHEVRON 50%
INPEX
20%

INPEX
BEACH

26.6064%9.7637%A

INPEX 60%
INPEX
TOTAL
40% 60%
TOTAL
40%

WA‐344‐P
WA‐344‐P

WA‐411‐P

SANTOS 63.6299%
INPEX
26.6064%BEACH
SANTOS 9.7637%
63.6299%

Darwinダーウィン

INPEX 60%
60%
INPEX
TOTAL 40%TOTAL 40%NORTHERN
北部準州
TERRITORY

WA‐494‐P

INPEX 100%

イクシス
WA‐281‐P
ICHTHYSSANTOS
47.83%
WA‐281‐P
CHEVRON 24.83% WA‐50‐L / WA‐51‐L/WA‐285‐P
INPEX
20%
WA‐50‐L / WA‐51‐L/WA‐285‐P
SANTOS
BEACH 47.83%
7.34%
CHEVRON
INPEX
BEACH

A
DarwinCBDダーウィン市街

24.83%
20%
7.34%

Wikham Point
ウィッカム・ポイント
Blaydin Point(Darwin LNG) ブライディン・ポイント(Construction
Site)(建設予定地)WESTERN
西オーストラリア州
AUSTRALIA

ガス田
BROOME
ブルーム

0

100

200km

MiddleArm
ミドルアーム半島
02

4km– Production rate： LNG : 8.4 million t/y(equivalent to approx. 10% of Japan’s current
LNG annual import volume) , LPG : approx. 1.6
million t/y , Condensate : approx. 100,000 barrels
per day(at peak)– Reserves : 40‐year project life. LNG productionof 8.4 Million t/y for approx. 20 years (thengradually decline) . Substantial LPG and
Condensate production. Approx. 1,030 million
BOE* of proved reserves as of Mar. 2013.
– Participating Interest: INPEX 66.07%**, TOTAL
30.0%, Tokyo Gas 1.575%, Osaka Gas 1.200%,
Chubu Electric Power 0.735%,Toho Gas 0.420%*This figure is based on INPEX’s Participating interest of 66.07%.
**Including 2.625% equity interest in the process of transfer to CPC

22

Ichthys LNG Project(2/6)⁻Marketing: LNG SPAs secured for the entire LNG production (8.4 million t/y)⁻Major Government approvals: Environmental approval, Pipeline licenses,
Production Licenses all obtained
⁻CAPEX : US$34.0 billion (100% project basis)⁻Financing the Project: Arrangement for US$ 20 billion of project financing with ECAs and majorcommercial banks were completed in December, 2012.
⁻EPC Works : Major EPC Contracts were awarded.
Upstream : CPF: Samsung Heavy Industries, FPSO: Daewoo Shipbuilding & Marine Engineering, Subsea Production System(SPS)： GE Oil & Gas, Umbilical, Riser and Flowline (URF)： McDermott
Downstream : Onshore LNG Plant : JGC, Chiyoda and KBR, Gas Export, Pipeline(GEP)： Saipem S.p.A, Mitsui Corporation,
Sumitomo Corporation and Metal One Corporation, Dredging in Darwin Harbor: Van Oord, Instrumentation and Control
System: Yokogawa Electric (including upstream facilities)LNG Sales Volume: 8.4 million t/ySchedule:

Kyushu Electric Power0.30 mtpa
Chubu Electric Power0.49 mtpa

Toho Gas
0.28 mtpa
CPC Corporation
1.75 mtpa

Osaka Gas
0.80 mtpa
Kansai ElectricPower0.80 mtpa
TOTAL
0.90 mtpa

23

Tokyo Electric Power
1.05 mtpa

Tokyo Gas
1.05 mtpa
INPEX Corporation
0.90 mtpa
Approximately 70% of the LNG to be delivered toJapanIchthys LNG Project(3/6)
Development Concept

Central Processing Facility LNG, LPG, Condensate
Floating Production,(CPF)
Storage and Offloading
Condensate(FPSO)
Darwin Onshore LNG Plant
Offtake
Tanker

Flexible
Riser
Upstream Downstream

Flowline

Gas Export
Pipeline(GEP)

