INPEX CORPORATION Annual Report 2004
INPEX CORPORATION
Annual Report 2004

Printed in Japan on recycled paper.

Year ended March 31, 2004

2004

Profile
We are the leading upstream oil and gas company in Japan engaged for almost the past four decades in the exploration,
development and production of crude oil and natural gas outside Japan. Based on production and reserve amounts, weare the largest upstream oil and gas company in Japan. As of March 31, 2004, our total net proved reserves were approximately 977 MMboe and for the fiscal year ended March 31, 2004, our net production was 196 Mboe per day. We conduct
a substantial portion of our exploration, development and production activities through joint ventures with international oil
and gas companies. In May 2004, we increased our net proved reserves and production by acquiring JODCO, which holds
a working interest in the Abu Dhabi Marine concession area in the United Arab Emirates. On a combined basis, as of March
31, 2004, our total net proved reserves were 1,634 MMboe and for the fiscal year ended March 31, 2004, our net production
was 309 Mboe per day.

Contents
Financial Highlights ................................................................ 1

FORWARD-LOOKING STATEMENTS:

Summary Reserve and Operating Data ................................. 2

This annual report includes forward-looking information that reflects theCompany’s plans and expectations. Such forward-looking information isbased on the current assumptions and beliefs of the Company in light of
the information currently available to it, and involves known and unknown
risks, uncertainties, and other factors. Such risks, uncertainties and otherfactors may cause the Company’s actual results, performance, achievements or financial position to be materially different from any future results,
performance, achievements or financial position expressed or implied bysuch forward-looking information. Such risks and uncertainties include,
without limitations, fluctuations in the following:

A Message from the President .............................................. 3
The Ambition to Grow ........................................................... 4
Global Business Activities ...................................................... 10
Corporate Governance .......................................................... 26
Financial Section ................................................................... 29
Reserves and Production ...................................................... 74
Subsidiaries and Affiliates ...................................................... 79
Other Investments ................................................................. 81
Corporate Data ..................................................................... 82– the price of and demand for crude oil and natural gas;
– exchange rates; and– the costs associated with exploration, development, production andother related expenses.
The Company undertakes no obligation to publicly update or revise any
information in this annual report (including forward-looking information).

Financial Highlights
INPEX CORPORATION and Subsidiaries
For the years ended March 31, 2002, 2003 and 2004

Years ended March 31,

Net sales
Operating income
Net income
Cash flows from operating activities
Total assets (at period end)
Long-term debt (at period end)
Shareholders’ equity (at period end)

(1)

Net income per share
Cash dividends per share(1)Millions of yen

Thousands of
U.S. dollars(2)

2002

2003

2004

2004

¥184,204
97,04927,606
51,827
287,649
31,024
230,825¥201,533
97,27027,912
51,282
338,747
46,865
253,570¥218,831
93,87634,782
44,464525,298
169,307
278,114$2,071,675
888,725
329,282
420,941
4,973,000
1,602,831
2,632,907

Yen

U.S. dollars(2)¥58,838.76
10,000$557.03
94.67¥46,852.92
10,000¥47,178.51
10,000Notes: (1) We made a three-for-one stock split of our common stock effective May 18, 2004. The figures are the amounts before the stock split.
(2) The translations of yen amounts into U.S. dollar amounts have been made at the rate of ¥105.63=US$1.00, the approximate exchange rate on March
31, 2004.

Net sales

Net income(Millions of yen)

(Millions of yen)

Total assets(Millions of yen)

40,000250,000

600,000
500,000

200,000

30,000400,000

150,000
20,000300,000

100,000
200,000
10,00050,000100,000

0

0

’02

’03

’04

0

’02

’03

’04

’02

’03

’04

1

Summary Reserve and Operating Data
INPEX CORPORATION and Subsidiaries
For the years ended March 31, 2002, 2003 and 2004

The following table sets forth the operating and reserve data of the INPEX Group (including our subsidiaries and equity method
affiliates) for the years ended March 31, 2002, 2003 and 2004. We acquired Japan Oil Development Co., Ltd. (JODCO) in May 2004.
The column ‘Combined INPEX and JODCO’ in this table represents the information assuming that JODCO became a fully-owned
subsidiary of INPEX on April 1, 2003.

Combined INPEX &JODCO(9)Year ended March 31,

2002

2003

2004

2004

199.9
3,555.2
792

166.4
3,367.4
728

359.5
3,703.5977

1,016.3
3,703.5
1,634

61.0
652,109.6
169.7

52.0
704,630.1
169.5

59.8
814,547.9
195.5

173.2
814,547.9
309.0

3.73
0.63

4.40
0.73

4.76
0.67

1,777
12,38338,151
52,311
12.8

7,893
18,03067,161
93,08411.8

167,792
25,296
92,348285,43613.7

167,792
25,431
99,031
292,25414.5

498,225 (7)615,827170

670,073436 (5)12.1

4.4 (5)(6)(1)

Net proved reserves (end of period) :Oil (MMbbls)
Gas (Bcf)
Total (MMboe)
Net production(1):Oil (Mbbls/day)Gas (Mcf/day)Total (Mboe/day)Average expenses per boe produced (US$)(2)Production(1)(3)
General and Administrative
Costs incurred (millions of yen):
Acquisition
Exploration
Development
Total
Reserves to production ratio
Standardized measure of discounted future
net cash flows (millions of yen)(1)Reserve replacement ratio (3-year average as %)Finding and development cost per boe(3-year average in US$)(2)(4)
Net probable reserves (end of period)(1)
Oil (MMbbls)
Gas (Bcf)
Total (MMboe)

903.7
3,834.0
1,542.7

5.07 (8)0.63

1,676.4
3,834.0
2,315.4

Notes: (1) See “Reserves and Production”(2) Converted into U.S. dollars using the average exchange rate for the respective fiscal year. ¥125.64, ¥121.10 and ¥112.94=US$1.00 were therespective exchange rates for the years ended March 31, 2002, 2003 and 2004.
(3) Operating expenses plus royalties due others.
(4) The sum of total costs incurred, including ¥37,297 million which is our proportional interest in the costs incurred by our equity method affiliates, for
exploration and development of oil and gas fields and total costs incurred for acquisitions of proved and probable reserves for the years ended
March 31, 2002, 2003 and 2004 divided by the sum of proved reserve extensions, acquisitions and revisions for the years ended March 31, 2002,
2003 and 2004.
(5) When calculating these figures, (i) for the years ended March 31, 2002 and 2003 and as of March 31, 2002 and 2003, we took into account only ourrelevant amounts and (ii) for the year ended March 31, 2004 and as of March 31, 2004, we also took into account JODCO’s relevant amounts as if
it had been our consolidated subsidiary during the entire period.
(6)Includes costs relating to the acquisition of JODCO in the amount of approximately ¥51 billion and the increase in reserves from acquisitionof JODCO.
(7) Converted into Japanese yen using the exchange rate of ¥120.20=US$1.00 which was the exchange rate as of March 31, 2003.
(8) Three-year average for the years ended March 31, 2002, 2003 and 2004 on a combined basis.
(9) Based on sales, expense or cost information for the immediately preceding year ended December 31.

2

A Message from the President
companies, we have discovered crude oil in the Kashagan
structure in the Caspian Sea, Kazakhstan. This structure is considered to have the great potential to be one of the leading supergiant oil fields in the world. We are also participating in the BTC(Baku-Tbilisi-Ceyhan) Oil Pipeline Project, which will serve as themain link in securing a shipping route for the crude oil to be produced in this region. Furthermore, INPEX is actively working toincrease its assets throughout the Caspian Sea, acquiring interests in the ACG (Azeri, Chirag and Gunashli) oil fields in Azerbaijan,
which is greatly expanding the scale of production there. In
February 2004, we entered into a service contract as an operator
with a 75% working interest for the integrated appraisal anddevelopment operations of the giant Azadegan Oil Field in theIslamic Republic of Iran. Then in May 2004, INPEX acquired all
The mission of INPEX CORPORATION is to secure a stable andthe shares in Japan Oil Development Co., Ltd., which holds a par-efficient supply of oil and natural gas for Japan, a nation poor inticipating interest and is involved in the development of large oil

energy resources. INPEX was established in 1966 as a pioneer-fields offshore Abu Dhabi, the United Arab Emirates. These steps

ing Japanese company to promote the development of oilhave surely resulted in a larger and more balanced asset portfolio.

resources in an international context. Over the course of our his-

In September 2001, we changed our corporate name fromtory, we have overcome many difficulties, and since 1970 we haveIndonesia Petroleum, Ltd. to “INPEX CORPORATION” to morediscovered a number of large oil and gas fields in Indonesia. Thanks

precisely reflect our corporate activity pursuing diversified busi-

to the solid financial foundation secured through those discover-ness opportunities in promising regions around the world.

ies, we have been diversifying the geographical scope of ourWe also announced in June 2001 that we would expand ouractivities in the midst of major shifts in the business environment

activities to any promising location throughout the world, abroad

surrounding oil—the two oil crises of the 1970s, the first Gulf War,or in Japan. In addition, we extended the scope of our businessand the collapse of the Soviet Union. As a result, we have steadily

to areas related to the development of oil and gas, such as elec-

and actively engaged in exploration and development in many

tricity and heat supply and sea water desalination.

promising regions of the world: Indonesia and Australia, as our

As projected by the Agency for Natural Resources andcore areas, as well as the Caspian Sea, the Middle East andEnergy in its Outlook for Domestic and World Energy Demand/

South America.

Supply, we believe oil and gas will continue to serve as theWith respect to environmental issues, INPEX has been focus-

dominant energy sources in the 21st century. It is also fore-

ing more of its efforts on the development of natural gas, primarily

casted that the need to secure a stable supply, especially tobecause natural gas is increasingly recognized as a cleaner energy

Asia, will become more acute on account of this area’s

resource both at home and abroad. Illustrating this approach isremarkable rise in demand, and accordingly, its rapid increase

the fact that we are now the largest supplier of natural gas to thein dependency on Middle East sources.

Bontang LNG Plant in Indonesia, one of the largest facilities of its

On November 17, 2004, INPEX listed on the First Section ofkind in the world. In that capacity, we are responsible for more

the Tokyo Stock Exchange. As a designated national flag com-than 25% of all the LNG exported to Japan from Indonesia, apany with advantageous access to desirable projects throughmajor supplier of LNG to Japan. We are also involved in natural

diplomacy of energy resources by the Japanese Government,

gas exports via pipeline from the West Natuna Sea in Indonesia to

INPEX is working to ensure the stable and efficient supply of energy

Singapore and Malaysia, and we are participating in two LNG

to Japan. Our overarching goal is to maximize corporate value by

projects: Bayu-Undan, located in the Timor Sea Joint Petroleum

conducting our operations in an efficient and highly transparent

Development Area, and Tangguh in Indonesia. In addition to thesemanner based on a long-range business strategy.

gas exports, we supply natural gas to the domestic markets ofIndonesia and Australia.
As an operator with a 100% working interest, INPEX has madepromising discoveries of natural gas and condensate fields inIndonesia and Australia. In partnership with prominent western oil

Kunihiko Matsuo
President

3

The Ambition to Grow
Upside Potential through Probable Reserves*(MMboe)Reserve Life**(RP Ratio)
3,949

4,000
2,315

2,315

3,000

2,000

35.0x
1,634
619

1,000

1,015

619

37.9%

1,015

619
1,015

14.5x

62.1%

0
ProvedProvedProvedDeveloped Undeveloped Reserves
Reserves
Reserves

Probable
Reserves

Proved+Probable

Notes:* Reserve amount includes INPEX and JODCO assuming that JODCO became a fully owned subsidiary of
INPEX at the beginning of FY2004. Amounts attributable to the equity affiliates are included.
** Reserve Life = Proved (& Probable) Reserves as of end of March 2004/Production in FY2003 (RP Ratio:
Reserve Production Ratio). Production amount in FY2003 includes JODCO’s production.

[ Our Strengths ]Large proved reserve base with interests in both legacy fields and significant development projects.
Our extensive and geographically diverse proved reserves support our stable and growing production. Based on independent
evaluation of proved reserves carried out in accordance with SEC regulations by DeGolyer and MacNaughton, independent petroleum engineering consultants, as of March 31, 2004, our proved reserves after giving effect to our acquisition of JODCO were 1,634
MMboe, 38% of which were proved undeveloped reserves. In addition, as of March 31, 2004, we and JODCO had a combined net
probable reserves of approximately 2,315 MMboe, based on DeGolyer and MacNaughton estimates.
Our reserves consist of interests in a mix of mature legacy fields in the Mahakam basin in Indonesia and the Abu Dhabi Marine
concession area and other acquisitions, such as our interest in the ACG oil fields in the South Caspian Sea. In addition, we are
involved in a number of key global oil and gas development projects, including the North Caspian Sea Project in Kazakhstan, theTangguh LNG project in Indonesia and the Azadegan oil field in Iran. Our reserves are, in many cases, jointly developed andproduced with leading global oil and gas companies including the “super major” and “major” oil and gas companies, as well asstate-owned oil and gas companies.
After giving effect to our acquisition of JODCO, based on our net proved reserves as of March 31, 2004 and combined production amounts for the period from April 1, 2003 to March 31, 2004, we had a reserve-to-production ratio of approximately 14.5 years.
Based on our net proved plus probable reserves as of March 31, 2004, that ratio would increase to 35.0 years. The reserve amounts
and the production amounts used to calculate these ratios take into account the interests held by INPEX’s and JODCO’s equity
method affiliates.

High growth potential in medium-term production through development of proved undeveloped and probable reserves.
We believe that several of our current development projects will result in increased production over the medium term through utilizationof our net proved undeveloped and probable reserves, including:4Historical Proved Reserves* by ProductHistorical Production* by Product(MMboe)(MMboe/d)

2,000

400
(for reference)
617

1,500

1,000
617
592

1,017

(for reference)

300

136

200

136
173

109

117

61

52

60

FY2002

FY2003

FY2004

561

500

100
360
200

167

FY2002

FY2003

0

0

INPEX

Oil/Condensate/LPG

FY2004

FY2004
INPEX after
Acquisition**

Natural Gas

Notes:* Amounts attributable to the equity affiliates are included.
** The sum of INPEX and JODCO assuming that JODCO became fully owned
subsidiary of INPEX at the beginning of FY2004.

INPEX

Oil/Condensate/LPG

FY2004
INPEX after
Acquisition**

Natural Gas

Notes:* Amounts attributable to the equity affiliates are included.
** The sum of INPEX and JODCO assuming that JODCO became fully owned
subsidiary of INPEX at the beginning of FY2004.

• Phase one of the development of ACG oil fields, which is expected to enter full production during 2005 with the start-up of therelated Baku-Tbilisi-Ceyhan crude oil pipeline. Work on phase two, which is expected to significantly expand production in 2006,
has already begun;• Development of the Kashagan oil field in the North Caspian Sea Project, which is scheduled to commence production in 2008;• Development of the Belanak oil and gas field in South Natuna Sea Block B, Indonesia, which commenced oil production in December
2004 with subsequent gas and LPG development plans expected in 2006 and 2008;• Development of the Berau-Bintuni Bay region of Papua, Indonesia, which is scheduled to commence production of natural gas to beprocessed at the Tangguh LNG plant in 2008; and• Stage one of the development of the Azadegan oil field in Iran where commencement of oil production is expected by 2008.

Strategic participation in gas projects that benefit from growing LNG demand in the Asia-Pacific region.
We believe that we are strategically positioned to be a major supplier of natural gas to help meet the increasing demand for LNG in the
Asia-Pacific region, including Japan, South Korea, Taiwan, China and the west coast of the United States. LNG is becoming an
increasingly important energy source for countries in this region because, compared with other energy alternatives, LNG is a cleaner
source of primary energy. Our natural gas projects located in the Asia-Pacific region, include:• Working interests in fields in the Mahakam basin that supply natural gas to the Bontang LNG plant in East Kalimantan, Indonesia,
which is one of the largest LNG plants in the world in terms of annual LNG production capacity. Our partners and we have been
investing to expand both the natural gas production in Mahakam and the surrounding fields and the processing capacity of theBontang LNG plant in order to capitalize on the increasing demand for LNG in the Asia-Pacific region;• The joint development of the Bayu-Undan gas field in the Joint Petroleum Development Area in the Timor Sea and the related
construction of the 500 kilometer undersea pipeline to transport natural gas from the Bayu-Undan gas field to a planned LNG plantoutside of Darwin, Australia;

5

LNG Supply and Demand Prospects in Asia/Pacific Region(mmtpa)

200

2015

CAG

~
2004

LNG Supply Amount

Mexico West Coast (exc BC)
U.S. West Coast (inc BC)

R 7%
China

150
India
TaiwanKorea

100

LNG Demand

Japan
50

0
2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

Source: Wood Mackenzie• The joint development of the gas fields in the Berau-Bintuni Bay region of Papua, Indonesia and our investment in the Tangguh LNG
Project in Indonesia, which is scheduled to process 1,210 MMcf of natural gas per day and produce approximately 7 million tonnesof LNG per year starting in 2008;• The gas discovery in the Masela block in Indonesia where we act as the operator. The Masela block contains the Abadi structure, thefirst hydrocarbon discovery in the Indonesian territory in the far eastem Timor Sea. We are conducting studies to commercialize theproduction of LNG from the natural gas found in the Abadi structure; and• The gas and condensate discovery in the WA-285-P block (Ichthys) in the Browse Basin on the Northwest Shelf of Western Australia,
where we act as the operator. We discovered natural gas and condensate flow in our exploratory wells drilled in the northwestern partof the permit area and are currently conducting feasibility and marketing studies to engage in the production of LNG or GTL and dimethyl
ether (DME) as well as gas supply to the domestic market.

Successful track record of reserve expansion
Our recent acquisitions have focused on strategic, long-term development projects that will offset expected production declines insome of our mature producing assets. These acquisitions include an interest in the Berau block, the principal block in the Tangguh
LNG project acquired in October 2001, an interest in the ACG oil fields in the Offshore South Caspian Sea area of Azerbaijan acquiredin April 2003, an interest in the Abu Dhabi Marine concession area through the acquisition of all JODCO shares in May 2004, and ourparticipation as an operator in the development of the Azadegan oil field in Iran from February 2004. As a result of these acquisitions
and participation, our three-year average reserve replacement ratio for the years ended March 31, 2004 was 170%. This ratio would be
436% if the acquisition of JODCO had taken place on April 1, 2003.

6

Net Debt to Total Capital Employed*

Equity Ratio**

(%)

(%)

30

100
12.0%

0

(6.9)%

-30

80.2%

75

74.9%

50

-60

52.9%

51.2%

25
(75.8)%(82.8)%-90

0
FY2002

FY2003

FY2004

FY2005

FY2002

Semiannual

FY2003

FY2004

FY2005
Semiannual

Notes:* Net Debt/(Net Debt + Minority Interests + Shareholder’s Equity)
Net Debt = Interest-bearing Debt – Cash and Cash Equivalents – Restricted Cash – Other debt securities with determinable market value** Equity Ratio = Shareholder’s Equity/Total Assets

Sound financial base and access to additional capital resources
Our future growth and capital needs will be supported by our sound capital structure and our significant liquidity. We also expect
to continue to have access to financial assistance from Japanese governmental agencies. Our financial strength is supported by
the following:• Our sound capital structure. We believe we have a strong financial position to fund the increasing future expenditures needed tosupport our sustainable growth. As of September 30, 2004, we had a net debt to total capitalization ratio of (-6.9)%. Net debt isinterest-bearing debt less cash and cash equivalents, restricted cash and other debt securities with determinable market value.
• Our significant liquidity. Our policy is to maintain sufficient cash at all times to enable us to make necessary and appropriate investments for existing and new crude oil and natural gas projects in a timely manner. As of September 30, 2004, we had ¥121.2 billion
yen in cash and cash equivalents and ¥77.2 billion in other debt securities with determinable market value.

Taking advantage of our designation as the national flag company in the upstream oil and gas industry
As the national flag company designated by the Japanese government, we expect to benefit through diplomacy of energy resources by
the Japanese government. Accordingly, we expect to have access to opportunities of new and promising exploration, development
and production projects, and in connection with our participation in such projects, we expect to have the strategic support of theJapanese government.

7Worldwide Exploration & Production Activities
OfficeINPEX Group
Other Investments
Producing
Discovered

Tehran Office

Abu Dhabi Branch

Head Office

Perth Office[ Our Strategy ]Our primary objective as a leading exploration and production company in Japan is to maximize corporate value. In order to achieve
this goal, we are seeking to execute the following strategies:

Increase production through the development of our large existing reserves base
We are actively participating in major projects such as Kashagan, ACG, Azadegan and Tangguh. Our proved undeveloped reserves
give us the opportunity to achieve substantial production growth even without further discoveries of new reserves. We also believe wehave opportunities to develop new probable reserves. As a result of the development and the commencement of production of someof our proved undeveloped and probable reserves, we expect stable net production to increase in the coming years.

Leverage our historical working relationships with major international oil and gas companies to expand ouroperations worldwide
Through our long-term involvement in international projects, we have established positive working relationships with leading oil and gas
companies, including national oil companies in host countries. By capitalizing on these existing relationships, we pursue participationin new promising projects, helping us to capture long-term growth opportunities for our reserves and production levels.

Achieve regional diversification of our asset portfolio, while balancing project phases
We have been diversifying business opportunities in promising regions around the world and acquired high quality assets, including
ACG, Kashagan and JODCO’s assets in the Abu Dhabi Marine Concession area. While focusing on Indonesia and Australia as our corearea and continuing our active involvement in the Caspian Sea area and the Middle East, we are seeking to achieve further geographic
diversification of our assets through participation in new projects in areas such as Africa and South America in the near term, andRussia, particularly Far East and East Siberia in the medium and long term. In addition to regional diversification, we consider various

8Jakarta Office

factors to achieve a well balanced portfolio such as assuming oil and gas operatorships, diversification of contractual arrangements
comprising production sharing contracts, concession agreements and service contracts, and balancing our assets among exploration,
development and production stages.

Enhance activities and capabilities as an operator
While we intend to continue acquiring attractive nonoperator working interests in selected projects, we are also pursuing opportunities
to act as operator in order to have more control over our investments. We have gained operating expertise by working closely over theyear with other leading international oil and gas companies. Furthermore, the acquisition of JODCO brings us valuable technical knowhow and experienced staff in the fields of petroleum development and facility engineering. We are currently the operator of the Masela
block (Abadi) in Indonesia and the WA-285-P block (Ichthys) in Australia as well as the Azadegan oil field in Iran. We are confident that
we will be able to operate these projects accurately and efficiently by outsourcing work to professionals and experts, and expect that,by enhancing our capabilities as an operator, we will be able to compete more effectively in the acquisition and development of new
projects around the world.

Capitalize on the growing demand for LNG in Japan and elsewhere in the Asia-Pacific region, throughinvolvement in major natural gas projects
Increasing demand for LNG in Japan, other countries in Asia and the West Coast of the United States provides us with afavorable environment to increase our natural gas production. In the Asia Pacific region, we have been participating in gas projects
including Mahakam, Tangguh and Bayu-Undan and also engaged in Masela (Abadi) and WA-285-P (Icthys) as an operator. We intend
to leverage our experience and relationships in these projects to further extend our involvement in regional gas projects andthereby expand our exposure to the LNG market generally.

Promote an efficient and transparent business culture that focuses on maximizing corporate value and returnon capital invested
We intend to improve our net ROACE, which was 12.4% on a pro forma basis for the year ended March 31, 2004, through therealization of returns on current development projects, continued focus on cost reductions and continuous portfolio review.

9Global Business Activities

Indonesia

Indonesia represents one of our Core Areas and the foundation of INPEX’s business activities. INPEX has
conducted successful projects in offshore East Kalimantan, as well as in the Natuna Sea and in the offshore Java and Sumatra regions. We also own interests in promising assets such as the Masela Block(Timor Sea) where natural gas and condensate have been discovered, and the Tangguh LNG Project,which is expected to become a new major LNG base in Indonesia.

Offshore Mahakam Block and Attaka Unit, East Kalimantan (INPEX CORPORATION)

East Kalimantan Block

Bontang LNG and LPG Plants 쐽

Santan Terminal 왖Badak Unit

Attaka Unit
Attaka Field

Badak Field

Nilam Unit

Saliki Block

Nilam Field

Tengah Block

Tambora Field

Tunu Field

Peciko Field

Sisi-Nubi Unit
Handil Field

Sisi Field
Nubi Field

Senipah Terminal 왖Bekapai Field

쎲 Balikpapan
Offshore Mahakam Block

Makassar Strait
Gas field
Oil field
Oil and Gas field

10(Producing)

In October 1966 our company entered into a production sharing
contract (PSC) with the Indonesian government and acquired a
100% working interest. This contract covers operations in the
Attaka Unit and the Mahakam Block.
In April 1970, INPEX established the Attaka Unit with Unocal,
each holding 50% interest. Soon after, the Attaka Field was discovered, with production of crude oil and accompanying natural
gas beginning in 1972. INPEX farmed out 50% of our working
interest in the Mahakam Block to TOTAL in July 1970. This venture resulted in the successive discoveries of the Bekapai Field,
Handil Field, Tambora Field, Tunu Field and Peciko Field, all ofwhich are still producing crude oil and natural gas today.
Once produced, crude oil and condensate are shipped bytanker from the terminal mainly to refineries and power companies in Japan. Natural gas is mainly transported to the
Bontang LNG/LPG Plant and then shipped to Japan and othercountries.
In January 1991, the PSC was extended 20 years throughDecember 2017. With this extension, the related blocks will continue to play a central role in INPEX Group operations.

South Natuna Sea Block B
Offshore Mahakam and Attaka Unit
Berau
(Tangguh Unit)

Offshore Northwest Java
MaselaOffshore Southeast Sumatra

Contributing to the Supply of Natural Gas
In August 1977, construction of the first and second gas liquefaction trains in Bontang, East Kalimantan were completed, and they thenbegan receiving supplies of natural gas produced in the East Kalimantan region. Rapidly increasing demand for LNG as a clean energy
source has fueled growth at Bontang, which has become a world leading LNG production plant. This plant has eight trains with anannual production of approximately 21 million tons of LNG and approximately 1 million tons of LPG. INPEX is the largest supplier ofnatural gas to Bontang, fulfilling its key role as a supplier of clean energy resources.
INPEX is also heavily involved in financing activities. The company is the largest investor in four finance companies created for the
purpose of securing construction capital for the liquefaction plants at Bontang.
The blocks where INPEX is active have sufficient reserves for natural gas supply to the Bontang LNG Plant for the term of thecurrent PSC.

LNG Production Volume (Historical and Projected) at Bontang
LNG Plant(Units: million tons)

25
20
15
10
5

Bontang LNG Plant, East Kalimantan

01977 1980

1985

Contracted volume

1990

1995

2000

2005

2009

Volume supplied by INPEXContract Area

Venture Company (est.)

Interest Owned

Offshore Mahakam

INPEX CORPORATIONINPEX 50%/TOTAL 50%

Attaka Unit

(February 21, 1966)

INPEX 50%/Unocal 50%

11Handil Central Processing Area

South Natuna Sea Block B (INPEX Natuna, Ltd.)In September 1978, our subsidiary, INPEX Natuna, acquired aninterest in South Natuna Sea Block B, where the Udang Field had
already been in production.
Subsequent to purchasing the interest in Block B, several new
fields were discovered in this block, including the Ikan Pari Field,
the Belida Field and the Sembilang Field. All crude oil produced
from these fields is shipped out from a sea terminal.
In January 1999, a sales agreement was concluded to deliver
gas from this block and its neighboring Natuna Sea Block A and
Kakap Blocks to Singapore, through the first Indonesian subsea
pipeline connecting foreign markets. Supply began in 2001, andthe following year saw new gas sales to Malaysia from this block.
On the strength of these developments, the PSC for this block
was extended through 2028.

(Producing)

Belida A Platform, South Natuna Sea Block B

Contract Area

Venture Company (est.)

Interest Owned

South Natuna Sea Block B

INPEX Natuna, Ltd.
(September 1, 1978)

INPEX Natuna, Ltd. 35%/ConocoPhillips 40%/ChevronTexaco 25%

Duyong Field

Gas Pipeline

South Natuna Sea Block B

KertehMalaysia Route
Belida Field
Natuna Island

Singapore RouteNatuna Sea

Singapore
Kalimantan Island

12Offshore Southeast Sumatra BlockIntan Field

Widuri Field
Zelda Field
Java Sea

SumatraNorthwest Corner Field

Offshore Northwest
Java Block

Bima Field
Cinta Field
Ardjuna Field쎲 Jakarta
Java

Offshore Northwest Java Block (INPEX Jawa, Ltd.)In 1986, INPEX acquired an interest in the Offshore Northwest
Java Block, which was then transferred to INPEX Jawa, Ltd., ajoint venture with other Japanese oil companies, in January 1987.
The decision for the interest acquisition was based on the factthat not only was this block already producing oil, it also held thepromise of discovery of new fields in unexplored regions.

(Producing)

The crude oil produced from the Ardjuna Field and others isshipped from a sea terminal, and the natural gas is supplied to
PLN (Indonesian national power company) and PGN (Indonesiannational gas company).
In March 2004, INPEX acquired JNOC’s 50% shares of INPEX
Jawa, Ltd. and increased its shares to 85%.

Contract Area

Venture Company (est.)

Interest Owned

Offshore Northwest JavaINPEX Jawa, Ltd. (November 10, 1986)

INPEX Jawa, Ltd. 7.25%/BP 46%/CNOOC approx. 36.72%/three others 10.03%

Offshore Southeast Sumatra Block (INPEX Sumatra, Ltd.)In January 1987, INPEX transferred an interest in the Offshore
Southeast Sumatra Block (acquired at the same time as theacquisition of the Offshore Northwest Java Block interest) to the
newly established INPEX Sumatra, Ltd.
Subsequent to INPEX’s involvement, new discoveries weremade at the Intan and Widuri Fields in this block, both of which
are currently producing oil. The crude oil produced from these(Producing)

fields is shipped via sea terminal. In December 2004, INPEX
Sumatora, together with other contractors, concluded the gas
sales agreement with PLN to supply natural gas from 2006 to2018. The natural gas will be produced mainly from gas fields of
Zelda and Banuwati areas and the sales gas will be supplied to
the Cilegon Power Plant of PLN in West Java by a subsea pipeline.

Contract Area

Venture Company (est.)

Interest Owned

Offshore Southeast Sumatra

INPEX Sumatra, Ltd. (February 15, 1991)

INPEX Sumatra, Ltd. 13.07%/CNOOC 65.54%/five others 21.39%

13

Abadi-1 DST, Masela Block

Masela Block, Timor Sea (INPEX Masela, Ltd.)(Discovered)

In December 1998, we won an open bid for and acquired a 100%interest as an operator in the Masela Block of the Timor Sea.
In December 2000, INPEX discovered a large-scale gas structure, Abadi, by drilling an exploration well in the Masela Block.
This represented the first discovery of natural gas in the Indonesian Timor Sea. In 2002, two appraisal wells delivered results that
far exceeded expectations. These two wells confirmed a considerable volume of gas and condensate reserves. We are presently
engaged in preparing for development and future commercialization, including the development of LNG as well as new technologies in GTL and DME production.
INPEX, working as a 100% operator in the permit WA-285-P(Browse), offshore Western Australia, discovered a considerable
volume of gas and condensate reserves. We intend to evolve into

a production operator through the commercialization of both ofthese blocks.

Timor Sea Joint Petroleum
Development Area

Indonesia

Masela Block

Abadi-3 쎲쎲 Abadi-2/ 2ST
es)oundari쎲 Abadi-1
tional B(InternaAustralia

Timor Sea

Contract Area

Venture Company (est.)

Interest Owned

MaselaINPEX Masela, Ltd. (December 2, 1998)

INPEX Masela, Ltd. 100%

Berau Block, Papua Province Tangguh LNG Project (MI Berau B.V.)
In October 2001, INPEX, working in a joint venture with Mitsubishi
Corporation, invested in MI Berau B.V., which holds an interest in
the Berau Block, a principal block in the Tangguh LNG Project, thethird LNG Project in Indonesia. Through this investment, INPEX
acquired a participating interest in the gas reserves of the Tangguh
LNG Project. The Tangguh project is scheduled to commence LNG
production around 2008. Long term sales agreements to supply
LNG for China, Korea and the U.S. have already been concluded.

Papua Province

Muturi Block

Misool Island
Wiriagar Block

Berau Block

Seram Island

Contract Area

Venture Company (est.)

Interest Owned

Berau

MI Berau B.V. (August 14, 2001)

MI Berau B.V. 22.856%/BP 48%/Nippon Oil Exploration (Berau), Ltd. 17.144%/
KG Berau 12.0%(Tangguh Unit)

14(Discovered)

MI Berau B.V. 16.3%/BP 37.2%/ CNOOC 12.5%/others 34%

Drilling Rig, Timor Sea

Expansion of Exploration Activities
To further bolster our status in the East Kalimantan area, and to increase assets that lead directly to commercialization, we are
strategically strengthening exploration activities in blocks around East Kalimantan and South Natuna Sea Block B. These efforts will
replenish assets in Indonesia, an INPEX Core Area.

Contract Area

Venture Company (est.)

Interest Owned

Saliki, Offshore East
Kalimantan

INPEX Offshore Northeast Mahakam, Ltd. (June 11, 1997)

INPEX Offshore Northeast Mahakam, Ltd. 50%/TOTAL 50%

East Kalimantan,
Offshore East Kalimantan(producing block)

INPEX Offshore North Mahakam, Ltd. (November 6, 2002)

INPEX Offshore North Mahakam, Ltd. 7.5%/
Unocal 92.5%

Nila, Natuna Sea

INPEX North Natuna, Ltd. (January 18, 2002)

INPEX North Natuna, Ltd. 35%/
ConocoPhillips 65%

Santan LPG Storage Facility

15

JPDA03-01
JPDA03-12Australia andJoint Petroleum Development
Area (JPDA)
WA-285-P

WA-10-L

WA-155-P
WA-12-L

VIC/P51
VIC/P52

VIC/P42

T/33P

Together with Indonesia, this region represents another INPEX Core Area. INPEX Alpha, Ltd. has been very
active in this area, with successes in offshore Western Australia. Together with our involvement in the BayuUndan LNG Project in the Joint Petroleum Development Area (JPDA), we intend to increase our assets in thisarea, pursuing a policy of proactive exploration in the region. We have also succeeded in discovering natural
gas and condensate, working as an operator in the permit WA-285-P, offshore Western Australia.

1. Projects in Australia
WA-10-L and others, Offshore Western Australia (INPEX Alpha, Ltd.)In February 1989, INPEX acquired a participating interest in thepermit WA-210-P in offshore Western Australia. This interest wasthen transferred to our subsidiary, INPEX Alpha, Ltd. As a resultof subsequent exploration activities, the Griffin Fields were discovered, and a production license (WA-10-L) was granted by theAustralian government for four blocks. Commercial production

Griffin Venture

16(Producing)from these blocks started in January 1994. The crude oil produced from the WA-10-L is processed and stored at the Griffin
Venture, a floating production storage unit, and then shipped forsale. Natural gas is also processed at the Griffin Venture and istransported through a 70 kilometer underwater pipeline whichconnects to the mainland’s trunk pipeline. The natural gas is thentransported for sale to an onshore gas producer.
In August 1995, INPEX Alpha also acquired participatinginterests in the WA-155-P (Part II) and the WA-12-L permits.
In July 1999, our company acquired an interest in the permit
WA-155-P (Part I). The Vincent and Ravensworth discoveries weremade in this permit.
In March 2001, our company received 54% of the outstanding shares of INPEX Alpha, Ltd. from Japan National Oil Corporation (JNOC), after which INPEX Alpha became a 100% subsidiaryof INPEX CORPORATION.

Contract Area

Venture Company (est.)

Interest Owned

WA-10-L

INPEX Alpha, Ltd. (February 17, 1989)

INPEX Alpha 20%/BHPBP 45%/ExxonMobil 35%

WA-155-P (Part I)

INPEX Alpha 28.5%/BHPBP 39.999%/Apache 31.501%

WA-155-P (Part II)

INPEX Alpha 18.67%/Apache 81.33%

WA-12-L

INPEX Alpha 18.67%/ExxonMobil 81.33%

Drilling Rig, WA-285-P

Expansion of Exploration Activities
INPEX Alpha, Ltd. has a total of eight projects in Australia, including four projects in offshore Western Australia and four projects
in offshore Tasmania, Victoria. These activities are part of our overall goal to increase our assets in Australia, one of the Core
Areas for INPEX.

RegionContract Area

Interest Owned

Bass Strait, Victoria

VIC/P42

INPEX Alpha 50%/Bass Strait Oil 50%

Offshore Portland, Victoria

VIC/P51

INPEX Alpha 20%/Santos 80%

VIC/P52

INPEX Alpha 33.33%/Santos 33.33%/Unocal 33.33%

Northwest Ocean, Tasmania

T/33P

INPEX Alpha 20%/Santos 80%

WA-285-P, Offshore Western Australia (INPEX Browse, Ltd.)INPEX transferred its 100% interest in the permit WA-285-P, offshore Western Australia, to our subsidiary, INPEX Browse, Ltd. in
September 1998. INPEX had previously won the interest throughan open bid.
INPEX Browse has pursued exploration activities as a 100%
operator, resulting in the discovery of an extremely promising gas
and condensate structure, Icthys, during 2000.
A development scheme is in the planning stages, looking
toward not only LNG, but also new technologies associated with
GTL and DME, as well as possibilities for domestic supply.

(Discovered)

Operation in Offshore Western Australia

Contract Area

Venture Company (est.)

Interest Owned

WA-285-P

INPEX Browse, Ltd. (September 1, 1998)

INPEX Browse 100%17

2. Projects in the Timor Sea Joint Petroleum Development Area (JPDA)(International Boundaries)

West Timor
Timor Sea Joint
Petroleum Development
Area

JPDA03-01
Kuda Tasi
Jahal

Elang-Kakatua Field

JPDA03-12

Planned gas pipeline to Darwin
Bayu-Undan gascondensate Field
Darwin •Timor Sea

Australia

Image of Offshore Production Facility, Bayu-Undan

JPDA03-12 Timor Sea Joint Petroleum Development Area (INPEX Sahul, Ltd.)In April 1993, INPEX acquired a 21.21% working interest in the
JPDA03-12 Contract Area, located in the Timor Sea Joint Petroleum Development Area which is an area jointly administered by
the government of Australia and East Timor.
The exploration operations in this contract area resulted in
the discovery of oil and gas in the Elang, Kakatua, Kakatua North,
Bayu-Undan and Hingkip structures. Production began in the Elangfield in July 1999, and in the Kakatua and Kakatua North Fields inthe following month.
The Undan gas-condensate field was discovered in JPDA0312 in 1995 immediately after the Bayu field was discovered in
JPDA03-13 in 1995 which is located directly east of JPDA03-12.
Both the JPDA03-12 and JPDA03-13 partners determined thatthe Bayu and Undan fields are a common gas-condensate accumulation and straddle both contract areas. In 1999, the unit operating agreement and the unitization agreement were entered into

18

(Producing)

between JPDA03-12 and the JPDA03-13 partners to establish
the Bayu-Undan unit for the purpose of carrying out the development and production of the Bayu-Undan gas-condensate field.
The original plans of the Bayu-Undan unit called for thedevelopment and production of condensate and LPG only. However, during 2002, an LNG sales contract was agreed designating the unit as a gas supply source for delivery to Japan. This
arrangement necessitated new plans for developing the unit as
an LNG project. For INPEX, the Bayu-Undan Project will standalongside the LNG projects of Bontang and Tangguh in Indonesia in terms of scale and importance.
In connection with this LNG project, INPEX established INPEXDLNGPL Pty Ltd for the purpose of investing in an undersea pipeline to Darwin, Australia, and in a venture carrying out the construction and operation of an LNG plant in the suburbs of Darwin.

Contract Area

Venture Company (est.)

03-12

INPEX Sahul, Ltd. (March 30, 1993)(Bayu-Undan Unit)

Undersea pipeline project
connecting the Bayu-Undan
gas-condensate Field
with Darwin

Interest Owned
INPEX Sahul 19.07%/ConocoPhillips 46.71%/Santos 19.27%/Petroz 14.95%
INPEX Sahul 10.53%/ConocoPhillips 48.47%/Santos 10.64%/Petroz 8.25%/
EniAgip 12.04%/
Tokyo Timor Sea Resources (Tokyo Electric/ Tokyo Gas) 10.08%

INPEX DLNGPL Pty Ltd(March 19, 2003)

INPEX DLNGPL Pty 10.53%/ConocoPhillips 48.47%/Santos 10.64%/
Petroz 8.25%/EniAgip 12.04%/
Tokyo Timor Sea Resources (Tokyo Electric/ Tokyo Gas) 10.08%

Construction and operationof an LNG plant in Darwin

JPDA03-01 Timor Sea Joint Petroleum Development Area (JPDA) (INPEX Timor Sea, Ltd.) (Discovered)
INPEX acquired the JPDA03-01 Contract Area in an open bid in
October 1991. In January 1992, all relevant parties signed a PS
contract. Subsequently, the drilling of five exploration wells

resulted in the discovery of crude oil in the Jahal, Klill and Kuda
Tasi structures.

Contract Area

Venture Company (est.)

Block Interest Ownership

03-01

INPEX Timor Sea, Ltd.
(November 25, 1991)

INPEX Timor Sea 35%/Woodside 40%/Santos 25%

19

Caspian Sea Area
Offshore North
Caspian Sea
ACG Oil Field
BTC Pipeline

In 1998, INPEX made its appearance in the Caspian Sea, successfully discovering the Kashagan Field, a
giant oil field in the North Caspian Sea. In 2003, we acquired the interests in the ACG Oil Field, a giant oilproducing field in the South Capian Sea. We are also participating in the BTC Pipeline, which serves as
an important transport facility for both the Kashagan Field and the ACG Oil Field.
INPEX’s activities in the Caspian Sea area will serve to expand our business. These projects will contribute to our corporate strategy of creating a balanced regional asset portfolio across the globe. These projects
deal mainly with crude oil, which will contribute to improving our balance between oil and gas assets.
Offshore North Caspian Sea Block, Republic of Kazakhstan (INPEX North Caspian Sea, Ltd.) (Development)
In September 1998, INPEX North Caspian Sea, Ltd., establishedjointly between INPEX and other Japanese companies, concluded an
Assignment and Assumption agreement with the Kazakhstan government and KazakhOil. Under the terms of this agreement, a participatory interest in the attractive North Caspian Sea Block was acquired.
The block contains regions encapsulating five giant structures.
The September 1999 drilling of the first exploration well, Kashagan
East 1 in the Kashagan Structure, the largest of the five structuresand located in the eastern part of the block, resulted in the discovery of oil. This discovery was formally announced in July of thefollowing year. This event represented the first discovery in the
Kazakhstan controlled area of the Caspian Sea. The Kashagan oil
field is the largest oil field discovered in the past 30 years. Total oil
production is anticipated to reach 13 billion barrels by maximizing
oil production though the injection of gas produced concomitantlywith the oil into the reservoir. In June 2002, KazMunayGas andthe North Caspian Sea PSA Contracting Companies made a Declaration of Commerciality for the block. In addition to the Kashagan
Structure, this block holds four other structures. In addition,
exploratory wells were drilled in four other structures, the Kalamkas,
Kashagan Southwest, Aktote and Kairan structures from 2002 to
2004. All of the wells confirmed hydrocarbon reserves and thedeclarations of discovery were made for each of the structures.

20

RussiaKazakhstan

쎲 Atyrau쎲 Astrakhan

Caspian Sea

Offshore North
Caspian Sea
BlockOperation in Offshore North Caspian Sea

Contract Area

Venture Company (est.)

Interest Ownership

Offshore North Caspian Sea

INPEX North Caspian Sea, Ltd.
(August 6, 1998)

INPEX North Caspian Sea 1/12/
EniAgip/ExxonMobil/Shell/ TOTAL/BG 1/6 each/ConocoPhillips 1/12

Azerbaijan

쎲
Baku

AtyrauACG Oil Field

쎲
Sangachal
Oil pipeline
BTC pipeline

CPC pipeline

OdessaDeep water portionof the Gunashli Field

North CaspianSea Block

Chirag Field

Constanta

Azeri Field

Northern Route
Novorossiysk

Aktau

Makhachkala
Supsa

Caspian Sea
Black Sea

TbilisiIstanbul

Western
Route

Caspian Sea
Baku

BTC PIPELINEACG Oil Field

CeyhanMediterranean Sea

ACG Oil Field, Caspian Sea, Republic of Azerbaijan (INPEX Southwest Caspian Sea, Ltd.) (Producing)
The Azeri-Chirag-deepwater Gunashli Fields, known as the ACG
Oil fields, are located in the South Caspian Sea area of the Republic of Azerbaijan. In December, 2002, we entered into an agreement to purchase a 10% working interest in the ACG Oil fields. In
April, 2003, with the consent of SOCAR, the Azerbaijian national
petroleum company, and the other ACG partners, the 10% interestin the ACG Oil fields were transferred to us. We are a member of
The Azerbaijan International Operating Company, or AIOC, a joint
operating company formed by the ten participating companies tooversee the operations of the ACG Oil fields. BP has assumed theoperatorship of ACG Oil fields. We have been participating in the

ACG Oil fields through INPEX Southwest Caspian Sea, Ltd., ourconsolidated subsidiary, in which JNOC holds a 49% interest.
Crude oil production began at the Chirag field in 1997 and its
current production is approximately 150,000 barrels per day. This
project is expected to increase production in stages, aiming toreach a production level of 1 million barrels per day by 2009. The
crude oil from these fields is currently being transported along aroute running from Baku to Supsa on the Black Sea (Western Route).
However, once construction of the BTC Pipeline has been completed, oil will mainly be transported via this route to theMediterranean Sea.

Contract Area

Venture Company (est.)