Subsea Production
System24

Ichthys LNG Project(4/6)
Key Locations of EPC Works
Aberdeen
SPS Engineering

Qindao
LNG plant module fabrication

LeidenURF Engineering

Geoje, Okpo
CPF/FPSO Engineering,
Construction

MonacoFPSO Turret Engineering

Yokohama
Onshore Engineering

HoustonCPF Topside
Engineering

Philippines
LNG plant module fabrication
Thailand
LNG plant module fabrication
Malaysia
FPSO Topside Engineering
Singapore
Instrumentation and Control
System Engineering,
FPSO Turret Manufacturing
Indonesia
25URF facility fabrication

DarwinLNG Plant Construction, Dredging in
Darwin Harbor, Accommodation Village
Construction
Perth
Project Management , GEPEngineering,
URF Engineering

Underline: Offshore, Italic: Onshore
Underline & Italic: Offshore & OnshoreIchthys LNG Project(5/6)
Piling at onshore
LNG Plant site

Accommodation Village

Fabrication of module foronshore LNG plant in China

26

Ichthys LNG Project (6/6)
Characteristics / Strengths of the Project– Wet gas with rich Condensate and LPG– Good coordination and relationship with TOTAL– Sufficient period of FEED prior to FID→ Thorough review on engineering works to＋minimize scope change→ More accurate cost estimation
Major/reliable EPC contractors involved–– High degree of lump‐sum for EPC contracts(approx. 75% of the price)– LNG SPAs with major/reliable buyers– Large‐scale project finance secured– Insurance arrangements for project facilities
during the construction period

27• Readiness for cost
overrun risk tosecure stableeconomics• Readiness for risk
management tocontrol projectschedule• Fully prepared forsteady progress

Abadi LNG Project SURF (subsea production facilities) FEED
commenced in November 2012. FLNG FEED
commenced in January 2013.
Tanimbar Islands AMDAL(Environmental & Social Impact
SaumlakiAssessment Process) ongoing

INDONESIAEAST TIMOR

Masela Block

Arafura Sea• Plans to complete the AMDAL report by the endof 2013 and to obtain final approval from the
Ministry of Environment.

Abadi gas field Strategic alliance with Shell

Timor Sea Joint Petroleum
Development Area

AUSTRALIA

Darwin0100• Shell provides technical services and assigns
secondees PS Contract requires to transfer a 10%
participating interest to an Indonesianparticipant to be designated by the
200km
Indonesian Government.
 PSC: Until 2028
 Further approach for future subsequentdevelopment utilizing the gas reserves• With FEED started, part of contingent resources
upgraded and booked as probable reserves (FYMarch 2013)• Conducting to drill 3 delineation wells and 1
exploratory well from June 201328

Prelude FLNG Project
INPEX Oil & Gas Australia Proprietary Limited–Participating Interest: 17.5% (Operator:
Shell)–Reserves : approximately 3 trillion cubicfeet of gas (Prelude and Concerto gas fields)–Production : 3.6 million t/y of LNG, alongwith 0.4 million t/y of LPG and approx.
36,000 bbl/d of condensate at peak
–FID in May 2011
–Targeting its production start‐up around 10
years from when the Prelude gas field was
first discovered in early 2007

FLNG (image)29

ACG
INPEX Southwest Caspian Sea, Ltd.
50km
The Caspian sea

Azerbaijan
Baku

ＡＣＧ

Deepwater portionof Gunashli
ChiragKazakhstan

RussiaAzeri
The Aral Sea
Uzbekistan
The Caspian Sea

Georgia

Armenia

Azerbaijan
Turkmenistan

500km

Iran

Oil field＊ on the basis of all fields and average rate of Sep., 201330

– Participating Interest: 10.9644%(Operator: BP)– Production *: Approximately 631,000
bbl/d– PSC: Until 2024
– Phase 1 : Starting oil production in theCentral Azeri area in February 2005
– Phase 2 : Starting oil production in theWest Azeri area in December 2005 andin the East Azeri area in October 2006
– Phase 3 : Starting oil production in the
Deepwater portion of the Gunashli area
in April 2008
– Additional Development:
Governmental Approval for Chirag Oil
Project (COP) in March 2010 (Startingoil production is scheduled in late2013)

Kashagan, etc.
INPEX North Caspian Sea, Ltd.
– Participating Interest: 7.56% (Operator: NCOC
(North Caspian Operating Company))

Kairan Structure
Kairan Structure
Kashagan oil fieldKashagan oil field– PSC: Kashagan – Until the end of 2021*– Kalamkas, Aktote, Kairan and Southwest
Kashagan structures are under evaluation.

CaspianSea
Sea
CaspianKashagan Southwest Structure
Kashagan Southwest Strucuture– Kashagan (Experimental Program)

Aktote Structure
Aktote Structure First Oil: September, 2013

RussiaRussiaKazakhstan
Kazakhstan
China
China

TurkeyTurkeyIran
Iran

Kalamkas Structure
Kalamkas Structure
Gas field
Gas field
Oil field
Oil field

India
India

 Oil Production : Approximately
10 thousand bbl/d**
 Oil Peak Target: 370 thousand bbl/d
 Further Plan: 450 thousand bbl/d (Target)* We have the options to extend the contract period by 10 years
twice in accordance with the current PSC

31** on the basis of all fields and average rate of Sep., 2013

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

Black Sea

TbilisiGEORGIABTC Pipeline

ARMENIA

CaspianSea

Baku

AZERBAIJAN

TURKEY

CeyhanCYPRUS

IRAN

SYRIA
IRAQ

Mediterranean
Sea– Participating Interest: 2.5%
(Operator : BP)– Obtained stock of the operating company(BTC Co.) through INPEX BTC Pipeline,
Ltd. in October 2002
– Commenced crude oil export in June 2006
from Ceyhan terminal– Complete commissioning work 1.2 million
bbl/d capacity expansion in March 2009
– Cumulative export volume reached 1,000
million bbls on September 13, 2010

32

ADMA
Japan Oil Development Co., Ltd. (JODCO)
Production Oil Field
Underwater pipeline
Undeveloped Oil
FieldsUmm Shaif Oil Field

Nasr Oil Field

Das Island

Lower/Upper Zakum
Oil Field

Satah Oil Field
Zirku Island

Umm Al‐Dalkh Oil Field

Umm Lulu Oil Field
Abu Dhabi

33– Umm Shaif / Lower Zakum• Participating Interest: 12.0% (Operator :ADMA‐OPCO*)– Upper Zakum / Umm Al‐Dalkh / Satah• Participating Interest:
Upper Zakum / Umm Al‐Dalkh: 12.0%
Satah: 40.0% (Operator : ZADCO*)*Operating company established by ADNOC and other companies
including JODCO. JODCO has a 12% interest in each company.

– Continuous development to keep andincrease the production level Umm Lulu /Nasr under development
aiming for early production
 Implementing a redevelopment planusing artificial islands for Upper Zakum

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

Copa Macoya / Guarico Oriental Blocks– INPEX’s Share• Gas JV : 70%
Oil JV : 30%– Joint Venture Agreement: 2006‐2026– Production*:• Gas: Approximately 57 million cf/d
• Crude oil: Approximately 1,000 bbl/d

Copa Macoya / Guarico Oriental Blocks

A T R A N T I C
O C E A N

CaracasVenezuela

BRAZIL＊ on the basis of all fields and average rate of Sep., 201334

Brazil Projects
Frade Japão Petróleo Limitada (FJPL) etc
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 37.5% shares of FJPL through a subsidiary)
Atlantic Ocean –BrazilFrade Block
Campos

Production**:• Crude oil: Approximately 20,000 bbl/d– Concession Agreement: Until 2025

Macaé
Rio de Janeiro

BM‐ES‐23– Participating Interest: 15%– Under Exploration
Oil and Gas field0＊＊ on the basis of all fields and average rate of Sep., 2013

35

100km

Canada Shale Gas Project
INPEX Gas British Columbia Ltd.

‐ Participating Interest: 40%*(Operator : Nexen)* INPEX Gas British Columbia Ltd. (INPEX 45.09%, JOGMEC
44.89%, Canadian Subsidiary of JGC Corporation 10.02%).