Interest Ownership

ACG Oil Fields

INPEX Southwest Caspian Sea, Ltd.
(January 29, 1999)

INPEX Southwest Caspian Sea 10%/BP 34.14%/Unocal 10.28%/SOCAR 10%/
Statoil 8.56%/ExxonMobil 8%/Itochu 3.92%/three others 15.1%

BTC Pipeline (INPEX BTC Pipeline, Ltd.)In September 2002, through our wholly-owned subsidiary, INPEXBTC Pipeline, Ltd., we acquired a 2.5% interest in the 1,760 km
BTC pipeline project in order to secure promising means of transporting crude oil produced by our projects in the Caspian Sea
from Baku (Azerbaijan) to Ceyhan (Turkey) on the Mediterranean
Sea via Tbilisi (Georgia). The multinational consortium formed by
11 companies is carrying out the construction and operation of
the BTC pipeline project.

The construction of the pipeline began in 2003 and is expected
to be completed and ready to export oil produced from the ACG
oil fields in 2005. Upon completion, the pipeline is expected tohave the capacity to transport 1 MMbbls of oil per day. Moreover,the BTC pipeline partners are contemplating further increasing
the transport capacity to accommodate the crude oil produced
from the Kashagan field.

Project

Venture Company (est.)

Interest Ownership

BTC Pipeline

INPEX BTC Pipeline, Ltd.
(October 16, 2002)

INPEX BTC Pipeline 2.5%/BP 30.1%/SOCAR 25%/Unocal 8.9%/
Statoil 8.71%/TPAO 6.53%/EniAgip 5%/TOTAL 5%/Itochu 3.4%/
ConocoPhillips 2.5%/Amerada Hess 2.36%

21

Azadegan Oil Field

Middle East

Soroosh Field andNowrooz Field

Abu Al Bukhoosh
ADMA

INPEX has working interests in the ADMA Block and the ABK Block offshore Abu Dhabi and produces
crude oil from a total of six fields. In Iran, INPEX is acting as operator in appraisal and development
operations in the Azadegan Oil Field. As with the Caspian Sea and South America, INPEX has designatedthe Middle East as one of our essential Target Areas, worthy of our continued development efforts.

ADMA Block, United Arab Emirates (Japan Oil Development Co., Ltd. (JODCO))In May 2004, INPEX made Japan Oil Development Co., Ltd.
(JODCO) a wholly owned subsidiary by acquiring, through a shareexchange, all the shares in the company held by Japan National
Oil Corporation (JNOC).
JODCO was established in 1973 and currently produces
crude oil from five fields in the ADMA Block, located in the Abu
Dhabi Marine Concession Area offshore Abu Dhabi, the United
Arab Emirates. Production in the Upper Zakum Field, the area’s
largest oil field, began in 1982, and in the Umm Al-Dalkh andSatah fields, in which JODCO took part in operations, in 1985
and 1987, respectively. Production has continued steadily since.
Crude oil production also continues at two existing fields: theUmm Shaif and Lower Zakum fields. Production at these locations began in 1962 and 1967, respectively. Crude oil is transported by subsea pipeline to the islands of either Das or Zirku,
and then shipped.
These five fields are operated by local operating venture companies. JODCO continuously sends a number of its personnel,
primarily engineers, to those companies.

Pipeline

ADMA Block
Umm Shaif Field

Das Island
Upper Zakum Field
Lower Zakum Field

Satah Field
Zirku Island

Umm Al-Dalkh Field
Abu DhabiContract Area

Venture Company (est.)

Interest Ownership

Umm Shaif Field/Lower Zakum Field

Japan Oil Development Co., Ltd.

JODCO 12%/ADNOC 60%/BP 14.67%/TOTAL 13.33%

Upper Zakum Field/Umm Al-Dalkh Field(February 22, 1973)

JODCO 12%/ADNOC 88%

Satah Field

22(Producing)

JODCO 40%/ADNOC 60%

Abu Al Bukhoosh Block, United Arab Emirates (INPEX ABK, Ltd.)In January 1996, INPEX acquired a 25% working interest in theconcession agreement covering the Abu Al Bukhoosh block offshore Abu Dhabi. In February 1996, we formed INPEX ABK, Ltd.
with JNOC and Mitsubishi Corporation and transferred our 25%
interest in the concession area to INPEX ABK. In March 2004, we
acquired JNOC’s 40% share in INPEX ABK.
This project is the first for INPEX in the Middle East oilproducing block, serving as a beachhead for additional projects
in the future.
Crude oil from the Abu Al Bukhoosh Field is sent by pipeline
to Das Island, where it is blended with crude oil from the Umm
Shaif Field, and then shipped on as Umm Shaif Crude.

(Producing)

Abu Al Bukhoosh Field

Abu Al Bukhoosh Block(International Boundaries)쎲
Abu Dhabi
United Arab Emirates

Contract Area

Venture Company (est.)

Interest Ownership

Abu Al Bukhoosh Block

INPEX ABK, Ltd. (February 29, 1996)

INPEX ABK 25%/TOTAL 75%

Soroosh Field and Nowrooz Field, Islamic Republic of Iran (JJI S&N B.V.)쎲

Bandar Khomeyni
Iran

Nowrooz Field
(In
ter
na
tio
na
lB

Soroosh Field

ou
nd
ary
)

In January 2003, JAPEX and INPEX participated in the development project of the Soroosh and Nowrooz Fields through joint
investment in JJI S&N, which holds a 20% participating interest in
the project.
Shell conducts development operations as the operator basedon a service contract (a so-called “buyback” contract) which wasentered into in 1999 with National Iranian Oil Company (NIOC).
Production at the Soroosh Field began in December 2001.
Currently the preparation for full scale production such as drillingdevelopment wells and constructing offshore production facilities
is under way.

(Producing)

Contract Area

Venture Company (est.)

Interest Ownership

Soroosh Field and Nowrooz Field

JJI S&N B.V. (October 3, 2002)

JJI S&N 20%/Shell 70%/OIEC 10%

Bushehr쎲

23

Azadegan Oil Field, Islamic Republic of Iran (Azadegan Petroleum Development, Ltd.)In February 2004, INPEX entered into a service contract (a socalled “buyback contract”) which became effective in March 2004
with Iran’s National Iranian Oil Company (NIOC) and its subsidiary, Naftiran Intertrade Co. Ltd. (NICO) for the integrated appraisaland development operations of the Azadegan Oil Field in the Islamic
Republic of Iran.
Under this agreement, INPEX holds a 75% participating interest
as an operator in the project to develop the oil field, with NICO
holding the remaining 25%. Under the current plan, twodevelopment stages are contemplated, where the second stage is
optional. In the first stage, oil production from the field is scheduled
to reach 50,000 bbls per day within 40 months after the effective
date of the contract, and a production level of 150,000 bbls per
day is scheduled to be reached within 52 months. In the optional
second stage, the production level is expected to increase by afurther 110,000 bbls per day within 8 years after the effective date.
Our engagement as an appraisal and production operator is
expected to enhance both our technological capabilities and presence as an international oil and gas development company.
Preparations are now underway to transfer INPEX’s participating interest in the project to wholly owned subsidiary Azadegan
Petroleum Development, Ltd.

24

(Development)쎲 Tehran

Baghdad쎲

Azadegan Oil Field
Iraq쎲 Ahwaz쎲 Kuwait

Contract Area

Venture Company (est.)

Interest Ownership

Azadegan Oil Field

Azadegan Petroleum Development, Ltd. (February 18, 2004)

INPEX 75%/NICO 25%

IranSouth America
In Brazil, INPEX has signed a Master Agreement with respect to the expansion of oil production in the
Albacora Field Concession. We are also engaged in oil field exploration in the Frade Block, offshore North
Campos. We expect further business development in this area.
Frade
Albacora

Frade Block Offshore North Campos, Brazil (INPEX Offshore North Campos, Ltd.)In July 1999, through Frade Japão Petróleo Limitada, or FJPL,
our equity method affiliate, we acquired a 12.75% interest (which
subsequently increased to 15%) in the Frade Block. FJPL is whollyowned by INPEX Offshore North Campos, Ltd., which is a joint
venture with JNOC and Sojitz Corporation which hold 50% and12.5% interest, respectively, while we retained the remaining
37.5% interest.
The Frade Block consists of a discovered portion with confirmed crude oil reserves and an undeveloped oil accumulation in
the northern Campos Basin, Brazil’s largest oil-producing region.
ChevronTexaco is the operator and the Frade partners are planning to commence development activities in 2005.

Campos 쎲(Discovered)Atlantic Ocean
Frade Block
Albacora Field

쎲 Macae
Marlim Field

Roncador Field

Contract Area

Venture Company (est.)

Interest Ownership

Frade

INPEX Offshore North Campos, Ltd. (October 12, 2000)

INPEX Offshore North Campos 15%/
Petrobras 42.5%/ChevronTexaco 42.5%

Albacora Block, Offshore North Campos, Brazil (Albacora Japão Petróleo Limitada (AJPL)) (Producing)
In December 1998, we established Albacora Japão Petróleo
Limitada, or AJPL, a Brazilian entity, jointly with Sojitz Corporation and we own 50% of AJPL. In November 2000, AJPL enteredinto a master agreement with Petrobras, the Brazilian nationaloil company.
Under this agreement, AJPL agreed to provide to Petrobras
the exclusive right to possess and use the assets in connection
with the Albacora Field Phase II Development Project and in turnhas been granted the oil allotments for nine years.

It is our belief that INPEX’s participation in this second projectin Brazil will give us more opportunities for involvement in new
projects by building a stronger cooperative relationship withPetrobras. Furthermore, through periodic dialogue with Petrobras,
we hope that we will be able to share expertise on deepwater
exploration and development technologies, skills in which
Petrobras has a world-class reputation.

Contract Area

Venture Company (est.)

Albacora

Albacora Japão Petróleo Limitada (AJPL) (December 23, 1998)25

Corporate Governance

INPEX contributes to ensuring a stable and efficient supply of energy to Japan, a social
responsibility it takes very seriously. Within this context, INPEX recognizes that enhancing corporate governance is an important management imperative.

Company Organizations
Management Bodies
Directors and Board of Directors
At INPEX, representative directors and other directors who act as executive officers carry out business operations. The execution ofthese business operations is overseen by the Board of Directors, which also discusses and decides on important business affairs.
Meetings of the Board are convened once a month and at other times as necessary. The Board is made up of 18 directors, 4 of whom
are outside directors. Each of these four outside directors serve concurrently as directors of Japan Petroleum Exploration Co., Ltd.,
Mitsubishi Corporation, Mitsui Oil Exploration Co., Ltd. and Marubeni Corporation, which are corporate shareholders of INPEX. As
business experts with extensive knowledge and experience in INPEX’s business fields, these outside directors are asked to express
opinions on management of essential INPEX businesses that contribute to its development from both specialist and objective perspectives. The business fields of the previously mentioned corporate shareholders include overseas upstream businesses. Therefore theymight compete against the INPEX Group occasionally. For this reason, INPEX recognizes the need to abide by special corporate
governance measures with respect to the possibility of conflicts of interest. To this end, each of INPEX’s directors, including outside
directors, is required to sign a written undertaking to comply with the Japanese Commercial Code relating to such matters as noncompetition practices, proper treatment for transactions giving rise to a conflict of interest and unauthorized information disclosure.
This reflects the importance of precisely carrying out their duties as directors with a high level of awareness of such matters.

Executive Committee
Made up of managing directors and above, the Executive Committee was established in April 2002 to expedite decision-making. In
principle, the Committee is convened every week, and at other times as necessary, to decide on matters that do not require aresolution of the Board and to conduct discussions that facilitate Board decisions. In addition to the aforementioned members of theCommittee, executive directors and standing statutory auditors, as well as representatives of departments related to resolutions andreports being discussed also attend these meetings.

Statutory Auditors and Board of Statutory Auditors
INPEX employs the statutory auditor system. Statutory auditors attend important meetings such as the Board of Directors and Executive
Committee. In addition, they conduct interviews with departments as necessary and audit the execution of duties of directors with regard
to the company’s overall business affairs and individual projects based on reports from relevant departments and other information.
Furthermore, statutory auditors receive reports related to every audit from the independent auditors and internal audit reports from theInternal Audit Department. The Board of Statutory Auditors, which consists of all statutory auditors, determines auditing policy, formulates
audit plans and receives reports on the status of audits and other matters from statutory auditors. To bolster the audit system, the number26

of statutory auditors was increased from three to four in June 2002. The result is that there are now three outside statutory auditors (onestanding and two part-time) and one other statutory auditor (standing). Moreover, since June 2003, the Board of Statutory Auditors hasconvened every month instead of every three months as before.

Internal Audit
The Internal Audit Department was established as an organization independent from business departments and reporting directly tothe president, to ensure the appropriateness and efficiency of business activities. As a body cutting across the INPEX Group, theInternal Audit Department evaluates the internal control systems of the group, including overseas offices. It also examines and evaluates the status of management bodies, the efficiency of business operations and other matters, pinpointing problem areas, making
necessary reports and conducting follow-up audits to confirm the status of improvements. The activities of the Internal Audit Department thus contribute to the proper management of the INPEX Group.

Classes of Share and Corporate GovernanceThe company’s Articles of Incorporation stipulate that certain major corporate decisions require a resolution by the holder of the specialclass share, in addition to the approval of the ordinary general meeting of shareholders or Board of Directors. The one special classshare was issued on November 17, 2004 to coincide with the listing of INPEX’s common stock on the Tokyo Stock Exchange. This
share is held by Japan National Oil Corporation (JNOC).
Major corporate decisions include “the appointment and removal of directors,” “the disposal of material assets,” “material amendments to the Articles of Incorporation,” “mergers, share exchanges or share transfers,” “capital reductions” and “dissolution.” Amongthese decisions the special class share will allow the holder to veto any appointment or removal of directors and any merger, shareexchange or share transfer, provided 20% or more of the voting rights attached to shares of common stock are held by a single nonpublic entity or a single non-public entity and its joint shareholders.
JNOC has established guidelines for the exercise of the special class share’s veto rights (with respect to decisions not approved bya meeting of the special class shareholder) in accordance with its internal business regulations. JNOC may veto any one of theaforementioned major corporate decisions only to the extent that it determines a proposed action or transaction (1) will likely result in
INPEX being managed in a manner inconsistent with its goal of securing a stable and efficient energy supply for Japan as a national flag
company; (2) will likely adversely affect the goal of efficiently securing a stable and efficient energy supply for Japan as a national flag
company; or (3) may affect the exercise of voting rights of the special class share held by JNOC. Furthermore, JNOC is obliged toobtain the approval of the Minister of Economy, Trade and Industry before exercising its voting rights or carrying out any other action
at the general meeting of the special class shareholder.
The exercise of veto rights by the special class share is thus restricted. With the existence of this class of share, INPEX believes thatit can minimize the risk of losing management control to foreign-owned concerns and an unsolicited takeover for speculative reasons.

27

Headquarters Organization Chart

Audit
Committee

General Shareholders
Meeting

Board ofDirectors

Executive
Committee

President

Secretary

Planning &New Ventures

Geophysics

Corporate Planning& Management

Accounting &Finance

Development

Internal Audit

MarketingPetroleum
Technology

GeneralAdministration

Gas BusinessJakarta OfficePublic Affairs

Exploration 1

Tehran Office

General Affairs

Exploration 2

Perth Office(Overseas office for INPEX Alpha,
INPEX Browse)

Abu Dhabi Branch(Overseas office forJapan Oil Development Co., Ltd.)

Moreover, because the scope of the veto is limited and guidelines have been set by JNOC for the exercise of veto rights, the specialclass share is an absolute minimum necessary measure that is highly transparent and does not unjustly impinge on INPEX’s ability tooperate with flexibility and efficiency.
After the scheduled abolishment of JNOC, the special class share shall be transferred to either the Japanese government or aJapanese governmental agency. If the special class share is transferred to an entity other than the Japanese government or a Japanese
governmental agency, INPEX shall be entitled to redeem it by a resolution of the board of directors.

Risk Management and Corporate Ethics
INPEX recognizes that two factors are vital to increase corporate value amid drastic changes in its operating environment: forestallingand mitigating losses by properly managing risk inherit in its business operations; and maintaining and strengthening trust with customers, investors and other parties. A wide range of risk factors could affect corporate value. With respect to risks associated withmanagement decisions such as management strategy, related departments analyze and examine issues, receiving advice from attorneys of law and other outside specialists as necessary. Materially important projects are decided on by the Board of Directors after firstbeing discussed by the Executive Committee and other managerial bodies. Subsequent changes in matters related to these projects
are then closely monitored.
The INPEX Group has formulated a set of Business Principles that embody the basic policies of its corporate activities. These
principles encompass corporate goals; code of conduct; corporate growth; ethics; health, safety and environment; and contributions
to society. The INPEX Group believes that by strictly adhering to these principles it can maintain and increase the trust and credibilityof the company in the eyes of shareholders, employees, business partners and international society—a vital element of continuous
corporate development. The company’s commitment to this approach is unwavering.

28

Financial Section

Contents
Management’s Discussion and Analysis of Financial Condition
and Results of Operations ............................................................ 30
Consolidated Balance Sheets ........................................................ 46
Consolidated Statements of Income ............................................... 48
Consolidated Statements of Shareholders’ Equity .......................... 49
Consolidated Statements of Cash Flows ........................................ 50
Notes to Consolidated Financial Statements .................................. 51
Report of Independent Auditors ..................................................... 61
Supplemental Information
Semiannual Consolidated Balance Sheets ..................................... 62
Semiannual Consolidated Statements of Income ............................ 64
Semiannual Consolidated Statements of Shareholders’ Equity ....... 65
Semiannual Consolidated Statements of Cash Flows ..................... 66
Notes to Semiannual Consolidated Financial Statements ............... 6729

Management’s Discussion and Analysis of Financial Condition
and Results of Operations

Overview
For the year ended March 31, 2004, we had net sales of ¥218.8 billion and net income of ¥34.8 billion. Net sales of crude oil and natural
gas amounted to ¥68.8 billion and ¥150.0 billion, respectively. Based on both production and reserves, we are the largest upstream oil
and gas company in Japan. As of March 31, 2004, our total net proved reserves were approximately 977 MMboe, and for the year ended
March 31, 2004, our net annual production was 195.5 Mboe per day.
Giving effect to our acquisition of JODCO, we had estimated net proved reserves of 1,634 MMboe, comprised of 1,016 MMbbls of
crude oil, condensate and LPG, and 3,704 Bcf of natural gas as of March 31, 2004. Approximately 38% of such reserves were classified
as net proved undeveloped. On the same basis, net production for the year ended March 31, 2004 averaged 173.2 Mbbls per day ofcrude oil, condensate and LPG, and 814.5 MMcf per day of natural gas, which together totaled 309.0 Mboe per day.
We engage primarily in the exploration, development and production of natural gas and crude oil in Indonesia, the Middle East,
Oceania, the Caspian Sea and certain other areas. Currently, most of our natural gas production takes place in Indonesia. We supply
the natural gas we produce in Indonesia to PERTAMINA, an Indonesian oil and gas company, which in turn sells most of the natural gas
to power and gas companies and others in Japan, Korea and Taiwan. A substantial portion of our crude oil production takes place in
the Middle East, in particular the United Arab Emirates. We sell substantially all of our crude oil production to electric power companies,
oil refinery companies and others in Japan.
We consider Asia, including Indonesia, and Oceania, including Australia, to be our core areas and the Middle East and the CaspianSea to be our target areas. The reserves of some of the projects in those core areas that are currently producing are expected to decline
over the next ten to fifteen years. In order to address such future reduction of reserves, we have been actively seeking new prospective
oil and gas projects to replace and supplement reserves in our existing core areas as well as other areas. In our core areas, we havediscovered natural gas and condensate in the course of our acting as operator in the Masela block in Indonesia and the WA-285-P(Ichthys) block in Australia, which we hope to bring to successful development and production. In other areas, in February 2004, weentered into a service contract with NIOC, Iran’s national oil company, for the development of the Azadegan Field, which, if we successfully
move to a production phase, will increase our crude oil production in the Middle East. We are also involved in exploration, development
and production in other areas, including the North and South Caspian Sea. Furthermore, we may acquire additional oil and gas assets
from JNOC prior to its abolishment, which is expected to occur by July 2005. We are actively seeking opportunities to acquire additional
working interests in fields which are already producing, as well as those under development. We expect that, over the next several years,
our development activities will significantly increase, thereby requiring substantial expenditures, and that such expenditures will require
additional financing.
As we invest in additional projects, we are seeking to diversify in our business operations in five principal ways, which we expect willmaterially affect our future results of operations and financial condition:• We are diversifying our areas of production to reduce the relative concentration of our crude oil and natural gas production assets
in Indonesia.
• In recent years, a substantial portion of our production volume and reserves have been natural gas, as opposed to crude oil, inparticular natural gas production in the Mahakam contract area in Indonesia. We are focusing on participating in more new projects
for crude oil, such as those in the Caspian Sea, as well as those in the Middle East through the acquisition of the right to develop the
Azadegan Field in Iran and the acquisition of JODCO, for the purpose of achieving a better balance between crude oil and naturalgas. There are material differences between crude oil and natural gas in terms of susceptibility to market price fluctuations, the timenecessary to recover costs, the manner in which they are sold, the average duration of the sales arrangements and the infrastructure
required for transportation.
• Historically, we have participated in most projects as a non-operator. We are now seeking opportunities to act as project operator.
Already, we are acting as operator in exploration and appraisal projects in the Masela block in Indonesia and the WA-285-P (Ichthys)
block in Australia. Also, we were appointed as an operator to develop the Azadegan Field in Iran.
• We are diversifying the mix of our working interests in the exploration, development and production phases. Crude oil and natural gas
exploration and development require substantial expenditures and investments, with high risks of failure. We have been seeking toacquire working interests in projects that are already in the production phase in addition to those under development, which would
provide additional operating cash flow to fund our exploration and development activities.
• We are diversifying the types of arrangements for exploration, development and production, into which we enter. Currently, a
substantial portion of our activities are conducted under production sharing contracts, or PSCs, and to a lesser extent, concessionagreements. With respect to the Azadegan Field, we have a service contract (buy-back arrangement) with the Iranian government.

30

Our Method of Accounting for Costs Related to Acquisition, Exploration, Development and Production
We incur four primary types of costs in connection with our oil and gas activities: costs of acquisition, exploration, development andproduction. Currently, we have mainly entered into two types of arrangements in connection with these activities: PSCs and concessionagreements. For the year ended March 31, 2004, approximately 90% of our net sales were attributable to sales under PSCs. Startingin the year ending March 31, 2005, the portion attributable to sales under concession agreements will increase in light of our acquisitionof JODCO.

Production Sharing Contracts
Non-recoverable Costs
Acquisition Costs
For projects under PSCs which are entirely in the exploration phase, we expense costs relating to the acquisition of rights to explore,
develop and produce as they are incurred. When we acquire rights to projects which are already in the development or production
phase, we record the acquisition expenditures or costs under “Exploration and development rights” in our consolidated balance sheet,
which is amortized under the unit-of-production method. Generally, cost recovery provisions under PSCs do not cover such
expenditures or costs.
Interest on Loans
We expense interest on loans we obtain for PSC projects.

Recoverable Costs
Exploration Costs
Our share of exploration costs incurred is capitalized under “Recoverable accounts under production sharing.” For projects which areentirely in the exploration phase prior to the obtaining of governmental approval for development, in light of the significant uncertainty
involved in the exploration activities for such projects, reserves in equal amounts to exploration costs are provided for as “Allowance
for recoverable accounts under production sharing,” which is a reserve account for potential losses from unsuccessful exploration.
Once governmental approval for development of a field in a contract area is received, reserves for exploration costs incurred thereafterin the same contract area are not provided. The previously provided allowance continues to remain unchanged in our balance sheet
until the allowance balance exceeds the remaining balance of exploration cost previously capitalized during the exploration phase
under “Recoverable accounts under production sharing,” at which point the excess of the allowance balance is reversed to income
in our income statement.
Development Costs
We record our share of all recoverable expenditures under the terms of the relevant PSC under “Recoverable accounts under
production sharing.”
Production Costs
During the production phase, operating costs incurred for production are initially included under “Recoverable accounts under production
sharing” if such costs are recoverable under the relevant PSC.
General and Administrative Expenses
General and administrative expenses are recorded under “Recoverable accounts under production sharing” if such expenses arerecoverable under the relevant PSC.

31

Cost Recovery and Production Sharing
In order to determine the cost of sale for crude oil and natural gas sold during a given period, the allocation of crude oil and natural gas
production among the host country’s government (or government entity) and contractors (including ourselves) must first be determined.
Different PSCs provide for different formulas for allocating oil and gas production among the host country’s government andcontractors. The following discussion is based on one type of PSC arrangement that applies to projects in Indonesia. Under that typeof PSC, at the end of each fiscal year, total production for that year is allocated to:(1) “first tranche petroleum,” which is a prescribed portion of total production and which is allocated between the host country’s
government and the contractors pursuant to prescribed percentages;(2) “cost recovery portion,” which is the oil and gas equivalent, determined based upon the then current unit price of crude oil and naturalgas, of (i) non-capital expenditures incurred for production during the current period and (ii) scheduled depreciation of the capital
expenditures for the current period, as calculated under the PSC, and which is allocated only to the contractors; because the oil andgas equivalent is determined based upon the then current unit price, as the unit price of crude oil and natural gas increases, the volume
of oil and gas comprising the “cost recovery portion” decreases while that of the “equity portion” (explained below) increases; andif the actual production for the year is not enough to cover the entire quantity of the oil and gas equivalent so calculated, the “costrecovery portion” will be reduced to the extent it is covered by the actual production and the quantity not so covered is carried forward
to the succeeding year in accordance with the relevant PSC; and(3) “equity portion,” which represents the residual and which is allocated between the host country’s government and the contractors
pursuant to prescribed percentages.
For purposes of our income statement, we record:• as net sales, our share of total sales relating to crude oil and natural gas production that are allocated to contractors, and• as cost of sales, a portion of “Recoverable account under production sharing” that is recovered through the allocation of our shareof the “cost recovery portion.”

Concession Agreements
Acquisition Costs
We account for acquisition costs related to projects under concession agreements in the same manner as those related to projects under
PSCs, as described above.
Exploration Costs
Our share of costs incurred for exploration is expensed as incurred. Exploration costs include our share of the costs of drilling exploratory
wells whether or not proved reserves are found at such wells.
Development Costs
Our share of costs related to tangible assets incurred during the development phase is capitalized under “Development preparationaccount,” which is included in “Other tangible fixed assets” in our balance sheet. When the project moves from the development phaseto the production phase, the balance under “Development preparation account” is reclassified as buildings and structures, wells, andother fixed assets as appropriate. We depreciate fixed assets primarily under the unit-of-production method. Such depreciation expenses
constitute cost of sales.
Production Costs
During the production phase, our share of operating costs is included in cost of sales.
General and Administrative Expenses
Our share of general and administrative expenses is expensed as incurred.

32

Factors Affecting Our Results of Operations
A number of factors affect our results of operations. They include:• crude oil prices and natural gas contract prices (and price adjustment frequency);• our crude oil and natural gas production volumes;• level of acquisition and exploration activities;• corporate taxes imposed on us outside Japan;• other trends in the international oil industry; and• movements in the exchange rate between the U.S. dollar and Japanese yen.

Crude Oil and Natural Gas Prices
While we negotiate sales prices for crude oil and condensate with customers, those prices generally take into account official prices, which
are determined by governmental authorities in the relevant oil producing regions, which fluctuate generally in line with the fluctuation ininternational crude oil prices. In Indonesia, our crude oil prices are determined based on the Indonesian Crude Price, or ICP, which isbased on price valuations by three private companies. Each type of Indonesian crude oil has its own ICP. For crude oil produced inAustralia and East Timor, our prices are determined based on the APPI (Asian Petroleum Price Index) Tapis, an internationally recognized
crude oil price. Sales contracts for crude oil are generally one-year contracts but also include spot contracts. In both cases, sales prices
are those at the time of sale and thus fluctuate.
For our natural gas, which is currently mostly produced in Indonesia, the selling price is determined based on ICP pursuant to eachsales contract. Sales contracts for natural gas are long-term contracts, typically lasting over 10 years. Typically, natural gas sales prices
move in conjunction with crude oil prices.

Our Crude Oil and Natural Gas Production Volumes
Our crude oil and natural gas production volumes depend primarily on the level of the proved and developed reserves in the projects
in which we participate, and market demand for crude oil and natural gas. The level of proved and developed reserves is affected by suchfactors as speed at which successful exploration and development moves to production and speed at which we produce crude oil andnatural gas, the extent to which we acquire additional producing reserves, our own as well as our partners’ expertise in recovery fromreserves, and expiration and extension of the terms of the contracts under which we produce crude oil and natural gas.

Level of Acquisition and Exploration Activities
Due to our policy of expensing exploration costs or, in the case of production sharing contracts, providing a full allowance for recoverable
costs incurred in the exploration phase, an increase in our level of participation in exploration phase projects has a more immediate
negative impact on our results of operations than would be the case were such costs accounted for using the successful efforts or fullcost method of accounting under U.S. GAAP.

Corporate Taxes Imposed on Us Outside Japan
We conduct all of our operations outside Japan, and most of the corporate taxes we pay are those paid overseas. With respect to ouroverseas taxes, expenses we incur in Japan are not deductible in general. Such domestic expenses include those relating toadministrative expenses at our headquarters, foreign exchange losses and the provision of various types of allowances. When suchdomestic expenses increase, pre-tax income in our consolidated statement of income decreases, but corporate taxes we pay overseas
do not decrease, thereby increasing our effective tax rate.
Historically, most of our corporate taxes are paid to Indonesia. Indonesia’s current corporate tax rate applicable to us is 48%. Indonesia
imposes corporate taxes on oil and gas operations on a PSC basis and does not permit the aggregating of expenses from different PSCs
for tax purposes. Thus, even if our exploration activities in Indonesia expand and related expenses increase with respect to one PSC,
we cannot deduct such expenses from taxable income attributable to another PSC in that country.

33

Other Trends in the International Oil Industry
Our results of operations are also affected by other trends in the international oil industry. They include:• actions by members of OPEC affecting price and production levels and related volatility in the levels of international oil prices;• political and military events in Iraq affecting the volume of future oil production in that country and the levels of international oil
prices; and• recent consolidation in the industry, including mergers creating so-called “super majors”, which is increasing competition for
exploration opportunities and operatorships.

Movements in the Exchange Rate Between the U.S. Dollar and Japanese Yen
Because our sales of crude oil and natural gas, most of our expenses and a substantial portion of our debt are denominated in U.S. dollars,
our net income, which is denominated in Japanese yen, is affected by fluctuations in the exchange rate between these currencies.
Appreciation of the Japanese yen against the U.S. dollar negatively impacts our sales and net income, while a depreciation of theJapanese yen against the U.S. dollar will have the opposite effect. However, as a substantial portion of our long-term debt is denominatedin U.S. dollars, revaluation of such long-term debt at the end of each period results in a foreign exchange gain if the Japanese yen
appreciates against the U.S. dollar, while a depreciation of the Japanese yen against the U.S. dollar will have an opposite effect.

Critical Accounting Policies and Estimates
We prepare our consolidated financial statements in conformity with Japanese GAAP. The preparation of these financial statements
requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of thefinancial statements and reported amounts of revenues and expenses during the reporting period. Actual results may differ from theseestimates, judgments and assumptions.
An accounting estimate in our consolidated financial statements is a critical accounting estimate if it requires us to make assumptions
about matters that are highly uncertain at the time the accounting estimate is made, and if the presentation of our financial condition or
results of operations are materially affected either by different estimates that we reasonably could have used in the current period, or bychanges in the accounting estimates that are reasonably likely to occur from period to period. We have identified the following criticalaccounting estimates with respect to our financial presentation:

Recoverable Accounts under Production Sharing
We capitalize expenditures made during the exploration, development and production phases under PSCs as “Recoverable accounts
under production sharing,” if they are recoverable under the relevant PSC. As discussed above, during the exploration phase prior to
obtaining governmental approval for development, a reserve in equal amounts is provided for as “Allowance for recoverable accounts
under production sharing.” Generally, this allowance continues to remain unchanged in our balance sheet until the allowance balanceexceeds the remaining balance of exploration cost previously capitalized during the exploration phase under “Recoverable accounts
under production sharing,” at which point the excess of the allowance balance is reversed to income in our income statement.

Exploration and Development Rights
Acquisition costs for exploration and development rights when such rights are acquired during the exploration phase are fully expensed
in the year such rights are acquired, and the costs when such rights are acquired during the production phase are amortized by the unitof-production method. The unit-of-production method requires a significant estimate as to the proved reserve quantities. While we believethat our proved reserve estimates are appropriate, changes in the estimates of the proved reserves may significantly affect future resultsof operations.

Investments in Exploration Companies
We have made investments in companies that are engaged in oil and gas activities, and have provided an allowance for probable losses
on such investments at an estimated amount based on the net assets of the investees. While we believe that the assessment andestimates are reasonable, future changes in the actual production volume, prices and foreign exchange rates may affect future
recoverability of the investments.

Deferred Tax Assets
We record deferred tax assets for temporary differences (including net operating loss carry-forwards) arising mainly from write-down ofinvestments in related parties and revaluation of land. Valuation allowances are provided when we believe that it is more likely than notthat assets will not be realized. Also, we take into account the effect of foreign tax credits in the calculation of valuation allowance.

34

Realization of deferred tax assets is principally dependent on our generating sufficient taxable income based on available evidence. If
future taxable income is lower than expected due to market conditions, foreign exchange rates or poor operating results, adjustments
may be required.

Retirement Benefits for Employees
The Japanese accounting standard “Accounting for Retirement Benefits” requires the recognition of retirement costs and related liabilities
based on the actuarially determined present value of retirement benefit obligations by the projected unit credit method. However, acompany is permitted to use a simplified method to account for its retirement costs and related liabilities if the number of its employees
is less than 300. For purposes of determining whether the simplified method may be used, the Japanese accounting standard requiresthat such determination be made for each retirement benefit plan separately, based on the number of employees covered by such plan.
We do not have any retirement benefit plan that individually covers more than 300 employees. Because of this, we use the simplified
method and provide an accrual for retirement benefits at the amount which would be required to be paid to all active employees as if
they voluntarily terminated their employment as of the balance sheet date. Accordingly, if our retirement costs and related liabilities had
been recognized based on the actuarially determined present value of the retirement benefit obligations by the projected unit credit
method, different retirement costs and liabilities would have been reported.

Historical Results of Operations
The following table shows certain audited consolidated income statement data derived from our audited consolidated financial
statements:(Millions of yen, except percentages)
Year ended March 31,

2002

2003

2004

Net sales
Cost of sales¥184,204
79,121100.0%
43.0¥201,533
95,997100.0%
47.6¥218,831
105,759

100.0%
48.3

Gross profit
Exploration expenses
Selling, general and administrative expenses
Depreciation and amortization

105,083
2,700
4,799
535

57.0
1.4
2.6
0.3

105,536
2,478
5,336
452

52.4
1.2
2.7
0.2

113,072
11,552
5,314
2,330

51.7
5.3
2.4
1.1

Operating income
Other income:Interest income
Gain on sales of mining rights
Equity in earnings of affiliates
Foreign exchange gain
Other

97,04952.7

97,27048.3

93,876

42.9

1,465
–
–
3,419
697

0.8
–
–
1.8
0.4

1,310
272
–
–
702

0.7
0.1
–
–
0.3

1,575
1,497
453
10,761
1,217

0.7
0.7
0.2
4.9
0.6

5,581

3.0

2,284

1.1

15,5037.1

267
15,758

0.1
8.5

689
1,503

0.3
0.7

1,817
–

0.8
–

7,132

3.9

16,234

8.1

10,057

4.6

1,777
–
840

1.0
–
0.5

5,945
2,538
2,594

2.9
1.3
1.3

746
–
1,986

0.4
–
0.9

25,77414.0

29,50314.6

14,606

6.7

76,85651,902(2,652)

41.7
28.1
(1.4)

70,051
51,953(9,814)

34.8
25.8
(4.8)

94,77360,318
(327)

43.3
27.6
(0.2)

¥ 27,606

15.0%¥ 27,912

13.8%¥ 34,782

15.9%

Other expenses:
Interest expense
Equity in losses of affiliates
Provision for allowance for recoverable
accounts under production sharing
Amortization of explorationand development rights
Foreign exchange loss
Other
Income before income taxes
and minority interests
Income taxes
Minority interests
Net income

35Comparison of the Year Ended March 31, 2004 with the Year Ended March 31, 2003
Net Sales
Net sales increased ¥17.3 billion, or 8.6%, to ¥218.8 billion for the year ended March 31, 2004 from ¥201.5 billion for the year ended
March 31, 2003. Net sales of crude oil for the year ended March 31, 2004 amounted to ¥68.8 billion, representing a decrease of ¥0.6
billion, or 0.8%, from the year before. Net sales of natural gas for the year ended March 31, 2004 amounted to ¥150.0 billion, representing
an increase of ¥17.8 billion, or 13.5%, over the year before.
Sales volume of crude oil for the year ended March 31, 2004 was 20.6 MMbbls, compared with 20.5 MMbbls for the previous year.
Although there was an increase in sales volume reflecting our acquisition of working interests in the ACG fields in Azerbaijan, this wasoffset by a decrease in the amount of production received by us for cost recovery purposes at South Natuna Sea Block B in the SouthNatuna Sea, Indonesia and a decrease in production volume at WA-10-L (Griffin Fields) in Australia. The average crude oil price for theyear ended March 31, 2004 was US$29.03 per bbl, an increase of $1.79 per bbl, or 6.6%, from US$27.24 per bbl for the previous year.
At the same time, there was a negative translation effect on net sales from the fact that the yen appreciated against the U.S. dollar, withthe average rate moving to ¥113.14 per U.S. dollar for the year ended March 31, 2004 from ¥122.26 per U.S. dollar for the previous year.
With regard to natural gas, although the yen appreciated against the U.S. dollar as mentioned above, net sales increased. In
connection with the extension of a certain sales agreement, we increased our share in the natural gas production covered by thatagreement, and this led to an increase in sales volume. Sales prices, which are linked to the crude oil price, also increased.
Cost of Sales
Cost of sales increased ¥9.8 billion, or 10.2%, to ¥105.8 billion for the year ended March 31, 2004 from ¥96.0 billion for the year ended
March 31, 2003. Although the appreciation of the yen against the U.S. dollar mentioned above had the effect of reducing cost of sales,
there were also increases in operating costs associated with increased production of natural gas, as well as increased development costs
related to an increase in the number of development wells drilled in the Mahakam contract area and the addition of cost of sales related
to the ACG fields, in which we acquired working interests.
Exploration Expenses
Exploration expenses increased by ¥9.1 billion to ¥11.6 billion for the year ended March 31, 2004 from ¥2.5 billion for the year ended
March 31, 2003. This increase was primarily due to our drilling of exploratory wells in the WA-285-P (Ichthys) block in Australia.
Selling, General and Administrative Expenses
Selling, general and administrative expenses amounted to ¥5.3 billion for the year ended March 31, 2004, almost the same as that for
the year ended March 31, 2003. During the year ended March 31, 2004, the number of employees increased and related expenses
increased by ¥0.5 billion. Also during that year, petroleum resources rent tax, or PRRT, which is levied in Australia, decreased by ¥1.2
billion. This decrease was due to a large increase in exploration costs related to the WA-285-P (Ichthys) block, which are deductible in
PRRT calculations.
Depreciation and Amortization
Depreciation and amortization increased ¥1.8 billion to ¥2.3 billion for the year ended March 31, 2004 from ¥0.5 billion for the year ended
March 31, 2003. We incurred an expense for the amortization of “Exploration and development rights” relating to INPEX Southwest
Caspian Sea, Ltd., a subsidiary which is in the production phase under a PSC, in the amount of ¥0.8 billion, and the amortization of similar
rights recorded in connection with our acquisition of INPEX Jawa, another such subsidiary, in the amount of ¥1.1 billion. Under our
accounting for PSCs, capitalized costs included in “Recoverable accounts under production sharing” are reflected in cost of goods soldat the time of recovery, and thus we do not have substantial depreciation of fixed assets in connection with such projects.
Other Income
Other income increased by ¥13.2 billion to ¥15.5 billion for the year ended March 31, 2004 from ¥2.3 billion for the year ended March
31, 2003. This increase was primarily due to a foreign exchange gain in the amount of ¥10.8 billion with respect to revaluation of our U.S.
dollar denominated long-term debt reflecting the appreciation of the Japanese yen against the U.S. dollar.
Other Expenses
Other expenses decreased by ¥14.9 billion, or 50.5%, to ¥14.6 billion for the year ended March 31, 2004 from ¥29.5 billion for the year
ended March 31, 2003. This decrease was primarily due to decreased provisions for “Allowance for recoverable accounts under
production sharing” recorded to offset costs capitalized under “Recoverable accounts under production sharing” because subsidiaries
which were in the exploration phase under PSCs incurred lower expenses than the year before. Another reason was that we did not incur
new acquisition costs of working interests in projects which were entirely in the exploration phase for the year ended March 31, 2004,
thereby reducing the amount of amortization of “Exploration and development rights.”36Income Taxes
Income taxes for the year ended March 31, 2004 increased ¥8.3 billion, or 16.1%, to ¥60.3 billion, from ¥52.0 billion for the year ended
March 31, 2003. This increase was primarily due to an increase in taxable income reflecting higher crude oil and natural gas prices. The
effective income tax rate for the year ended March 31, 2004 was 63% compared to 73% for the year ended March 31, 2003. As explainedin “Factors Affecting Our Results of Operations—Corporate Taxes Imposed Outside Japan,” the fact that most of the corporate taxes
we pay are those paid overseas and administrative expenses we incur in Japan are not deductible for such taxes results in a high effective
income tax rate. The decrease from the previous year was due to the fact that we recorded a foreign exchange gain as discussed above,
but this gain did not affect the foreign corporate taxes which constitute most of our corporate taxes.
Minority Interests
Minority interests for the year ended March 31, 2004 reflected a net loss in the amount of ¥0.3 billion, compared with a net loss in theamount of ¥9.8 billion for the year ended March 31, 2003. In the year ended March 31, 2004, INPEX North Caspian Sea, Ltd. and INPEX
Masela, Ltd., both subsidiaries in the exploration phase, incurred net losses, just as they did the previous year. In the year ended March
31, 2004, however, there was an offsetting factor in that INPEX Southwest Caspian Sea had net income.
Net Income
As a result of the foregoing factors, net income increased ¥6.9 billion, or 24.6%, to ¥34.8 billion for the year ended March 31, 2004 from
¥27.9 billion for the year ended March 31, 2003.

Comparison of the Year Ended March 31, 2003 with the Year Ended March 31, 2002
Net Sales
Net sales increased ¥17.3 billion, or 9.4%, to ¥201.5 billion in the year ended March 31, 2003 from ¥184.2 billion in the year ended March
31, 2002. Net sales of crude oil for the year ended March 31, 2003 amounted to ¥69.3 billion, representing an increase of ¥3.9 billion,
or 5.9%, from the year before. Net sales of natural gas for the year ended March 31, 2003 amounted to ¥132.2 billion, representing an
increase of ¥13.5 billion, or 11.3%, over the year before.
Sales volume of crude oil for the year ended March 31, 2003 was 20.5 MMbbls, a 10.0% decrease from 22.8 MMbbls for the previous
year. This was due, among other reasons, to a decrease in the volume of production received for cost recovery under the Mahakam PSC,
because of an increase in the crude oil price for the calculation of production for cost recovery. There was a positive impact on net sales
from the fact that the average crude oil price for the year ended March 31, 2003 was US$27.24 per bbl, an increase of $4.44 per bbl,
or 19.5%, from US$22.80 per bbl for the previous year. There was a negative translation effect on net sales from the appreciation of the
yen against the U.S. dollar, with the average rate moving to ¥122.26 per U.S. dollar for the year ended March 31, 2003 from ¥124.41
per U.S. dollar for the previous year.
With regard to natural gas, although the yen appreciated against the U.S. dollar as mentioned above, net sales were positively affectedby an increase in sales price, which is linked with crude oil price, as well as by the commencement of full-scale production at South NatunaSea Block B.
Cost of Sales
Cost of sales increased ¥16.9 billion, or 21.3%, to ¥96.0 billion in the year ended March 31, 2003 from ¥79.1 billion in the year ended
March 31, 2002. Although the appreciation of the yen against the U.S. dollar mentioned above had a negative effect on cost of sales,
there were increases in operating costs associated with increased production of natural gas, as well as increased development costs
related to an increase in the number of drilling development wells at the Mahakam contract area and to the commencement of full-scale
production at South Natuna Sea Block B.
Exploration Expenses
Exploration expenses decreased by ¥0.2 billion, or 8.2%, to ¥2.5 billion for the year ended March 31, 2003 from ¥2.7 billion for the year
ended March 31, 2002. This reflected the net result of an increase in activities in exploration areas in Australia where we, through INPEX
Alpha, Ltd., have a working interest, and a decrease in such activities at the WA-285-P (Ichthys) block, also in Australia.
Selling, General and Administrative Expenses
Selling, general and administrative expenses increased by ¥0.5 billion, or 11.2%, to ¥5.3 billion in the year ended March 31, 2003 from
¥4.8 billion in the year ended March 31, 2002. The primary reason for this increase was an increase in PRRT levied by Australia, reflecting
an increase in the amount subject to that tax due to a decrease in production-related expenditures and exploration costs that are
deductible from that tax.