‐ Production**: Gas: Approximately 96million cf/d
‐ Concession Agreement2
 Horn River : 366km

Zakum Central Complex



Cordova : 333km2

Liard : 517km2‐ 1,250 million cf/d (approximately 200 thousandboe/d) at Horn River and Cordova areas as fullscale production expected

Central Azeri Platform‐ Horn River area: Production Start in 2010
‐ Cordova area: Production Start in 2019 (planned)

Hydraulic Fracturing site in the Horn River Area

36

Joslyn Oil Sands Project
INPEX Canada, Ltd.
– Participating Interest:
7405070799

Fort McMurray

CanadaEdmonton
Calgary

7280060T24
7404110452

Joslyn Oil Sands Lease(217km²)

Alberta– Concession Agreement (Lease)• 7280060T24 : Indefinite• 7404110452 : 15 year primary lease from
November 2004*• 7405070799 : 15 year primary lease from July
2005*
*Can be extended

Athabasca River– Oil Sands Upstream Project:

Fort McMurray0• Upstream project: 10% (operator: TOTAL)

20km

Joslyn Oil Sands Lease Location• Mining project will commence operations in late
2010s and will reach a production rate of 100,000
barrels of bitumen per day, followed byadditional 100,000 barrels of bitumen per day as
the second phase– Upgrader Project:• Under consideration

37

Gulf of Mexico (USA) Projects
Teikoku Oil (North America) Co., Ltd. / INPEX Gulf of Mexico Co., Ltd.
Shallow Water Projects(Teikoku Oil (North America) Co., Ltd. )– Concession Agreement– Participating Interest:
Ship Shoal 72: 25%, West Cameron 401/402: 25%,
Main Pass 118: 16.67%, SL 20183: 25%– Production volume*•Gas: Approximately 8 million cf/d
•Crude oil: Approximately 1,000 bbl/dSL20183
Louisiana

Texas

MexicoMain
Main Pass
118

West Cameron
401/4020500

1,000km

Ship Shoal
72
CUBA

WR95/96/139/140
Keathley Canyon Block874/875/918/919(Lucius Field)

Deep Water Project(INPEX Gulf of Mexico Co., Ltd.)– Concession Agreement– Participating Interest:
Walker Ridge 95/96/139/140 : 15%
Lucius Field(Teikoku Oil(North America) Co., Ltd.)－ Concession Agreement－ Participating Interest: 7.2%(Operator : Anadarko)－ FID : December 2011
－ Production Start : latter half of 2014 (planned)＊ Ship Shoal 72, West Cameron 401/402, Main Pass 118, SL 20183 on the basis of all fields and average rate of Sep., 201338

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
Lukami– Production Commencement: 1975

Moko

– Production*: Approximately 14,000
bbl/dTshialaMuandaGCO

BananaAtlantic Ocean

Soyo

ANGOLAOil field0＊ on the basis of all fields and average rate of Sep., 2013

39

5

10km

Block 14, Offshore Angola
INPEX Angola Block 14 Ltd.
Rep. ofCongo

Block 14
D.R. Congo– Participating Interest: 9.99%(Operator: Chevron)– Production* : Approximately 138,000 bbl/d– PSC: Until 2035
– Plans to further expand exploration, development
and production activities

Republic ofAngolaAtlantic Ocean

100km＊ on the basis of all fields and average rate of Sep., 201340

Sakhalin I
Sakhalin Oil and Gas Development Co.
0

5

10km

Gas field
Oil Field

OdoptuStructure

Sakhalin
IslandVal

ChayvoStructure
Arkutun‐Dagi
Structure– Sakhalin Oil and Gas Development Co. (SODECO):INPEX owns approximately 6.08% of the total
share– SODECO’s Participating Interest: 30.0%– Production*:• Crude Oil : Approximately 140,000 bbl/d• Gas: Approximately 204 million cf/d **– Operator: ExxonMobil– PSC: In December 2001 the project proceeded to thedevelopment phase for 20 years– Commenced production from Chayvo Structure in
October 2005; commenced crude oil export in
October 2006
– Commenced production from Odoptu Structure in
September 2010
– Commenced natural gas supply to Russian
domestic market, and natural gas supply to
Chinese and other markets considered＊ on the basis of all fields and average rate of Sep., 2013**sales volume
41

Block 10, Iraq
INPEX South Iraq, Ltd.
TurkeyTURKEYIRAQ

IRAN– Participating Interest: 40%(Operator: Lukoil)

Erbil– Signed a Service Contract for theonshore Block 10 jointly with asubsidiary of LUKOIL in November
2012