37

Depreciation and Amortization
Depreciation and amortization for the year ended March 31, 2003 amounted to ¥0.5 billion, remaining relatively unchanged from theyear before.
Other Income
Other income decreased by ¥3.3 billion, or 59.1%, to ¥2.3 billion for the year ended March 31, 2003 from ¥5.6 billion for the year ended
March 31, 2002. This decrease was primarily due to the foreign exchange gain of ¥3.4 billion recognized in 2002, which was notrecognized in 2003 with the appreciation of the yen against the dollar.
Other Expenses
Other expenses increased by ¥3.7 billion, or 14.5%, to ¥29.5 billion for the year ended March 31, 2003 from ¥25.8 billion for the year
ended March 31, 2002. Large increases in both the amortization of “Exploration and development rights” and our provision for “Allowance
for receivable accounts under production sharing,” both associated with our acquiring an additional working interest in the Kashagan
Field in the North Caspian Sea and increasing exploration activities, more than offset a decrease of ¥14.2 billion in our equity in losses
of affiliates. The large amount of equity in losses in affiliates in the year ended March 31, 2002 was attributable to the loss incurred at
the Tangguh Project in Indonesia.
Income Taxes
Income taxes for the year ended March 31, 2003 amounted to ¥52.0 billion, largely unchanged from the year ended March 31, 2002.
The effective income tax rate for the year ended March 31, 2003 was 73%, compared with 68% for the previous year. The increase in
the effective income tax rate was due to the fact that we recorded a foreign exchange loss as discussed above, but this loss was nota deductible item for purposes of foreign corporate taxes which constitute most of our corporate taxes.
Minority Interests
Minority interests for the year ended March 31, 2003 reflected a net loss in the amount of ¥9.8 billion, compared with a net loss in theamount of ¥2.7 billion for the year ended March 31, 2002. In the year ended March 31, 2003, INPEX North Caspian Sea, Ltd. and INPEX
Masela, Ltd., both subsidiaries in the exploration phase, incurred net losses, reflecting the incurrence of substantial exploration expenses.
Net Income
As a result of the foregoing factors net income increased ¥0.3 billion, or 1.1%, to ¥27.9 billion in the year ended March 31, 2003 from
¥27.6 billion in the year ended March 31, 2002.

Analysis of Recoverable Accounts under Production Sharing
As discussed above, with respect to projects under PSCs, our share of costs arising during the exploration, development and production
phases are capitalized under “Recoverable accounts under production sharing.” The following table shows changes in the balance of“Recoverable accounts under production sharing” during the year ended March 31, 2002 through the year ended March 31, 2004:(Millions of yen)
Year ended March 31,
Recoverable accounts under production sharing

2002

2003

2004

Balance at beginning of period
Add: Exploration costs
Development costs
Operating expenses
Other
Less: Cost recovery—capital expenditures
Cost recovery—non-capital expenditures
Other¥ 84,457
9,684
30,46824,911–
12,716
39,58419¥ 97,201
15,552
57,63428,654
1,948
14,21249,476860¥136,441
13,74384,84834,242
30,692
21,74460,0089,446

Balance at end of period¥ 97,201¥136,441¥208,768

Allowance for recoverable accounts under production sharing at end of period¥(27,127)¥ (42,838)¥ (44,676)“Cost recovery—non-capital expenditures” are generally larger than “operating expenses” because some of the exploration costs anddevelopment costs that are recoverable in the fiscal year when such costs are incurred are included in addition to operating expenses.

38Comparison of the Year Ended March 31, 2004 with the Year Ended March 31, 2003
Compared with the year ended March 31, 2003, exploration costs for the year ended March 31, 2004 increased at our project in the
North Caspian Sea, but overall such costs decreased due to the fact that there were no exploratory drilling activities at the Masela blockin Indonesia. Development costs increased substantially, reflecting the fact that they now included development costs relating to our
project at the ACG fields. Another reason for the increase was the increase in development drilling activities at the Mahakam contract
area. Operating expenses increased due to increases at the Mahakam contract area and South Natuna Sea Block B, and reflecting theaddition of operating activities at the ACG fields during the period. Other recoverable costs increased, reflecting the increase in“Recoverable accounts under production sharing” due to the acquisition of the ACG fields.
Cost recovery during the year ended March 31, 2004 occurred primarily at the Mahakam contract area, South Natuna Sea Block B
and the ACG fields. The increase in cost recovery from the previous year reflected the addition of the ACG fields and also increased
expenditures in those projects. Most of the reductions under “Less: Other” in the year ended March 31, 2004 related to reductions in
the balance of recoverable accounts under production sharing with respect to fields being closed.

Comparison of the Year Ended March 31, 2003 with the Year Ended March 31, 2002
Compared with the year ended March 31, 2002, exploration costs for the year ended March 31, 2003 increased, reflecting exploratory
activities at our project in the North Caspian Sea and at the Masela block. Development costs also increased, reflecting increased
development activities at South Natuna Sea Block B and the increased development drilling at the Mahakam contract area. Operating
expenses increased, mainly at the Mahakam contract area. Other costs reflect the investment in additional rights for the project in the
North Caspian Sea, which contributed to an increase in “Recoverable accounts under production sharing.”
Cost recovery during the year ended March 31, 2003 occurred primarily at Mahakam and Natuna, and the increase from the previous
year reflected increased expenditures in those projects.

Liquidity and Capital Resources
Our Funding Sources
Our primary sources of funding are cash generated by operating activities, long-term borrowings, and equity investments in our
subsidiaries by JOGMEC. We expect that, over the next several years, our acquisition, exploration and development activities, including
the development of the ACG fields in Southwest Caspian Sea, the Azadegan field in Iran and the Kashagan field in the North CaspianSea, will significantly increase, thereby requiring substantial expenditures. Under appropriate circumstances, in addition to obtaining
funds from the sources described above, we may seek additional funding through any of, or a combination of, issuances of debt andequity securities in domestic or international capital markets, project financing on a non-recourse basis, and the farming out of working
interests in projects.
Our policy is to maintain sufficient cash at hand at any given time to fund expenditures for existing and new crude oil and natural gas
projects in a timely manner. For this purpose, our cash management policy is to invest excess cash in low-risk and liquid financial
instruments, such as Japanese government bonds.
We fund oil and gas projects which are in the exploration phase with funds generated by operations or equity investments from JNOC
(going forward, we will obtain such equity investments from JOGMEC), and projects which are in the development phase with funds
generated by operations and/or long-term loans. We finance our acquisitions of working interests in oil and gas projects with funds
generated by operations as well as equity investments from JNOC (going forward, we will obtain such equity investments from JOGMEC)
and/or long-term loans. JNOC has made a substantial portion of such equity investments, and JBIC and Japanese commercial banks
have been providing such long-term loans, which are partly guaranteed by JNOC (going forward, we will obtain such guarantees from
JOGMEC). JBIC, a Japanese governmental financial institution, provides financing for development of natural resources overseas,among other things. JBIC currently provides up to 70% of the aggregate amount of debt for projects which have agreed to supply crude
oil or natural gas to Japan in an energy crisis. Currently, the Japanese commercial banks that provide loans to us are Mizuho Corporate
Bank, Ltd. and The Bank of Tokyo-Mitsubishi, Ltd. The aggregate outstanding principal amount of our long-term debt was ¥169.4 billion
as of March 31, 2004. JNOC has guaranteed ¥56.1 billion of that aggregate principal amount.
JOGMEC has succeeded to JNOC’s role of providing financial assistance to oil and gas projects of Japanese companies. In responseto criticism that taxpayer money previously has not been used by JNOC as effectively as possible to promote Japan’s energy supply,
JOGMEC has stated that it intends to assess more vigorously the economic viability of proposed projects when considering requests

39

for financial assistance. Going forward, JOGMEC’s financial assistance represents a useful capital resource for us, although it is too early
to determine whether its tightened policy on project assessment will have any material impact on our ability to fund our projects.
A portion of JBIC’s loans to us is guaranteed by JNOC (as mentioned above, going forward, we will obtain guarantees from JOGMEC).
As for the remaining portion of such loans, in order to enhance the funding availability for our future development activities, we are required
to maintain for JBIC cash collateral generally equivalent to six months’ debt service in a reserve account established at Mizuho Corporate
Bank. The balance of that reserve account was ¥8.6 billion as of September 30, 2004. JBIC is expected to provide us loans under suchcollateral for certain of our future development activities, and will maintain such loans without any further collateral, for so long as ourfinancial condition does not significantly deteriorate, for example when our gross profit becomes negative in two consecutive periods.
We believe that we have sufficient funding sources for our planned expenditures and investments, such as our future cash flows fromoperating activities, equity investments by JOGMEC, borrowings from JBIC and/or commercial banks supported by JOGMEC’s
guarantee, issuances of debentures, and equity financing under appropriate circumstances.

Our Expenditures for Crude Oil and Natural Gas Projects
Although under our accounting for PSCs all recoverable costs are capitalized in “Recoverable costs under production sharing” regardlessof the nature of the underlying activities and then expensed as cost recovery in accordance with the relevant PSC, we do look at the
breakdown of our expenses among exploration expenses, development expenses and operating expenses.
The following information has been prepared based on available data in the reports provided by operators. The definition of each item
is as follows:• Acquisition of properties includes acquisition cost of mining rights, exploration and development rights, and signing bonus as well as
the increase in recoverable accounts under production sharing due to acquisition.
• Exploration costs include exploration drilling, geological and geophysical studies. If the project (contract area) is entirely in the
exploration phase, general and administrative costs, such as personnel costs, office running costs in the country where the relevant
project is conducted, are included in this category.
• Development costs include development drilling and production facilities.
• Operating expenses include well operations, transportation, maintenance, and supervision of production activities. General andadministrative expenses in the project (contract area) where there is a producing field and/or a field of which governmental approvalfor development has been received.
Our definition of exploration and development expenditures and the basis of preparation of the following table are different from thoserequired under Statement of Financial Accounting Standard No. 69, “Disclosure about Oil and Gas Producing Activities,” or SFAS 69.
Such differences include, but are not limited to, the following:• Our expenditures reflected in the table are on a cash-call basis as to joint ventures for PSCs where we are not an operator, while SFAS
69 requires that expenditures be recorded on an accrual basis.
• We prepared the table based on definitions in the reports from operators. These definitions may not be consistent with that of
SFAS 69.
• SFAS 69 requires that general and administrative costs which are not directly related to exploration and development activities be
excluded from exploration and development expenditures. However, general and administrative costs are not necessarily excluded
from those expenditures.

40

The table below shows our expenditures for each of the three years ended March 31, 2004:(Millions of yen, except percentages)
Year ended March 31,

2002

2003

2004

Exploration
Development¥12,383
38,151

15.7%
48.3¥ 18,030
67,161

15.3%
57.2¥ 25,296
92,348

16.3%
59.4

Subtotal
Operating expenses

50,53428,39364.0
36.0

85,191
32,24972.5
27.5

117,644
37,685

75.7
24.3¥78,927100.0%¥117,440

100.0%¥155,329

100.0%Total

The table below shows our exploration and development expenditures for each of the three years ended March 31, 2004 bygeographical region:(Millions of yen, except percentages)
Year ended March 31,

Asia and Oceania
Middle East
Caspian Sea area and others
Total

2002

2003

2004

¥46,085
1,116
3,333

91.2%
2.2
6.6

¥76,472
1,333
7,386

89.7%
1.6
8.7

¥ 85,286
1,106
31,252

72.5%
0.9
26.6

¥50,534

100.0%¥85,191

100.0%¥117,644

100.0%The table below shows our operating expenses for each of the three years ended March 31, 2004 by geographical region:(Millions of yen, except percentages)
Year ended March 31,

Asia and Oceania
Middle East
Caspian Sea area and others
Total

2002

2003

2004

¥26,469
1,924
–

93.2%
6.8
–

¥30,309
1,940
–

94.0%
6.0
–

¥34,391
2,019
1,275

91.3%
5.3
3.4

¥28,393

100.0%¥32,249

100.0%¥37,685

100.0%

Our expenditures increased by ¥37.9 billion, or 32%, to ¥155.3 billion in the year ended March 31, 2004 from ¥117.4 billion in theyear ended March 31, 2003. This was primarily due to exploratory drilling activities at the WA-285-P (Ichthys) block in Australia, increased
development drilling activities at the Mahakam contract area in Indonesia and the addition of development activities at the ACG fields.
Our expenditures increased by ¥38.5 billion, or 49%, to ¥117.4 billion in the year ended March 31, 2003 from ¥78.9 billion in the year
ended March 31, 2002. This was primarily due to exploratory drilling activities at the Masela block in Indonesia and North Caspian Sea
and the start of full-time development activities at South Natuna Sea Block B in Indonesia.

41

Our Expenditures for Acquisitions of Crude Oil and Natural Gas Projects
The table below shows our expenditures for acquisitions of oil and gas properties for each of the three years ended March 31, 2004 bygeographical region:(Millions of yen, except percentages)
Year ended March 31,

Asia and Oceania
Middle East
Caspian Sea area and others
Total

2002

2003

2004

¥1,777––100.0%
–
–

¥ 336
–
7,557

4.3%
–
95.7

¥

3,252
44
164,496

2.0%
0.0
98.0

¥1,777100.0%¥7,893100.0%¥167,792

100.0%

Our acquisition cost increased by ¥159.9 billion to ¥167.8 billion in the year ended March 31, 2004 from ¥7.9 billion in the year ended
March 31, 2003. This was primarily due to the acquisition of the ACG fields. Our expenditures increased by ¥6.1 billion to ¥7.9 billion
in the year ended March 31, 2003 from ¥1.8 billion in the year ended March 31, 2002. This was primarily due to the acquisition of anadditional working interest in the North Caspian Sea area.

Maturities of Long-term Debt
The following table summarizes the maturities of our outstanding long-term debt as of March 31, 2004:(Millions of yen and U.S. dollars)Long-term debt denominated inYear ending March 31,

U.S. dollars

2005
2006
2007
2008
2009 and thereafter

$

Total

Yen

Total yen equivalent

1.1
34.9
121.1
154.3
1,064.6¥––––
24,066

¥

118
3,688
12,793
16,300136,526$1,376.0¥24,066¥169,425

Although we have a significant amount of long-term debt from JBIC and other financial institutions and the amount of such debt is
expected to increase going forward, we do not expect to require any significant amount of funds to be applied for the repayment of suchdebt in the near future as such loans are tied to projects and the repayment schedule takes into account the expected schedule ofproduction from the relevant projects.

42Historical Cash FlowsThe following table summarizes our historical cash flows for the periods presented:(Millions of yen)
Year ending March 31,

Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by financing activities
Cash and cash equivalents at the end of period

2002

2003

2004

¥ 51,827(39,624)
9,444
49,775¥ 51,282(40,533)
21,23878,414¥ 44,464(218,121)
151,120
54,582

Cash Provided by Operating Activities
Cash provided by operating activities decreased ¥6.8 billion to ¥44.5 billion in the year ended March 31, 2004 from ¥51.3 billion in theyear ended March 31, 2003. This decrease was primarily due to an increase in exploration costs at the WA-285-P (Ichthys) block whichmore than offset an increase in our income reflecting increased crude oil prices.
Cash provided by operating activities decreased by ¥0.5 billion to ¥51.3 billion in the year ended March 31, 2003 from ¥51.8 billion
in the year ended March 31, 2002. Although increased crude oil prices resulted in increased income, it was slightly more than offset bycash provided to exploratory drilling activities at Masela block and North Caspian Sea.
We had a working capital surplus of ¥81.4 billion as of March 31, 2002, ¥91.8 billion as of March 31, 2003 and ¥78.1 billion as ofMarch 31, 2004.

Cash Used in Investing Activities
Cash used in investing activities increased ¥177.6 billion to ¥218.1 billion in the year ended March 31, 2004 from ¥40.5 billion in the year
ended March 31, 2003. This increase was primarily due to our acquisition of a 10% interest in the ACG fields.
Cash used in investing activities increased ¥0.9 billion to ¥40.5 billion in the year ended March 31, 2003 from ¥39.6 billion in the year
ended March 31, 2002. Our capital expenditures included in recoverable accounts under production sharing agreements increased from
¥19.1 billion in the year ended March 31, 2002 to ¥39.4 billion in the year ended March 31, 2003 due in part to expanded development
at South Natuna Sea Block B but this increase was largely offset by the net proceeds from sales of marketable and investment securities.

Cash Provided by Financing Activities
Cash provided by financing activities increased ¥129.9 billion to ¥151.1 billion in the year ended March 31, 2004 from ¥21.2 billion in
the year ended March 31, 2003. This increase was primarily due to an increase in long-term debt and an increase in minority investments
associated with our acquisition of rights in the ACG fields.
Cash provided by financing activities increased ¥11.8 billion to ¥21.2 billion in the year ended March 31, 2003 from ¥9.4 billion in theyear ended March 31, 2002. The largest factor in the increase was an increase of ¥7.2 billion in proceeds from the issuance of minority
interests caused by the additional acquisition of a working interest in the North Caspian Sea and exploration activities there and at theMasela block.

43

Market Risks
Our primary market risk exposures are to fluctuations in oil and gas prices, exchange rates and interest rates.

Commodity Price Risk
We are exposed to fluctuations in prices of crude oil and natural gas, which are commodities whose prices are determined by reference
to international market prices. International oil and gas prices are volatile and are influenced by global as well as regional supply anddemand conditions. This volatility has a significant effect on our net sales and net income.
The effect of price changes on our sales and net income is highly complex. For example:• natural gas sales prices move together with crude oil prices; however, movements in sales prices of natural gas are not directly
proportional to those of crude oil prices;• since sales and net income are determined by the prices as of the dates on which sales are recorded, the actual transaction pricedoes not match the average price of the period; and• sales and net income are affected by not only crude oil prices but also the cost recovery amount of the period under ourcontractual arrangements.
We currently do not hedge against market risk resulting from fluctuations in oil and gas prices. We are considering purchasing floor
options to hedge against decreases of crude oil prices beyond certain levels, taking into account the balance between the cost of such
options and the effectiveness of such hedging, in order to secure repayment of loans from third parties for our projects if crude oil prices
were to decrease substantially.
For your information, the following analysis indicates the impact on our net income of changes in crude oil prices. The estimatedamount generated from the analysis is presented only for analytical purposes. Since various market conditions and unforeseen situations
that may arise due to our investment behavior (which may be directed by our strategic considerations) could change our sensitivity, you
should not interpret the calculated amount shown below to be predictive of actual future events or results.
We have based our analysis of how movements in crude oil prices might have affected our net income on financial information derived
from our consolidated financial statements as of and for the year ended March 31, 2004.
If the crude oil price had changed by US$ 1 per bbl, the effect on our net income for the year ended March 31, 2004 would have been
approximately ¥2 billion.
In connection with this analysis, you should note the following:• The amount indicated by the analysis for the year ended March 31, 2004 shows only the result of a simulation on the past that is notextendable to the future. The sales volume, costs, investments and other variables are discrete and different from the previous year.
Therefore, the analysis for the year ending March 31, 2005 may differ from the impact shown above.
• Had crude oil prices been significantly different from the actual prices for the year ended March 31, 2004, the deviation would have
had less of an impact on our net income than may be suggested by the amount indicated above. This is because the gas sales
contracts of our natural gas projects have price mechanisms that moderate the effect of fluctuations of crude oil prices after thefluctuations exceed a certain level.

44Foreign Exchange Risk
Our foreign exchange exposure gives rise to market risk associated with exchange rate movements. An appreciation of the Japanese
yen against the U.S. dollar has a negative effect on sales and net income, while the same appreciation has a positive effect on a substantial
portion of our long-term debt, which is denominated in U.S. dollars. Moreover, foreign exchange gain/loss resulting from sales of crude
oil and natural gas is determined by the exchange rates as of the dates on which the sales are recorded during the period, while foreignexchange gain/loss resulting from revaluation of our debt denominated in U.S. dollars is determined by the difference of the exchange
rates between the beginning date of the period or borrowing date and the ending date of the period. As a result, the sensitivity of thelatter does not reflect the average exchange rate of the period. These positive and negative effects cancel out each other. For the year
ended March 31, 2004, the effect of a ¥1 change per US$1 on net income would have been roughly neutral under our total foreignexchange risk exposure. We do not currently hedge against market risk resulting from foreign exchange fluctuations, but may engage
in such activities under appropriate circumstances in the future.

Interest Rate Risk
We are exposed to interest rate risks arising from our long-term debt. Upward fluctuations in interest rates increase the cost of new debt
and the interest cost of outstanding floating rate borrowings. A substantial portion of our long-term debt has floating interest rates thatare determined by reference to the 6-month London Interbank Offered Rate. We have no short-term debt. Currently, we have no plans
to use interest rate swaps or other derivative products to hedge against our interest rate exposure, but may engage in such transactions
under appropriate circumstances. If we face a situation where interest rates rapidly increase, we may consider entering into transactions
such as interest rate swaps or cap options on interest rates to hedge against such increase with respect to our borrowings, taking into
account the cost of such transactions and the prospect of future movements of interest rates.

45

Consolidated Balance Sheets
INPEX CORPORATION and Subsidiaries
As of March 31, 2003 and 2004

Millions of yen

Thousands of
U.S. dollars(Note 3)

2003

2004

2004

¥ 78,414
15,78920,865
1,373
54
2,610
(28)

¥ 54,582
19,265
18,979893
43
13,212(22)$ 516,728
182,382
179,674
8,454
407
125,078(208)

119,077

106,952

1,012,515

8,123
7,230
15,9104,014
15,9989,160
8,508
15,896
4,002
20,722

86,71880,545150,488
37,887
196,175

51,275(21,405)

58,288(23,146)

551,813(219,123)

29,87035,142332,690

–
811
3,036
38

134,367
651
2,868
23

1,272,054
6,163
27,151
218

3,885

137,9091,305,586

96,174(7,369)79,371(5,710)751,406(54,057)

Recoverable accounts under production sharing
Less allowance for recoverable accounts under production sharing

88,805
136,441(42,838)

73,661
208,768(44,676)

697,349
1,976,408(422,948)

Long-term loans receivable
Deferred tax assets (Note 6)
Other investments
Less allowance for doubtful accounts

93,603
54
1,498
2,085
(130)

164,092
52
4,205
3,615
(330)

1,553,460
492
39,80934,223(3,124)

185,915

245,295

2,322,209¥338,747¥525,298$4,973,000

ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable—tradeMarketable securities (Note 4)Inventories
Deferred tax assets (Note 6)
Other current assets
Less allowance for doubtful accounts
Tangible fixed assets:
Buildings and structures
Wells
Machinery, equipment, and vehicles
Land
Other
Less accumulated depreciation and amortization
Intangible assets:
Exploration and development rights
Mining rights
Goodwill
Other
Investments and other assets:
Investment securities (Note 4)Less allowance for investments in exploration

Total assets
See accompanying notes to consolidated financial statements.

46

LIABILITIES AND SHAREHOLDERS’ EQUITYCurrent liabilities:
Accounts payable
Current portion of long-term debt (Note 5)
Income taxes payable (Note 6)
Other current liabilities
Long-term liabilities:
Long-term debt (Note 5)
Deferred tax liabilities (Note 6)
Accrued employees’ retirement benefits
Accrued officers’ retirement benefits
Other

Total liabilities

Minority interests in consolidated subsidiaries

Millions of yen

Thousands of
U.S. dollars(Note 3)

2004

2004

2003

¥

3,539
132
8,293
15,311

¥

3,273
118
8,372
17,132$30,985
1,117
79,258
162,189

27,27528,895273,549

46,865
2,694
792
645
6,012

169,307
10,314
784
512
4,493

1,602,831
97,6437,422
4,847
42,53557,008

185,410

1,755,278

84,283

214,305

2,028,827

894

32,879311,266

Shareholders’ equity (Note 7):
Common stock, without par value:
Authorized —600,000 shares
Issued and outstanding — 589,200 shares
Retained earnings
Unrealized holding gain on securities
Translation adjustments

29,46029,460278,898

220,853410
2,847

249,628
154(1,128)2,363,230
1,458(10,679)

Total shareholders’ equity

253,570

278,1142,632,907¥338,747¥525,298$4,973,000

Contingent liabilities (Note 13)

Total liabilities and shareholders’ equity

47

Consolidated Statements of Income
INPEX CORPORATION and Subsidiaries
For the years ended March 31, 2002, 2003 and 2004

Millions of yen

Thousands of
U.S. dollars(Note 3)

2002

2003

2004

2004

Net sales
Cost of sales¥184,204
79,121¥201,533
95,997¥218,831
105,759$2,071,675
1,001,221

Gross profit
Exploration expenses
Selling, general and administrative expenses (Note 10)
Depreciation and amortization

105,083
2,700
4,799
535

105,536
2,478
5,336
452

113,072
11,5525,314
2,330

1,070,454
109,363
50,30822,058Operating income
Other income:Interest income
Foreign exchange gain
Gain on sales of mining rights
Equity in earnings of affiliates
Other

97,04997,27093,876

888,725

1,465
3,419
–
–
697

1,310
–
272
–
702

1,575
10,761
1,497
453
1,217

14,911
101,874
14,172
4,289
11,521

5,581

2,284

15,503

146,767267
36
15,758

689
26
1,503

1,817
–
–

17,202
–
–

7,132
1,777
–
804

16,234
5,945
2,538
2,568

10,057746–
1,986

95,2107,062–
18,801

25,77429,503

14,606138,275

76,85670,051

94,773

897,217

Income taxes (Note 6):
Current
Deferred

51,093809

51,143810

55,081
5,237

521,452
49,579Minority interests

51,902(2,652)

51,953(9,814)60,318(327)

571,031(3,096)

Net income (Note 8)¥ 27,606¥ 27,912¥ 34,782$ 329,282

Other expenses:
Interest expense
Loss on devaluation of investment securities
Equity in losses of affiliates
Provision for allowance for recoverable accounts
under production sharing
Amortization of exploration and development rights
Foreign exchange loss
Other

Income before income taxes and minority interests

See accompanying notes to consolidated financial statements.

48

Consolidated Statements of Shareholders’ Equity
INPEX CORPORATION and Subsidiaries
For the years ended March 31, 2002, 2003 and 2004

Millions of yen
Commonstock

Retainedearnings

Balance at March 31, 2001
Net income
Cash dividends paid
Bonuses to directors and statutory auditors
Unrealized holding gain on securities
Translation adjustments¥29,460–––––¥178,840
27,606(7,365)(124)––

Balance at March 31, 2002
Net income
Cash dividends paid
Bonuses to directors and statutory auditors
Unrealized holding gain on securities
Translation adjustments

29,460–––––198,957
27,912(5,892)(124)––

Balance at March 31, 2003
Net income
Cash dividends paid
Bonuses to directors and statutory auditors
Unrealized holding loss on securities
Translation adjustments

29,460–––––

Balance at March 31, 2004

¥29,460

Unrealized
holding gain
on securities

¥

–
–
–
–
730
–

Translation
adjustments

¥

Total
shareholders’equity

–
–
–
–
–
1,678

¥208,300
27,606(7,365)
(124)
730
1,678

730
–
–
–
(320)
–

1,678
–
–
–
–
1,169

230,825
27,912(5,892)
(124)
(320)
1,169

220,853
34,782(5,892)
(115)
–
–

410
–
–
–
(256)
–

2,847
–
–
–
–
(3,975)

253,570
34,782(5,892)(115)(256)(3,975)¥249,628¥ 154¥(1,128)¥278,114

Commonstock

Retainedearnings

Unrealized
holding gain
on securities

Translation
adjustments

Totalshareholders’equityBalance at March 31, 2003
$278,898
Net income–
Cash dividends paid–
Bonuses to directors and statutory auditors–
Unrealized holding gain on securities–
Translation adjustments–$2,090,817
329,282(55,780)(1,089)––$ 3,881–––(2,423)–$ 26,953––––(37,632)$2,400,549
329,282(55,780)(1,089)(2,423)(37,632)

Balance at March 31, 2004

$2,363,230$ 1,458$(10,679)$2,632,907

Thousands of U.S. dollars (Note 3)$278,898

See accompanying notes to consolidated financial statements.

49

Consolidated Statements of Cash Flows
INPEX CORPORATION and Subsidiaries
For the years ended March 31, 2002, 2003 and 2004

2002

Cash flows from operating activities:
Income before income taxes and minority interests¥ 76,856
Depreciation and amortization
2,710(Gain) loss on sales of tangible fixed assets
32
Amortization of goodwill
169
Provision for allowance for doubtful accounts
4
Provision for allowance for recoverable accounts under production sharing
7,158(Reversal of) provision for accrued retirement benefits
68Interest and dividend income(1,594)
Interest expense
266
Gain on sales of marketable securities(4)
Loss on sales of marketable securities–
Loss on devaluation of investment securities
35
Foreign exchange (gain) loss
(834)
Equity in losses of affiliates
15,758Gain on sales of mining rights–
Gain on sales of investment securities(31)
Loss on sales of investment securities–
Accounts receivable(600)
Recovery of recoverable accounts under production sharing (capital expenditures)
12,716
Recoverable accounts under production sharing (operating expenditures)(6,307)
Inventories(344)
Accounts payable
1,016
Other receivables(1,001)
Accrued expenses
1,809
Long-term accrued expenses(1,007)
Advance payments received(613)
Bonuses to directors and statutory auditors
(124)
Other
(951)
Subtotal
105,187
Interest and dividends received
2,562Interest paid
(253)
Income taxes paid
(55,669)
Net cash provided by operating activities
51,827
Cash flows from investing activities:
Decrease in short-term investments
260
Purchases of marketable securities(41,469)
Proceeds from sales of marketable securities
83,083Purchases of tangible fixed assets(8,348)Proceeds from sales of tangible fixed assets–
Purchases of intangible assets(15)
Purchases of investment securities(56,878)
Proceeds from sales of investment securities
1,538
Investment in recoverable accounts under production sharing(19,153)
Additional acquisition of shares of consolidated subsidiary–
Decrease in short-term loans receivable
222
Long-term loan made–Collection of long-term loans receivable
5
Purchase of mining rights (Note 14)–
Proceeds from sales of mining rights (Note 14)–
Proceeds from purchase of subsidiaries’ stock resulting inchanges in the scope of consolidation (Note 14)
–
Other
1,131
Net cash used in investing activities(39,624)
Cash flows from financing activities:
Proceeds from long-term debt
14,256
Repayment of long-term debt
(116)
Proceeds from minority interests for additional shares
2,669
Cash dividends paid
(7,365)
Restricted cash deposited
–
Other
–
Net cash provided by financing activities
9,444
Effect of exchange rate changes on cash and cash equivalents
999
Net increase (decrease) in cash and cash equivalents
22,646
Cash and cash equivalents at beginning of year
27,129Cash and cash equivalents at end of year
¥ 49,775
See accompanying notes to consolidated financial statements.

50

Millions of yen

Thousands of
U.S. dollars(Note 3)

2003

2004

2004

¥ 70,051
2,464
(15)
169
14
16,356163(1,405)
690
(17)
2
26
1,977
1,503
–
(242)
64
(2,259)14,212(14,685)
(567)
(459)
(1,555)
1,829
1,410
4,795
(124)
1,871
96,2682,397(718)(46,665)
51,282¥ 94,773
4,049
58
169
123
11,284(141)(1,711)
1,816–––(11,980)(452)(1,497)(63)–(2,521)
21,744(13,828)
480
(266)
(389)
541
(741)
(2,160)(114)(826)
98,3482,471(1,322)(55,033)
44,46490(2,424)
38,691(8,916)237(5)(59,676)
29,864(39,412)
–
–
(8)
4
–
–

–
–
20,707(8,920)22–(19,661)
3,685(58,997)
(633)
1
–
2
(163,511)
3,052

–
–
196,033(84,446)
208–(186,130)
34,886(558,525)(5,992)10–
19(1,547,960)
28,893–
1,022(40,533)

3,992
2,140
(218,121)

37,792
20,259(2,064,953)

17,381(148)
9,901(5,892)–(4)
21,238(3,348)28,63949,775¥ 78,414

136,028(195)
30,320(5,892)(9,140)(1)
151,120(1,295)(23,832)
78,414¥ 54,582

1,287,778(1,846)
287,039(55,780)(86,528)(9)1,430,654(12,260)(225,618)
742,346$ 516,728$

897,217
38,332
549
1,600
1,164
106,826(1,335)(16,198)
17,192–––(113,415)(4,279)(14,172)(596)–(23,866)
205,851(130,910)
4,544(2,518)(3,683)
5,121(7,015)(20,449)(1,079)(7,820)931,061
23,393(12,515)(520,998)
420,941

Notes to Consolidated Financial Statements
INPEX CORPORATION and Subsidiaries

1. BASIS OF PRESENTATIONINPEX CORPORATION (the “Company”) is primarily engaged in the exploration, development and production of natural gas and crudeoil, and is 50% owned by Japan National Oil Corporation.
The Company and its domestic subsidiaries maintain their accounting records and prepare their financial statements in accordancewith accounting principles generally accepted in Japan, and its overseas subsidiaries maintain their books of account in conformity withthose of their countries of domicile. The accompanying consolidated financial statements have been prepared in accordance withaccounting principles generally accepted in Japan, which may differ in certain material respects from accounting principles generally
accepted in the United States of America, and are compiled from the consolidated financial statements prepared by the Company as
required by the Securities and Exchange Law of Japan.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES(a) Principles of consolidation and accounting for investments in unconsolidated subsidiaries and affiliates
The accompanying consolidated financial statements include the accounts of the Company and companies controlled directly or
indirectly by the Company. Companies over which the Company exercises significant influence in terms of their operating and financial
policies are included in the consolidated financial statements on an equity basis. All significant intercompany balances and transactions
are eliminated in consolidation.
Most of the Company’s subsidiaries are consolidated on the basis of fiscal periods ending December 31, which differ from that of
the Company; however, the significant effect of the difference in fiscal periods has been properly adjusted in consolidation.
The excess of cost over underlying net assets at fair value as of their dates of acquisition is amortized over a period of less than 20
years on a straight-line basis.
(b) Cash equivalents
All highly liquid investments with a maturity of three months or less when purchased are considered cash equivalents.
(c) Foreign currency translation
Monetary assets and liabilities denominated in foreign currencies are translated into yen at the exchange rates prevailing at the balance
sheet date. All revenues and expenses associated with foreign currencies are translated at the rates of exchange prevailing when suchtransactions were made. The resulting exchange gain or loss is credited or charged to income.
The revenue and expense accounts of the overseas subsidiaries are translated into yen at the rates of exchange in effect at the balance
sheet date. Except for the components of shareholders’ equity, the balance sheet accounts are also translated into yen at the rates of
exchange in effect at the balance sheet date. The components of shareholders’ equity are translated at their historical exchange rates.
Translation adjustments are presented as components of shareholders’ equity and minority interests in the accompanying consolidated
financial statements.
(d) Securities
In general, securities are classified into three categories: trading, held-to-maturity or other securities. Securities held by the Company andits subsidiaries are all classified as other securities. Other securities with a determinable market value are stated at fair value with any changes
in unrealized holding gain or loss, net of the applicable income taxes, included directly in shareholders’ equity. Other securities without adeterminable market value are stated at cost. Cost of securities sold is determined by the moving average method.
(e) Inventories
Inventories are mainly stated at cost determined by the average method.
(f) Allowance for doubtful accounts
The allowance for doubtful receivables is provided at an amount determined based on the historical experience of bad debt with respect
to ordinary receivables, plus an estimate of uncollectible amounts determined by reference to specific doubtful receivables from
customers which are experiencing financial difficulties.
(g) Recoverable accounts under production sharing and related allowance
Cash investments made by the Company during exploration, development and production phases under a production sharing contract
are recorded as “Recoverable accounts under production sharing” so long as they are recoverable under the terms of the relevant
contract. When the Company receives the natural gas and crude oil in accordance with the contract, an amount corresponding to thepurchase costs of the products (i.e., a cost recovery portion of the investments) is released from this account.
Because these investments are recoverable only where commercial oil or gas is discovered, an allowance for recoverable accounts
under production sharing is provided for probable losses on investments made during the exploration phase under production sharing

51

contracts arising from the failure to discover commercial oil and gas. This allowance is stated at an amount based on an assessmentof the recoverability of the investment in each respective project.
(h) Allowance for investments in exploration
The allowance for investments in exploration is provided for future potential losses on investments in exploration companies at an
estimated amount based on the net assets of the investees.
(i) Tangible fixed assets
Depreciation of tangible fixed assets is determined primarily by the declining-balance method, except for the buildings acquired on
and after April 1, 1998, on which depreciation is computed by the straight-line method, at rates based on the estimated useful livesof the respective assets. However, depreciation of certain mining facilities of two domestic subsidiaries is computed by the unit-ofproduction method.
(j) Intangible fixed assets
Exploration and development rights at the exploration stage are fully amortized in the year such rights are acquired and those at the
production stage are amortized by the unit-of-production method.
Capitalized computer software costs are being amortized over a period of five years.
Other intangible fixed assets are amortized by the straight-line method.
(k) Accrued retirement benefits
The Company and its subsidiaries have a defined benefit plan, i.e., lump-sum payment plan, covering substantially all employees,
the amounts of which are determined by reference to their basic rates of pay, length of service, and the conditions under which
termination occurs.
Accrued retirement benefits for employees are provided at the amount which would be required to be paid if all active employees
voluntarily terminated their employment as of the balance sheet date.
In addition, directors and statutory auditors of the Company and certain consolidated subsidiaries are customarily entitled to lumpsum payments under their respective unfunded retirement benefits plans. The provision for retirement benefits for these officers has been
made at an estimated amount.
(l) Leases
Non-cancelable leases are primarily accounted for as operating leases except that lease agreements which stipulate the transfer ofownership of the leased assets to the lessee are accounted for as finance leases.
(m) Research and development expenses and advertising costs
Research and development expenses are charged to income as incurred.
(n) Income taxes
Deferred tax assets and liabilities are determined based on the differences between financial reporting and the tax bases of the assets
and liabilities and are measured using the enacted tax rates and laws which will be in effect when the differences are expected to reverse.
(o) Derivative financial instruments
The Company has entered into various derivatives transactions in order to manage risk arising from adverse fluctuation in interest rates
and in the price of crude oil. Derivatives are carried at fair value with any changes in unrealized gain or loss charged or credited tooperations, except for those which meet the criteria for deferral hedge accounting under which unrealized gain or loss is deferred as an
asset or a liability.
(p) Appropriation of retained earnings
Under the Commercial Code of Japan, the appropriation of retained earnings with respect to a given financial period is made by resolutionof the shareholders at a general meeting to be held subsequent to the close of such financial period. The accounts for that period donot, therefore, reflect such appropriations.
(q) Recent accounting pronouncements
Impairment of fixed assets
A new Japanese accounting standard “Impairment of Fixed Assets” was issued in August 2002 that is effective for fiscal years beginningon or after April 1, 2005. Early adoption is allowed from fiscal years beginning on or after April 1, 2004 and an application from fiscal years
ending March 31, 2004 to March 30, 2006 is also permitted. The new standard requires that tangible and intangible fixed assets be carriedat cost less depreciation, and be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amountof an asset may not be recoverable. Companies would be required to recognize an impairment loss in their income statement if certain
indicators of asset impairment exist and the book value of an asset exceeds the undiscounted sum of future cash flows of the asset. The

52

standard states that impairment losses should be measured as the excess of the book value over the higher of (1) the fair market valueof the asset net of disposition costs and (2) the present value of future cash flows arising ongoing utilization of the asset and from disposal
after asset use. The standard covers land, factories, buildings and other forms of property, plant and equipment as well as intangible
assets. Fixed assets will be grouped at the lowest level for which there is identifiable cash flows that are independent of cash flows ofother groups of assets.
The Accounting Standards Board of Japan issued practical guidelines on the application of the standard in October 2003. In
accordance with the new guidelines, the Company and its subsidiaries expect to review their properties including recoverable accounts
under product sharing on a contract basis. The Company believes that the new accounting standard on impairment of fixed assets will
not have a material impact on their financial condition or results of operations under the current guidelines.
Business combination
A new Japanese accounting standard “Business Combination” was issued in October 2003 that is effective for fiscal years beginningon or after April 1, 2006. The new accounting standard requires business combinations to be accounted for primarily by the purchasemethod and permits certain limited business combinations to be accounted for by the pooling-of-interest method.
The Company will account for the acquisition of Japan Oil Development Co., Ltd. by the purchase method in line with the new standard.
See Note 16.

3. U.S. DOLLAR AMOUNTS
The translation of yen amounts into U.S. dollar amounts is included solely for convenience, as a matter of arithmetic computation only,at ¥105.63 = U.S.$1.00, the approximate rate of exchange in effect on March 31, 2004. This translation should not be construed as arepresentation that yen have been, could have been, or could in the future be, converted into U.S. dollars at the above or any other rate.

4. SECURITIESa) Information regarding other securities with determinable market value as of March 31, 2003 and 2004 is as follows:
Millions of yen
Acquisition
cost

Carrying
value

Gross
unrealized
gains (losses)

Securities whose fair value exceeds their carrying value:
Stock
¥
77
Debt securities
56,439¥84
56,876¥ 7
437

March 31, 2003

Subtotal
56,516
Securities whose carrying value exceeds their fair value:
Stock
195
Debt securities
21,40556,960444

180
21,398(15)(7)

Subtotal

21,60021,578

(22)

Total

¥78,116¥78,538¥422

Millions of yen

March 31, 2004

Acquisition
cost

Securities whose fair value exceeds their carrying value:
Stock
¥ 210
Debt securities
35,950¥Carrying
value

Gross
unrealized
gains (losses)

282
36,076¥ 72
126

Thousands of U.S. dollars$

Acquisition
cost

Carrying
value

Gross
unrealized
gains (losses)

1,988
340,339$ 2,670
341,531

$ 682
1,192

Subtotal
36,160
Securities whose carrying value exceeds their fair value:
Stock
77
Debt securities
27,36336,358198

342,327

344,201

1,874

70
27,330

(7)
(33)

729
259,046663
258,733

(66)
(313)

Subtotal

27,44027,400(40)

259,775

259,396

(379)

Total

¥63,600¥63,758¥158$602,102$603,597$1,49553b) Information regarding sales of securities classified as other securities for the years ended March 31, 2002, 2003 and 2004
is as follows:Year ended March 31,

Proceeds from sales
Gain on sales
Loss on sales

Millions of yen

Thousands of
U.S. dollars

2002

2003

2004

2004

¥84,62035–¥68,555259
65¥24,391
63–$230,910
596–c) The components of other securities without a determinable market value at March 31, 2003 and 2004 are summarized
as follows:
Millions of yen

Thousands of
U.S. dollars

2003

2004

2004

Other securities:
Unlisted securities (*)
Trust beneficiary certificates¥12,685
3,529¥17,402
3,509$164,745
33,220Total¥16,214¥20,911$197,965

March 31,

( )* An allowance is provided for investments in exploration companies at an estimated amount based on the financial position of the investees.

d) The redemption schedule for securities with maturity dates classified as other securities at March 31, 2004 is as follows:
Millions of yen
1 year or
lessMore than 1
year but lessthan 5 years

More than 5
year but lessthan 10 years

Debt securities:
Public bonds
Corporate bonds
Other¥10,645
4,824
3,510

¥43,537
4,398
–

Total

¥18,979¥47,935

March 31, 2004

Thousands of U.S. dollars
1 year or
lessMore than 1
year but lessthan 5 years

More than 5
year but lessthan 10 years¥–––$100,776
45,66933,229$412,165
41,636
–

$–
–
–

¥–

$179,674$453,801$–

5. LONG-TERM DEBT
Long-term debt at March 31, 2003 and 2004 consisted of the following:
Millions of yen

Thousands of
U.S. dollars

2003

2004

2004

Loans from banks and others, at interest rates ranging from1.055% to 2.150%, due through 2016:
SecuredUnsecured¥–
46,997¥ 83,090
86,335$ 786,614
817,334

Less: Current portion

46,997
132

169,425118

1,603,948
1,117¥46,865¥169,307$1,602,831

March 31,

Assets pledged as collateral for long-term debt and guarantee obligation at March 31, 2003 and 2004 were as follows:
Millions of yen
March 31,

Other current assets (restricted cash)
Investment securities

54

Thousands of
U.S. dollars

2003

2004

2004

¥–
–

¥ 9,140
2,722$ 86,528
25,770¥–¥11,862$112,298

The aggregate annual maturities of long-term borrowings subsequent to March 31, 2004 are summarized as follows:Year ending March 31,

Millions of yen

Thousands of
U.S. dollars

2005
2006
2007
2008
2009
2010 and thereafter

¥

118
3,688
12,793
16,30014,207
122,319$¥169,425$1,603,948

1,117
34,914
121,112
154,312
134,498
1,157,995

6. INCOME TAXESThe Company and its domestic consolidated subsidiaries are subject to a number of taxes based on income which, in the aggregate,
resulted in a statutory tax rate of approximately 36.2% in 2002, 2003 and 2004.
The effective tax rates reflected in the consolidated statements of income for the years ended March 31, 2002, 2003 and 2004 differ
from the statutory tax rate for the following reasons:Year ended March 31,

2002

2003

2004

Statutory tax rate
Effect of:Permanent differences
Change in valuation allowance
Foreign tax credits
Foreign taxes
Equity in earnings of affiliates
Other

36.2%

36.2%

36.2%

0.1
2.2
(34.1)
64.5
0.5
(1.9)

0.1
5.7
(39.9)
67.9
0.7
2.4

0.1
0.7
(29.5)
54.0
(0.6)
1.9

Effective tax rates

67.5%

73.1%

62.8%

The significant components of deferred tax assets and liabilities at March 31, 2003 and 2004 were as follows:
Millions of yen

Thousands of
U.S. dollars

2003

2004

2004

Deferred tax assets:
Investments in related parties
Loss on revaluation of land
Recoverable accounts under production sharing (Foreign taxes)
Allowance for investments in exploration
Allowance for recoverable accounts under production sharing
Net operating loss
Accumulated amortization of development costs
Accrued retirement benefits
Other¥ 23,915
4,547
–
3,843
2,793
1,634
998
453
4,045

¥ 29,259
4,547
6,778
2,558
670
4,757
545
402
4,603

$ 276,995
43,04664,167
24,217
6,343
45,035
5,160
3,806
43,576

Total gross deferred tax assets
Valuation allowance

42,228(39,105)

54,119(45,177)

512,345(427,691)

3,123

8,942

84,654

2,676
1,592

9,881
5,427

93,544
51,377

March 31,

Total deferred tax assets
Deferred tax liabilities:
Foreign taxes
Other
Total deferred tax liabilities

4,268

15,308144,921

Net deferred tax liabilities¥ (1,145)¥ (6,366)$ (60,267)

55

7. SHAREHOLDERS’ EQUITY
In accordance with the Commercial Code (the “Code”), the Company has provided a legal reserve, which is included in retained earnings.
The Code provides that an amount equal to at least 10% of the amount to be disbursed as distributions of earnings be appropriated to
the legal reserve until the total of such reserve and the additional paid-in capital account equals 25% of the common stock account. The
legal reserve amounted to ¥7,365 million and ¥7,365 million ($69,725 thousand), respectively, at March 31, 2003 and 2004.
The Code provides that neither additional paid-in capital nor the legal reserve is available for dividends, but both may be used to reduceor eliminate a deficit by resolution of the shareholders or may be transferred to common stock by resolution of the Board of Directors.
On October 1, 2001, an amendment to the Code went into effect. The amendment provides that if the total amount of additional paidin capital and the legal reserve exceeds 25% of the amount of common stock, the excess may be distributed to the shareholders either
as a return of capital or as dividends subject to the approval of the shareholders.