SAUDI ARABIA

IRAN
BagdadIRAQ– Plans to carry out seismic surveys andto drill exploratory well(s)Garraf Oil Field
West Quma
Oil Field

Block 10Basra

SAUDI ARABIA

Rumaila Oil Field
0

100km

42

Key Investments and Contracts I*
Company

Field / Project NameCountry

Minami‐Nagaoka, etc. **Japan•INPEX CORPORATION

MahakamContract Type Ownership StageJapan
ConcessionｰProducingIndonesia

PSｰProducing•INPEX South Makassar

Sebuku Block(Ruby Gas Field) Indonesia

PS

100%

Producing•INPEX Natuna

South Natuna Block ‘B‘Indonesia

PS

100%

Producing•MI Berau B.V.

Berau(Tangguh LNG Project) Indonesia

PS

44%

Producing•INPEX Masela

Masela(Abadi)**Indonesia

PS

51.9%

Preparation for Development•INPEX Sahul

Bayu‐Undan

JPDA

PS

100%

Producing•INPEX Browse

WA‐285‐P **Australia

Concession

100%

Exploration•INPEX Ichthys Pty Ltd.

WA‐50‐L(Ichthys) **Australia

Concession

100%

Development•Ichthys LNG Pty Ltd.

Ichthys Downstream **Australia‐

66.07%Development•INPEX Oil & Gas Australia Pty Ltd.

Prelude FLNG Project

Australia

Concession

100%

Development•INPEX Timor Sea

JPDA 06‐105(Kitan)

JPDA

PS

100%

Producing•INPEX Alpha

Van Gogh/Coniston

Australia

Concession

100%

Producing/Development•INPEX Alpha

Ravensworth

Australia

Concession

100%

Producing•INPEX CORPORATION

Asia/Oceania

Note：* As of the end of October 2013** Operator project*** INPEXʹs participating interest 66.07% represents the figure before the completion of condition precedent of the participating interest transfer contracts with CPC
43 whose interest will be a 2.625% .

Key Investments and Contracts II*
Company

Field / Project NameCountry Contract Type Ownership Stage

Eurasia (Europe – NIS)•INPEX Southwest Caspian Sea

ACG

Azerbaijan

PS

51%

Producing•INPEX North Caspian Sea

Kashagan

Kazakhstan

PS

45%

Producing•JODCOADMA(Upper Zakum, etc.)

UAE

Concession

100%

Producing•INPEX South Iraq

Block 10

Iraq

Service100%

Exploration•Teikoku Oil (D.R. Congo)

Offshore D.R.Congo

D.R.Congo

Concession

100%

Producing•INPEX Angola Block 14

Block 14, Offshore Angola

AngolaPS

100%

Producing/Development

Joslyn Oilsands

CanadaConcession

100%

Preparation for Development•INPEX Gas British Columbia Canada Shale Gas project

CanadaConcession 45.09%

Producing/Evaluation•Teikoku Oil & Gas Venezuela

Venezuela

The Middle East

AfricaAmericas•INPEX Canada

Copa Macoya** / Guarico Oriental•Teikoku Oil (North America) Ship Shoal 72etc./Lucius•Frade Japão Petróleo Limitada

44

Frade

JV

100%

ProducingUSA

Concession

100%

Producing/Development

BrazilConcession

37.5%***

ProducingNote：* As of the end of April 2013** Operator project*** Frade Japão Petróleo Limitada is subsidiary of INPEX Offshore North Campos (INPEX’s equity method affiliate). 37.5% of ownership means indirect investment
from INPEX through INPEX Offshore North Campos.

OthersValuation Indices

EV/Proved Reserves*

PBR**

25.0

2.0

20.0

1.5

15.0
5.0
0.0
US$

1.0

22.3

10.0

15.5
5.2
INPEX

Average of
Independents

Average of Oil
Majors

0.5

1.6

1.5

Average of
Independents

Average of Oil
Majors

0.6

0.0
x

INPEX

•

**

EV (Enterprise Value) / Proved Reserves= (Total market value + Total
debt ‐ Cash and cash equivalent + Minority interest) / Proved Reserves.
Total market value as of 30/09/2013, Financial data: INPEX as of
30/09/2013, Independents and Oil Majors as of 30/06/2013 and Proved
Reserves: INPEX as of 31/03/2013, Independents and Oil Majors as of
31/12/2012.
PBR = Stock price / Net asset per share. Total market value as of
30/09/2013. Financial data: INPEX as of 30/09/2013, Independents andOil Majors as of 30/06/2013. Sources based on public data.

46

Medium‐ to Long‐Term Vision
Three Growth Targets and Key Initiatives for the First Five Years
1. Continuous Enhancement of E&P Activities→Achieve a net production volume of 1 million boed by the early 2020s

2. Strengthening 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
Efficient Organizational Structure
2. Investment for Growth and Return for Shareholders
3. Responsible Management as a Global Company
47

Investment Plan and Funding Sources
Approximately 3.5 trillion yen
For Ichthys, Abadi and other E&P projects etc.
5 years (from Fiscal 2013 to Fiscal 2017)

Own Funds

CashFlowApproximately 1.5
trillion yen of cash
available on hands (As of
September 30, 2013)

Operating cash flow
(252.3billion yen in
the fiscal year ended2013)Cash and other liquid
investments on hand

48

*
**

Bank Loans
Sizeable lending fromJBIC* together withcommercial banks
Guaranteed by
JOGMEC** for a certain
portion of loans fromcommercial banks
Project finance

JBIC : Japan Bank for International Cooperation
JOGMEC : Japan Oil, Gas and Metals National Corporation

Core 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,
which are 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 less49

Production Sharing Contracts

Cost Recovery Portion

1. Cost Recovery Portion Non‐capital expenditures incurred for
production and recovered during thecurrent period
 Scheduled depreciation of the capital
expenditures for the current period andrecovered during 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
50

Accounting on Production Sharing Contract
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

51

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 Agreement
Cash Out

Assets on Balance Sheet

Income Statement

All exploration costs are
expensed as incurred
Exploration Expenditures

Development Expenditures

Production Costs(Operating expenses)

Acquisition Costs

Exploration expenses

Tangible Fixed Assets

All production costs are
expensed as incurred

Mining Rights

Cost of sales(Depreciation and amortization)

Cost of sales(Operating expenses)

Cost of sales(Depreciation and amortization)

52

Taxation Summary in Australia※The content may be changed by tax revisions
Sales
Operating expense⇒(Oil/Gas sales price)×(Sales volume)

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

・・・・・・・・・②

PRRT(Petroleum Resource Rent Tax)=(Upstream Revenue－Upstream Capex & Opex－ Expl. Cost－Abandonment Cost－ undeductedcarried forward PRRT expenditure)×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 same group of entities.

Corporate Tax(In Australia)

・Undeducted PRRT Expenditure: non‐utilised PRRT deductible expenditure can be carriedforward to the following year(s), which is 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 Licenceapplication is made.
*LTBR = Long Term Bond Rate
*GDP Factor = GDP Deflator of Australia

Corporate Tax＝ (①－②－③－Interest paid)×30％
53

Crude Oil Prices
130

Brent

WTI

Dubai

120
110
100
90
80
70
60
(US$/bbl)

Brent
WTI
Dubai

Apr.

May

Jun.

Jul.

2012

Aug.

Sep.

Oct.

Nov.

Dec.

Jan.

Feb.

Mar.

Apr.

May

Jun.

Jul.

Aug.

Apr.‐Sep.
2012
Average109.1992.85
106.33Apr. 201２‐Mar. 2013
Average
Apr.
May
110.28 103.43 103.28
92.06
92.07
94.80
107.09 101.68 100.33

2013
Jun.
103.3495.80
100.32

Jul.
Aug.
107.43 110.45
104.70 106.54
103.52 107.11

Sep.
111.25106.24108.28Apr.‐Sep.
2013
Average106.53100.02103.5454

Stock split and reduction in investment unit
 Conducted to split an common stock in the ratio of 1:400 effective
on October 1, 2013, and to adopt a share unit system with 100
shares defined as a single investment unit.
 As a result of these initiatives, the investment unit amount of theCompany’s shares was one quarter of what it had been before thestock split and adoption of the share unit system, making it easierfor individual investors to trade shares of the Company’s stock.

55

Sep.

2013