8. AMOUNTS PER SHARE

Year ended March 31,

Net income
Cash dividends
Net assets

Yen

U.S. dollars

2002

2003

2004

2004

¥ 46,852.92
10,000.00
391,760.56¥ 47,178.51
10,000.00
430,169.19¥ 58,838.76
10,000.00
471,826.00$ 557.03
94.67
4,466.78

Net income per share is computed based on the net income available for distribution to shareholders of common stock and the weightedaverage number of shares of common stock outstanding during the year.
Cash dividends per share represent the cash dividends declared as applicable to the respective years.
Amounts per share of net assets are computed based on the net assets available for distribution to the shareholders and the numberof shares of common stock outstanding at the year end.
See Note 16 (c) for the impact of a three-for-one stock split on amounts per share date.

9. DERIVATIVESThe Company utilizes derivatives for the purpose of hedging its exposure to adverse fluctuation in interest rates and the price of crudeoil, but does not enter into such transactions for speculative or trading purposes.
The Company is exposed to credit risk in the event of nonperformance by the counterparties to these derivative transactions, but any
such loss would not be material because the Company enters into transactions only with financial institutions or trading companies withhigh credit ratings. The notional amounts of the derivatives do not necessarily represent the amounts exchanged by the parties and,
therefore, are not a direct measure of the Company’s risk exposure in connection with derivatives.
No derivatives positions remained outstanding at March 31, 2003 or 2004.

10. RESEARCH AND DEVELOPMENT EXPENSES
Research and development expenses included in selling, general and administrative expenses amounted to ¥13 million, ¥64 million and¥56 million ($530 thousand) for the years ended March 31, 2002, 2003 and 2004, respectively.

11. RETIREMENT BENEFIT EXPENSES
Retirement benefit expenses for employees amounted to ¥129 million, ¥155 million and ¥103 million ($975 thousand) for the years ended
March 31, 2002, 2003 and 2004, respectively.

12. LEASESThe following pro forma amounts represent the acquisition costs, accumulated depreciation and net book value of the leased assets at
March 31, 2003 and 2004, which would have been reflected in the consolidated balance sheets if finance lease accounting had been
applied to the finance leases currently accounted for as operating leases:

56

Millions of yen

Thousands of
U.S. dollars

March 31,

2003

2004

2004

Acquisition costs of leased property
Accumulated depreciation

¥36
35

¥19
19

$180
180

Net carrying amount

¥ 1

¥ –

$ –

Lease payments relating to finance leases accounted for as operating leases amounted to ¥10 million, ¥8 million and ¥1 million ($9thousand) for the years ended March 31, 2002, 2003 and 2004, respectively.
There are no future minimum lease payment subsequent to March 31, 2004 relating to finance leases accounted for as operating leases.

13. CONTINGENT LIABILITIESAt March 31, 2004, the Company and its consolidated subsidiaries were contingently liable as guarantors of indebtedness of
unconsolidated subsidiaries and affiliates in the aggregate amount of ¥9,461 million ($89,567 thousand).
In addition, INPEX BTC Pipeline, LTD, a consolidated subsidiary, was contingently liable as guarantor of indebtedness of BTC Pipeline
Project Finance in the amount of ¥4,330 million ($40,992 thousand) at March 31, 2004.

14. SUPPLEMENTARY CASH FLOW INFORMATIONa) Following are the assets and liabilities of INPEX Jawa and its subsidiary which became consolidated subsidiaries during theyear ended March 31, 2004 following the acquisition of their stock:
Millions of yen

Thousands of
U.S. dollars

Current assets
Long-term assets
Current liabilities
Minority interests
Minority interests in consolidated subsidiaries¥ 13,916
2,539(34)(2,526)(5,126)$ 131,743
24,037(322)(23,914)(48,528)

Purchase of stock
Cash and cash equivalents held by subsidiaries

8,769(12,761)

83,016(120,808)

Net proceeds¥ 3,992$ 37,792

March 31, 2004b) Summary of the increase in assets and liabilities following the acquisition of interests by INPEX Southwest Caspian Sea, Ltd.
during the year ended March 31, 2004 is as follows:
March 31, 2004

Millions of yen

Current assets
Long-term liabilities
Current liabilities¥

Purchase of mining rights¥(163,511)

5
164,494(988)

Thousands of
U.S. dollars$

47
1,557,266(9,353)$(1,547,960)c) Summary of the decrease in assets and liabilities following the sales of interests by INPEX Sahul, Ltd. during the year ended
March 31, 2004 is as follows:
March 31, 2004

Current assets
Long-term liabilities
Current liabilities

Millions of yen

¥

21
1,737
(203)

Thousands of
U.S. dollars$

199
16,444(1,922)

Net assets of business soldGain on sales of mining rights

1,555
1,497

14,721
14,172

Proceeds from sales of mining rights¥3,052$28,89357

15. SEGMENT INFORMATIONThe Company and its subsidiaries are primarily engaged in the joint exploration, development and production of natural gas and crude
oil in Indonesia, the Middle East, Oceania, the Caspian Sea and certain other areas. As net sales, operating income and total assets of
the oil and natural gas business constituted more than 90% of the consolidated totals for the years ended March 31, 2002, 2003 and2004, the disclosure of business segment information has been omitted.
The geographical segment information for the Company and its subsidiaries for the years ended March 31, 2002, 2003 and 2004
is summarized as follows:
Millions of yen
Year ended March 31, 2002

Asia-Oceania (a)Other (b)Total

Eliminations

Consolidated

Sales to third parties
Intergroup sales and transfers¥180,023–¥4,181–¥184,204–¥––¥184,204–

Total sales
Operating expenses

180,023
83,506

4,181
3,769

184,204
87,275–(119)

184,204
87,156

Operating income¥ 96,517¥ 412¥ 96,929¥

119¥ 97,048

Total assets¥139,617¥6,497¥146,114¥141,535¥287,649

Asia-Oceania (a)Other (b)Total

Eliminations

Consolidated

Sales to third parties
Intergroup sales and transfers¥196,986–¥4,547–¥201,533–¥––¥201,533–

Total sales
Operating expenses

196,986
100,733

4,547
3,654

201,533
104,387–(124)

201,533
104,263

Operating income¥ 96,253¥ 893¥ 97,146¥

124¥ 97,270

Total assets¥176,650¥8,789¥185,439¥153,308¥338,747

NIS (b)Other (c)Total

Eliminations

Consolidated

–
6,506

¥7,409–¥218,831
6,506

¥

–
(6,506)¥218,831
–

6,506
4,754

7,409
5,440

225,337
131,620(6,506)(6,665)

218,831
124,955(a) Asia-Oceania: Indonesia, Australia(b) Other: UAE

Millions of yen
Year ended March 31, 2003(a) Asia-Oceania: Indonesia, Australia, East Timor(b) Other: UAE

Millions of yen
Year ended March 31, 2004

Asia-Oceania (a)Sales to third parties
Intergroup sales and transfers¥211,422–¥

Total sales
Operating expenses

211,422
121,426

Operating income¥ 89,996¥

1,752¥1,969¥ 93,717¥

159¥ 93,876

Total assets¥214,325¥191,697¥6,412¥412,434¥112,864¥525,298(a) Asia-Oceania: Indonesia, Australia, East Timor(b) NIS: Kazakhstan, Azerbaijan(c) Other: UAE, IranThousands of U.S. dollars

58

Year ended March 31, 2004

Asia-Oceania (a)Sales to third parties
Intergroup sales and transfers$2,001,534–

NIS (b)Other (c)Total–61,592$70,141–$2,071,675
61,592

Total sales
Operating expenses

2,001,534
1,149,541

61,59245,00670,14151,5012,133,267
1,246,048

Operating income$ 851,993$

16,586$18,640$ 887,219$

Total assets$2,029,016$1,814,797$60,703$3,904,516$

Eliminations

Consolidated–(61,592)$2,071,675–(61,592)(63,098)

2,071,675
1,182,950

1,506$ 888,725$1,068,484$4,973,000$

Overseas sales
Overseas sales, which include sales (other than exports to Japan) of its overseas subsidiaries, for the years ended March 31, 2002,
2003 and 2004 are summarized as follows:
Millions of yen
Year ended March 31, 2002

Overseas sales
Consolidated net sales
Overseas sales as a percentage of consolidated net sales

Asia (a)Other (b)Total

¥43,405–
23.6%¥6,819–3.7%¥ 50,224
184,204
27.3%

Asia (a)Other (b)Total

¥57,418–
28.5%¥5,737–
2.8%¥ 63,155
201,533
31.3%(a) Asia: Korea, Taiwan, Indonesia, Singapore(b) Other: Australia

Millions of yen
Year ended March 31, 2003

Overseas sales
Consolidated net sales
Overseas sales as a percentage of consolidated net sales(a) Asia: Korea, Taiwan, Indonesia, Singapore(b) Other: Australia

Millions of yen
Year ended march 31, 2004

Overseas sales
Consolidated net sales
Overseas sales as a percentage ofconsolidated net sales

Thousands of U.S. dollars

Asia (a)Other (b)Total

Asia (a)Other (b)Total¥58,089–¥6,257–¥ 64,346
218,831$549,929–$59,235–$ 609,164
2,071,675

26.5%

2.9%

29.4%

26.5%

2.9%

29.4%

(a) Asia: Korea, Taiwan, Indonesia, Singapore(b) Other: Australia

16. SUBSEQUENT EVENTSa) In accordance with a share exchange contract dated March 29, 2004 between Japan Oil Development Co., Ltd. (“JODCO”) and theCompany, the Company acquired from Japan National Oil Corporation (“JNOC”) all issued and outstanding shares of common stockof JODCO in exchange for 50,744.25 new shares of the Company’s common stock on May 17, 2004. As a result, the Company’s
additional paid-in capital was increased by ¥62,402 million ($590,760 thousand).
JODCO’s net sales and net loss for the year ended December 31, 2003 amounted to ¥259,697 million ($2,458,553 thousand)and ¥58,602 million ($554,786 thousand), respectively, which included civil rehabilitation-related gains of ¥124,545 million($1,179,068 thousand) and civil rehabilitation-related losses of ¥192,397 million ($1,821,424 thousand).
A summary of JODCO’s financial position as of December 31, 2003 is as follows:
Millions of yen

Thousands of
U.S. dollars

Current assets
Fixed assets¥104,777
48,265$ 991,925
456,925

Total assets¥153,042$1,448,850

Current liabilities
Long-term liabilities¥154,648
23,770$1,464,054
225,031

Total liabilities
Shareholders’ equity

178,418(25,376)

1,689,085(240,235)

Total liabilities and shareholders’ equity¥153,042$1,448,850

59

As of December 31, 2003, JODCO was in the process of civil rehabilitation proceedings and the civil rehabilitation plan wascompleted on January 31, 2004. A summary of JODCO’ financial position as of March 31, 2004 is as follows:
Millions of yen

Thousands of
U.S. dollars

Current assets
Fixed assets¥ 73,630
47,596$ 697,055
450,592

Total assets¥121,226$1,147,647

Current liabilities
Long-term liabilities¥ 42,593
22,773$ 403,228
215,592

Total liabilities
Shareholders’ equity

65,36655,860618,820
528,827¥121,226$1,147,647

Total liabilities and shareholders’ equityb) The Company made a three-for-one stock split of the Company’s common stock effective May 18, 2004 that resulted in an increaseof 1,279,888.50 shares of the Company’s common stock.
Had this stock split been made as of April 1, 2001, amounts per share information for the years ended March 31, 2002, 2003 and2004 would have been as follows:
Yen
Year ended March 31,

Amounts per share:— Net assets— Net income

U.S. dollars

2002

2003

2004

2002

2003

2004

¥130,586.85
15,617.64¥143,389.73
15,726.17¥157,275.33
19,612.92$1,236.27
147.85$1,357.47
148.88$1,488.93
185.68c) At the meeting of the Board of Directors held on April 15, 2004, it was resolved that the Company amend its Article of
Incorporation and issue one special class share to JNOC. The shareholders at the extraordinary meeting held on May 10, 2004
approved these resolutions.
The special class share, which has no voting rights at the common shareholders meeting, will be issued to JNOC on the date theCompany’s common stock is listed on the Tokyo Stock Exchange. The ownership of the special class share will give its holder a vetoright over the following major corporate actions and transactions by imposing the requirement to obtain a class vote:• Appointment and removal of directors• Disposition of all or part of the material assets• Amendments to the Article of Incorporation with respect to (i) the purpose of the Company’s business and (ii) the granting of voting
rights to the Company’s shares other than common stock• Mergers, share exchange or share transfer• Capital reduction• Dissolution
The special class share will be redeemed upon request by the relevant special class shareholder.
d) At the meeting of the Board of Directors held on September 2, 2004, it was resolved that INPEX North Makassar, Ltd., a majority owned
subsidiary of the Company, would assign its mining rights and related obligations to a third party due to a decline in expected
profitability. The assignment of the mining rights and related obligations is expected to become effective November 22, 2004, subject
to an approval of the government of Republic of Indonesia. No gain or loss on the assignment of mining rights and related obligations
will be recognized.

60

Report of Independent Auditors

The Board of Directors and Shareholders
INPEX CORPORATION

We have audited the accompanying consolidated balance sheets of INPEX CORPORATION and subsidiaries asof March 31, 2003 and 2004, and the related consolidated statements of income, shareholders’ equity, and cash
flows for the years then ended, all expressed in yen. These financial statements are the responsibility of theCompany’s management. Our responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted in Japan. Those standards
require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements. An audit also includes assessing the accounting principles used andsignificant estimates made by management, as well as evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated
financial position of INPEX CORPORATION and subsidiaries at March 31, 2003 and 2004, and the consolidated
results of their operations and their cash flows for the years then ended in conformity with accounting principles
generally accepted in Japan.

Supplemental Information
As described in Note 16 to the consolidated financial statements, the Company acquired all the shares of common
stock of Japan Oil Development Co., Ltd. on May 17, 2004. In addition, the Company made a three-for-one stock
split effective May 18, 2004, and the issuance of one special class share was approved by the shareholders at an
extraordinary meeting held on May 10, 2004.
The U.S. dollar amounts in the accompanying consolidated financial statements with respect to the year ended
March 31, 2004 are presented solely for convenience. Our audit also included the translation of yen amounts into
U.S. dollar amounts and, in our opinion, such translation has been made on the basis described in Note 3 to theconsolidated financial statements.

Tokyo, Japan
October 8, 2004

61

Supplemental Information

Semiannual Consolidated Balance Sheets (Unaudited)
INPEX CORPORATION and Subsidiaries
As of September 30, 2003 and 2004

Millions of yen

Thousands of
U.S. dollars(Note 3)

2003

2004

2004

¥ 37,976
13,68528,531
828
21,241(15)¥ 121,183
39,751
12,761
1,256
28,205(33)$ 1,091,247
357,956
114,912
11,310253,985(297)

102,246

203,123

1,829,113

54,403(21,975)

282,149(213,202)

2,540,738(1,919,874)

32,42868,947620,864

135,035
3,713

133,7518,513

1,204,422
76,659138,748

142,264

1,281,081

88,928(6,069)103,444(4,166)

931,508(37,514)

Recoverable accounts under production sharing
Less allowance for recoverable accounts under production sharing

82,859191,108(49,403)99,278225,947(44,939)

893,994
2,034,642(404,674)

Other investments
Less allowance for doubtful accounts

141,705
11,099(130)

181,008
24,223(687)

1,629,968
218,127(6,186)

235,533

303,8222,735,903¥508,955¥ 718,156$ 6,466,961

ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable—tradeMarketable securities (Note 4)Inventories
Other current assets
Less allowance for doubtful accounts

Tangible fixed assets
Less accumulated depreciation and amortization
Intangible assets:
Exploration and development rights
Other
Investments and other assets:
Investment securities (Note 4)Less allowance for investments in exploration

Total assets
See accompanying notes to semiannual consolidated financial statements.

62

Millions of yen

Thousands of
U.S. dollars(Note 3)

2003

2004

2004

1,942
132
10,751
25,108¥ 16,784
1,230
38,33544,981$ 151,139
11,076345,205
405,052

37,933

101,330

912,472

166,100
770
453
13,556

179,8821,438
498
34,355

1,619,829
12,9494,485
309,365

180,879

216,173

1,946,628

Total liabilities

218,812317,5032,859,100

Minority interests in consolidated subsidiaries

27,08833,144298,460

Shareholders’ equity (Note 6):
Common stock, without par value:
Additional paid-in capital
Retained earnings
Unrealized holding gain (loss) on securities
Translation adjustments

29,460–232,745(34)
884

29,46062,403
276,629
256(1,239)265,286
561,936
2,491,031
2,305(11,157)

Total shareholders’ equity

263,055

367,5093,309,401¥508,955¥718,156$6,466,961

LIABILITIES AND SHAREHOLDERS’ EQUITYCurrent liabilities:
Accounts payable
Current portion of long-term debt (Note 5)
Income taxes payable
Other current liabilities
Long-term liabilities:
Long-term debt (Note 5)
Accrued employees’ retirement benefits
Accrued officers’ retirement benefits
Other

¥

Contingent liabilities (Note 9)

Total liabilities and shareholders’ equity

63Semiannual Consolidated Statements of Income (Unaudited)
INPEX CORPORATION and Subsidiaries
For the six months ended September 30, 2003 and 2004

Millions of yen

Thousands of
U.S. dollars(Note 3)

2003

2004

2004

¥110,188
53,545¥213,939
91,454$1,926,511
823,539

Gross profit
Exploration expenses
Selling, general and administrative expenses
Depreciation and amortization

56,643
5,051
2,314
399

122,485
982
4,068
888

1,102,972
8,843
36,632
7,997

Operating income
Other income:Interest income
Gain on sales of mining rights
Equity in earnings of affiliates
Reversal of allowance for recoverable accounts under production sharing
Other

48,879116,547

1,049,500

541
1,498
1,028
–
567

1,604
–
–
744
348

14,444
–
–
6,699
3,134

3,634

2,696

24,277

680
–
5,890
390
552
1,252

1,185
479
180
890
5,252
940

10,671
4,313
1,621
8,014
47,294
8,465

8,764

8,926

80,37843,749110,317993,399

Income taxes:
Current
Deferred

28,973(521)

83,032(4,835)

747,699(43,539)

Minority interests

28,452(2,601)

78,197(897)

704,160(8,078)Net income (Note 6)¥ 17,898¥ 33,017$ 297,317

Net sales
Cost of sales

Other expenses:
Interest expense
Equity in losses of affiliates
Provision for allowance for recoverable accounts under production sharing
Amortization of exploration and development rights
Foreign exchange loss
Other

Income before income taxes and minority interests

See accompanying notes to semiannual consolidated financial statements.

64Semiannual Consolidated Statements of Shareholders’ Equity (Unaudited)
INPEX CORPORATION and Subsidiaries
For the six months ended September 30, 2003 and 2004

Millions of yen

Translation
adjustments

Totalshareholders’equity–––¥220,853
17,898(5,892)¥ 410––¥ 2,847––¥253,570
17,898(5,892)

–
–
–
–

(114)
–
–
232,745

–
(444)
–
(34)

–
–
(1,963)
884

(114)
(444)
(1,963)
263,055

Additional
paid-in
capitalCommonstock

Balance at March 31, 2003
¥29,460
Net income–
Cash dividends paid–
Bonuses to directors andstatutory auditors–
Unrealized holding gain on securities–
Translation adjustments–
Balance at September 30, 2003
29,460Retainedearnings

Unrealized
holding
gain onsecurities¥

Balance at March 31, 2004
Net income
Cash dividends paid
Bonuses to directors andstatutory auditors
Unrealized holding loss on securities
Translation adjustments
Increase due to a shareexchange transaction

29,460–––––249,628
33,017(5,892)

154––(1,128)––278,11433,017(5,892)

–
–
–

–
–
–

(124)
–
–

–
102
–

–
–
(111)

(124)
102
(111)

–

62,403–––62,403

Balance at September 30, 2004

¥29,460¥62,403¥276,629¥ 256¥(1,239)¥367,509

Additional
paid-in
capitalRetainedearnings

Unrealized
holding
gain onsecurities

Translation
adjustments

Totalshareholders’equity–––$2,247,888
297,317(53,057)$1,387––$(10,158)––$2,504,403
297,317(53,057)–––(1,117)
–
–

–
918
–

–
–
(999)

(1,117)918(999)

Thousands of U.S. dollars (Note 3)

Commonstock

Balance at March 31, 2004
$265,286
Net income–
Cash dividends paid–
Bonuses to directors andstatutory auditors–
Unrealized holding gain on securities–
Translation adjustments–
Increase due to a shareexchange transaction–$

561,936–––

561,936

Balance at September 30, 2004

$561,936$2,491,031$2,305$(11,157)$3,309,401$265,286

See accompanying notes to semiannual consolidated financial statements.

65Semiannual Consolidated Statements of Cash Flows (Unaudited)
INPEX CORPORATION and Subsidiaries
For the six months ended September 30, 2003 and 2004

Cash flows from operating activities:
Income before income taxes and minority interests
Depreciation and amortization(Gain) loss on sales of tangible fixed assets
Amortization of goodwill(Reversal of) provision for allowance for doubtful accounts
Provision for allowance for recoverable accounts under production sharing(Reversal of) provision for accrued retirement benefits
Interest and dividend income
Interest expense
Foreign exchange loss
Equity in (gains) losses of affiliates
Gain on sales of mining rights
Gain on sales of investment securities
Accounts receivable
Recovery of recoverable accounts under production sharing (capital expenditures)
Recoverable accounts under production sharing (operating expenditures)
Inventories
Accounts payable
Other receivables
Accrued expenses
Long-term accrued expenses
Advance payments received
Bonuses to directors and statutory auditors
Other
SubtotalInterest and dividends received
Interest paid
Income taxes paid
Net cash provided by operating activities
Cash flows from investing activities:
Proceeds from sales of marketable securities
Purchases of tangible fixed assets
Proceeds from sales of tangible fixed assets
Purchases of intangible assets
Proceeds from intangible assets
Purchases of investment securities
Proceeds from sales of investment securities
Investment in recoverable accounts under production sharing
Decrease in short-term loans receivable
Long-term loan madeCollection of long-term loans receivable
Purchase of mining rights
Proceeds from sales of mining rights
Other
Net cash used in investing activities
Cash flows from financing activities:
Proceeds from long-term debt
Repayment of long-term debt
Proceeds from minority interests for additional shares
Cash dividends paid
Restricted cash deposited
Proceeds from refund of restricted cash
Other
Net cash provided by financing activities
Effect of exchange rate changes on cash and cash equivalents
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of the period
Increase in cash and cash equivalents due to a share exchange transaction
Cash and cash equivalents at end of the period

66

See accompanying notes to semiannual consolidated financial statements.

Millions of yen

Thousands of
U.S. dollars(Note 3)

2003

2004

2004

¥ 43,749
1,013
49
84
(13)
6,565
(213)
(570)
680
1,828
(1,028)(1,498)
(63)
2,104
9,314
(7,826)545(1,597)
(452)
(74)
(855)
5,859
(114)
243
57,730
1,117(482)(26,515)
31,850¥110,317
5,589
(46)
84
470
263
41
(1,688)
1,185
4,171
479
–
–
(7,218)16,729(3,078)(363)
3,699(5,932)
13,037
1,547
1,877
(127)
(3,393)
137,643
1,983(1,047)(75,062)
63,517$ 993,399
50,329
(414)
757
4,232
2,368
369
(15,200)
10,671
37,5604,313––(64,998)
150,644(27,717)(3,269)33,309(53,417)
117,398
13,931
16,902(1,144)(30,554)
1,239,469
17,857(9,428)(675,930)
571,968

9,495(4,873)10(1)–(15,105)684(26,859)(12)(0)
1(162,476)
3,053
(17)
(196,100)

14,221(5,542)350(3)
0(33,491)–(30,829)
(0)
(736)
3
–
–
(516)
(56,543)

128,059(49,905)
3,152
(27)
0
(301,585)–(277,614)(0)(6,628)27––(4,646)(509,167)

117,782(59)
28,795(5,892)(16,500)––
124,126(314)(40,438)
78,414–¥ 37,976

10,793(1,701)
1,244(5,892)
–
580
(79)
4,945
(1,212)
10,70754,58255,894¥121,183

97,190(15,318)
11,202(53,057)
–
5,223
(711)
44,529(10,914)
96,416
491,508
503,323$1,091,247

Notes to Semiannual Consolidated Financial Statements (Unaudited)
INPEX CORPORATION and Subsidiaries

1. BASIS OF PRESENTATIONINPEX CORPORATION (the “Company”) is primarily engaged in the exploration, development and production of natural gas and crudeoil, and is 54.0% owned by Japan National Oil Corporation.
The Company and its domestic subsidiaries maintain their accounting records and prepare their semiannual financial statements inaccordance with accounting principles generally accepted in Japan, and its overseas subsidiaries maintain their books of account inconformity with those of their countries of domicile. The accompanying semiannual consolidated financial statements have been
prepared in accordance with accounting principles generally accepted in Japan, which may differ in certain material respects fromaccounting principles generally accepted in the United States of America, and are compiled from the semiannual consolidated financial
statements prepared by the Company as required by the Securities and Exchange Law of Japan.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES(a) Principles of consolidation and accounting for investments in unconsolidated subsidiaries and affiliates
The accompanying semiannual consolidated financial statements include the accounts of the Company and companies controlled
directly or indirectly by the Company. Companies over which the Company exercises significant influence in terms of their operating andfinancial policies are included in the semiannual consolidated financial statements on an equity basis. All significant intercompany
balances and transactions are eliminated in consolidation.
Most of the Company’s subsidiaries are consolidated on the basis of six-month periods ending June 30, which differ from that of theCompany; however, the significant effect of the difference in the periods has been properly adjusted in consolidation.
The excess of cost over underlying net assets at fair value as of their dates of acquisition is amortized over a period of less than 20
years on a straight-line basis.
(b) Cash equivalents
All highly liquid investments with a maturity of three months or less when purchased are considered cash equivalents.
(c) Foreign currency translation
Monetary assets and liabilities denominated in foreign currencies are translated into yen at the exchange rates prevailing at the balance
sheet date. All revenues and expenses associated with foreign currencies are translated at the rates of exchange prevailing when suchtransactions were made. The resulting exchange gain or loss is credited or charged to income.
The revenue and expense accounts of the overseas subsidiaries are translated into yen at the rates of exchange in effect at the balance
sheet date. Except for the components of shareholders’ equity, the balance sheet accounts are also translated into yen at the rates of
exchange in effect at the balance sheet date. The components of shareholders’ equity are translated at their historical exchange rates.
Translation adjustments are presented as a component of shareholders’ equity and minority interests in the accompanying semiannual
consolidated financial statements.
(d) Securities
In general, securities are classified into three categories: trading, held-to-maturity or other securities. Securities held by the Company
and its subsidiaries are all classified as other securities. Other securities with a determinable market value are stated at fair value withany changes in unrealized holding gain or loss, net of the applicable income taxes, included directly in shareholders’ equity. Other
securities without a determinable market value are stated at cost. Cost of securities sold is determined by the moving average method.
(e) Inventories
Inventories are mainly stated at cost determined by the average method.
(f) Allowance for doubtful accounts
The allowance for doubtful receivables is provided at an amount determined based on the historical experience of bad debt with respect
to ordinary receivables, plus an estimate of uncollectible amounts determined by reference to specific doubtful receivables from
customers which are experiencing financial difficulties.
(g) Recoverable accounts under production sharing and related allowance
Cash investments made by the Company during exploration, development and production phases under a production sharing contract
are recorded as “Recoverable accounts under production sharing” so long as they are recoverable under the terms of the relevant
contract. When the Company receives the natural gas and crude oil in accordance with the contract, an amount corresponding to thepurchase costs of the products (i.e., a cost recovery portion of the investments) is released from this account.

67

Because these investments are recoverable only where commercial oil or gas is discovered, an allowance for recoverable accounts
under production sharing is provided for probable losses on investments made during the exploration phase under production sharing
contracts arising from the failure to discover commercial oil and gas. This allowance is stated at an amount based on an assessmentof the recoverability of the investment in each respective project.
(h) Allowance for investments in exploration
The allowance for investments in exploration is provided for future potential losses on investments in exploration companies at an
estimated amount based on the net assets of the investees.
(i) Tangible fixed assets
Depreciation of tangible fixed assets is determined primarily by the declining-balance method, except for the buildings acquired on andafter April 1, 1998, on which depreciation is computed by the straight-line method, at rates based on the estimated useful lives of therespective assets. However, depreciation of mining facilities is computed primarily by the unit-of-production method.
(j) Intangible fixed assets
Exploration and development rights at the exploration stage are fully amortized in the year such rights are acquired and those at the
production stage are amortized by the unit-of-production method.
Mining rights are amortized primarily by the unit-of-production method.
Capitalized computer software costs are being amortized over a period of five years.
Other intangible fixed assets are amortized by the straight-line method.
(k) Accrued retirement benefits
The Company and its subsidiaries have a defined benefit plan, i.e., lump-sum payment plan, covering substantially all employees,
the amounts of which are determined by reference to their basic rates of pay, length of service, and the conditions under which
termination occurs.
Accrued retirement benefits for employees are provided at the amount which would be required to be paid if all active employees
voluntarily terminated their employment as of the balance sheet date.
In addition, directors and statutory auditors of the Company and certain consolidated subsidiaries are customarily entitled to lumpsum payments under their respective unfunded retirement benefits plans. The provision for retirement benefits for these officers has been
made at an estimated amount.
(l) Leases
Non-cancelable leases are primarily accounted for as operating leases except that lease agreements which stipulate the transfer ofownership of the leased assets to the lessee are accounted for as finance leases.
(m) Research and development expenses and advertising costs
Research and development expenses are charged to income as incurred.
(n) Income taxes
Deferred tax assets and liabilities are determined based on the differences between financial reporting and the tax bases of the assets
and liabilities and are measured using the enacted tax rates and laws which will be in effect when the differences are expected to reverse.
(o) Appropriation of retained earnings
Under the Commercial Code of Japan, the appropriation of retained earnings with respect to a given financial period is made by resolutionof the shareholders at a general meeting to be held subsequent to the close of such financial period. The accounts for that period donot, therefore, reflect such appropriations.
(p) Recent accounting pronouncements
Impairment of fixed assets
A new Japanese accounting standard “Impairment of Fixed Assets” was issued in August 2002 that is effective for fiscal years beginningon or after April 1, 2005. Early adoption is allowed from fiscal years beginning on or after April 1, 2004 and an application from fiscal years
ending March 31, 2004 to March 30, 2006 is also permitted. The new standard requires that tangible and intangible fixed assets be carriedat cost less depreciation, and be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amountof an asset may not be recoverable. Companies would be required to recognize an impairment loss in their income statement if certain68indicators of asset impairment exist and the book value of an asset exceeds the undiscounted sum of future cash flows of the asset. The
standard states that impairment losses should be measured as the excess of the book value over the higher of (1) the fair market valueof the asset net of disposition costs and (2) the present value of future cash flows arising ongoing utilization of the asset and from disposal
after asset use. The standard covers land, factories, buildings and other forms of property, plant and equipment as well as intangible
assets. Fixed assets will be grouped at the lowest level for which there is identifiable cash flows that are independent of cash flows ofother groups of assets.
The Accounting Standards Board of Japan issued practical guidelines on the application of the standard in October 2003. In
accordance with the new guidelines, the Company and its subsidiaries expect to review their properties including recoverable accounts
under product sharing on a contract basis. The Company believes that the new accounting standard on impairment of fixed assets will
not have a material impact on their financial condition or results of operations under the current guidelines.
Business combination
A new Japanese accounting standard “Business Combination” was issued in October 2003 that is effective for fiscal years beginningon or after April 1, 2006. The new accounting standard requires business combinations to be accounted for primarily by the purchasemethod and permits certain limited business combinations to be accounted for by the pooling-of-interest method.

3. U.S. DOLLAR AMOUNTS
The translation of yen amounts into U.S. dollar amounts is included solely for convenience, as a matter of arithmetic computation only,at ¥111.05=U.S.$1.00, the approximate rate of exchange in effect on September 30, 2004. This translation should not be construed
as a representation that yen have been, could have been, or could in the future be, converted into U.S. dollars at the above or any
other rate.

4. SECURITIESa) Information regarding other securities with determinable market value as of September 30, 2003 and 2004 is as follows:
Millions of yen

September 30, 2003

Other securities:
StocksBonds:
National and local government bonds
Corporate bonds
Total

Carrying
value

Gross
unrealized
gains (losses)

297

¥ 26

67,020
10,636

66,91910,676(101)
40¥77,927¥77,892¥ (35)

Acquisition
cost

¥

271

¥

Millions of yen

September 30, 2004

Other securities:
StocksBonds:
National and local government bonds
Corporate bonds
Total

Carrying
value

Gross
unrealized
gains (losses)

355

¥ 68

71,135
5,917

71,301
5,947

166
30

¥77,339¥77,603¥264

Acquisition
cost

¥

287

¥

Thousands of U.S. dollars
Carrying
value

Gross
unrealized
gains (losses)

3,197

$ 612

640,567
53,282642,062
53,552

1,495
270$696,434$698,811$2,377

Acquisition
cost

$

2,585

$

69

b) The components of other securities without a determinable market value at September 30, 2003 and 2004 are summarized
as follows:
Millions of yen

Thousands of
U.S. dollars

2003

2004

2004

Other securities:
Unlisted securities (*)
Trust beneficiary certificates¥16,125
3,519¥18,6282,000$167,744
18,010Total¥19,644¥20,628$185,754

September 30,( )* An allowance is provided for investments in exploration companies at an estimated amount based on the financial position of the investees.

5. LONG-TERM DEBT
Long-term debt at September 30, 2003 and 2004 consisted of the following:
Millions of yen

Thousands of
U.S. dollars

2003

2004

2004

Loans from banks and others, at interest rates ranging from 1.025% to 3.050%,
due through 2016
SecuredUnsecured¥ 80,847
85,385¥ 90,819
90,293$ 817,821
813,084

Less: Current portion

166,232
132

181,1121,230

1,630,905
11,076¥166,100¥179,882$1,619,829

September 30,

Assets pledged as collateral for long-term debt and guarantee obligation at September 31, 2003 and 2004 were as follows:

September 30,

Other current assets (restricted cash)
Investment securities

Millions of yen

Thousands of
U.S. dollars

2003

2004

2004

¥16,500–¥ 8,560
2,743$ 77,082
24,701¥16,500¥11,303$101,783

Yen

U.S. dollars

2003

2004

2004

¥ 30,377.50–
446,462.08¥ 17,596.54–
191,427.36$ 158.46–
1,723.79

6. AMOUNTS PER SHARE

For the six months ended September 30,

Net income
Cash dividends
Net assets

Net income per share is computed based on the net income available for distribution to shareholders of common stock and the weightedaverage number of shares of common stock outstanding during the period.
Cash dividends per share represent the cash dividends declared as applicable to the respective periods.
Amounts per share of net assets are computed based on the net assets available for distribution to the shareholders and the numberof shares of common stock outstanding at the period end.

70

The Company made a 3-for-1 stock split on May 18, 2004. The following table shows the amounts per share information if this stock
split had been made at the beginning of the previous year.
Yen
For the six months ended September 30,

2003

Net income
Cash dividends
Net assets¥ 10,125.83–
148,820.69

7. RETIREMENT BENEFIT EXPENSES
Retirement benefit expenses for employees amounted to ¥70 million and ¥112 million ($1,012 thousand) for the six months ended
September 30, 2003 and 2004, respectively.

8. LEASES
The following amounts represent the acquisition costs, accumulated depreciation and net book value of the leased assets at September
30, 2003 and 2004, which would have been reflected in the consolidated balance sheets if finance lease accounting had been applied
to the finance leases currently accounted for as operating leases:
Millions of yen

Thousands of
U.S. dollars

September 30,

2003

2004

2004

Acquisition costs of leased property
Accumulated depreciation

¥20
20

¥–
–

$–
–

Net carrying amount

¥ –

¥–

$–

Lease payments relating to finance leases accounted for as operating leases amounted to ¥1 million for the six months ended
September 30, 2003.
There are no future minimum lease payment subsequent to September 30, 2004 relating to finance leases accounted for as
operating leases.

9. CONTINGENT LIABILITIESAt September 30, 2004, the Company and its consolidated subsidiaries were contingently liable as guarantors of indebtedness of
unconsolidated subsidiaries and affiliates in the aggregate amount of ¥10,715 million ($96,488 thousand).
In addition, INPEX BTC Pipeline, LTD, a consolidated subsidiary, was contingently liable as guarantor of indebtedness of BTC Pipeline
Project Finance in the amount of ¥4,455 million ($41,117 thousand) at September 30, 2004.

71

10. SEGMENT INFORMATIONThe Company and its subsidiaries are primarily engaged in the joint exploration, development and production of natural gas and crude
oil in Indonesia, the Middle East, Oceania, the Caspian Sea and certain other areas. As net sales and operating income of the oil andnatural gas business constituted more than 90% of the consolidated totals for the six months ended September 30, 2003 and 2004,
the disclosure of business segment information has been omitted.
The geographical segment information for the Company and its subsidiaries for the six months ended September 30, 2003 and 2004
is summarized as follows:
Millions of yen
For the six months ended September 30, 2003

Asia-Oceania (a)Other (b)Total

Eliminations

Sales to third parties
Intergroup sales and transfers¥106,068–¥4,1203,178¥110,188
3,178

¥

–
(3,178)¥110,188–

Total sales
Operating expenses

106,068
58,929

7,298
5,641

113,366
64,570(3,178)(3,261)

110,188
61,309Operating income¥ 47,139¥1,657¥ 48,796¥¥ 48,879

83

Consolidated(a) Asia-Oceania: Indonesia, Australia, East Timor(b) Other: UAE, Azerbaijan

Millions of yen
For the six months ended September 30, 2004

AsiaOceania (a)Sales to third parties
Intergroup sales and transfers¥128,631–

Total sales
Operating expenses
Operating income

NIS (b)Middle East (c)Other (d)Total

Eliminations

Consolidated

–
7,187

¥85,308–¥ ––¥213,939
7,187¥–(7,187)¥213,939–

128,631
69,565

7,187
5,238

85,30829,797–60

221,126
104,660(7,187)(7,268)

213,939
97,392¥ 59,066¥1,949¥55,511¥(60)¥116,466¥¥116,547¥

81(a) Asia-Oceania: Indonesia, Australia, East Timor(b) NIS: Kazakhstan, Azerbaijan(c) Middle East: UAE, Iran(d) Other: Japan

Thousands of U.S. dollars
AsiaOceania

NIS

Middle East

Sales to third parties
Intergroup sales and transfers$1,158,316–$–
64,719$768,194–

Total sales
Operating expenses

1,158,316
626,429

64,71947,168Operating income$ 531,887$17,551

For the six months ended September 30, 2004

72

Other

Total

Eliminations

Consolidated––$1,926,510
64,719$–(64,719)$1,926,510–

768,194
268,321–
540

1,991,229
942,458(64,719)(65,448)

1,926,510
877,010$499,873$(540)$1,048,771$$1,049,500$

729

Overseas sales
Overseas sales, which include sales (other than exports to Japan) of its overseas subsidiaries, for the six months ended September 30,
2003 and 2004 are summarized as follows:
Millions of yen
For the six months ended September 30, 2003

Overseas sales
Consolidated net sales
Overseas sales as a percentage of consolidated net sales

Asia (a)Other (b)Total

¥26,377–23.9%¥2,107–
1.9%¥ 28,484
110,188
25.9%(a) Asia: Korea, Taiwan, Indonesia(b) Other: Australia

Millions of yen
For the six months ended September 30, 2004

Overseas sales
Consolidated net sales
Overseas sales as a percentage ofconsolidated net sales

Thousands of U.S. dollars

Asia (a)Other (b)Total

Asia (a)Other (b)Total

¥67,986–¥2,133–¥ 70,119
213,939$612,210–$19,208–$ 631,418
1,926,511

31.8%

1.0%

32.8%

31.8%

1.0%

32.8%

(a) Asia: Korea, Taiwan, Indonesia, Singapore, Thailand(b) Other: Australia

11. SUBSEQUENT EVENTS(a) The Company issued one special class share, which has no voting rights at the common shareholders meeting, to Japan National
Oil Corporation on November 17, 2004. The ownership of the special class share will give its holder a veto right over the following
major corporate actions and transactions by imposing the requirement to obtain a class vote.
• Appointment and removal of directors• Disposition of all or part of the material assets• Amendments to the Article of Incorporation with respect to (i) the purpose of the Company’s business and (ii) the granting of voting
rights to the Company’s shares other than common stock.
• Mergers, share exchange or share transfer• Capital Reduction• Dissolution
The special class share will be redeemed upon request by the relevant special class shareholder.
(b) As a part of a civil rehabilitation plan, Japan Oil Development Co., Ltd., which became a wholly owned subsidiary of the Company
effective May 17, 2004, issued a new share allotted to Japan National Oil Corporation with an issued value of ¥10 million on January
29, 2004. Regarding this matter, Oversea Oil Development Co. Ltd., a former shareholder of Japan Oil Development Co., Ltd.,
appealed to the Tokyo District Court for the following items on February 23, 2004.
• Rescission of a resolution for approval to issue the new share to Japan National Oil Corporation at an extraordinary generalshareholders meeting of Japan Oil Development Co., Ltd.
• Rescission of issuing the new share
The Tokyo District Court dismissed all accusations on October 14, 2004. The court decision was confirmed on October 28, 2004.
The court appeal related to the aforementioned procedure of civil rehabilitation has been brought to the end by the court decision.

73

Reserves and Production

1. Oil and Gas Reserves
GeneralOur crude oil and natural gas reserve estimates have been extracted without material adjustments from the reserve report dated June4, 2004 prepared by DeGolyer and MacNaughton, independent petroleum engineering consultants, which contains their evaluation of(i) both proved and probable reserves as of March 31, 2004 as well as (ii) proved reserves as of March 31, 2003, and is based upon theirauthority as experts with respect to such matters.
DeGolyer and MacNaughton conducted their review of our fields using the standards applied by the SEC with respect to our estimatesof proved reserves, and the standards applied by SPE/WPC with respect to our estimates of probable reserves. SPE/WPC standards
differ in various material respects from standards applied by the SEC.
Proved reserves are those estimated quantities which geological and engineering data demonstrate with reasonable certainty to be
recoverable in the future years from known reservoirs under existing economic and operating conditions as of the date the estimate is
made. Proved developed reserves are those reserves which can be expected to be recovered through existing wells with existing
equipment and operating methods. Proved undeveloped reserves are those reserves which are expected to be recovered from new wellson undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
There is greater risk that the probable reserve estimates will not actually be recovered. Probable reserves are reserves susceptibleof being proved that are based on reasonable evidence of producible hydrocarbons within the limits of a structure or reservoir above
known or inferred fluid contacts but are defined to a lesser degree of certainty because of more limited well control and/or the lack ofdefinitive production tests. Since our proved reserve figures included in this offering circular were prepared under SEC standards, somereserves which might otherwise be classified as proved under SPE/WPC standards are included in probable reserves.
Estimation and evaluation of proved and probable reserves naturally involve multiple uncertainties. The accuracy of any reserves
evaluation depends on the quality of available information and engineering and geological interpretation. Based on the results of drilling,
testing and production after the report date of the estimates prepared by DeGolyer and MacNaughton, reserves may be significantly
restated upwards or downwards. Changes in the price of crude oil and natural gas may also affect our proved and probable reserve
estimates as well as estimates of our discounted future net cash flows because these reserves are evaluated, and the discounted future
net cash flows are estimated, based on prices and costs as of the date of the evaluation.
Reserve estimates included herein are (i) our reserve amounts as of our respective March 31 fiscal year end, for the most recent four
years and (ii) combined figures of our and JODCO’s reserve amounts as of March 31, 2003 and 2004. The proportional interests inreserves held by equity method affiliates of (i) ours and (ii) ours and JODCO’s are not broken down by geographical regions, although
in JODCO’s case all such reserves are in the Middle East.
At March 31, 2004, we had estimated combined net proved crude oil (which includes NGL) and natural gas reserves of approximately
1,016 MMbbls and 3,704 Bcf, respectively, of which approximately 16.5% and 100%, respectively, were attributable to our interests in
the Asia and Oceania region which includes Indonesia, Australia, and the Joint Petroleum Development Area. Approximately 66.2% and
0%, respectively, of such reserves were attributable to our interest in the Middle East which includes the United Arab Emirates and Iran,and approximately 17.3% and 0%, respectively, were attributable to the Caspian Sea area and the remaining parts of the world.

74

Proved Reserves
INPEX
The table below sets forth information about our net proved and proved developed reserves at March 31, 2001, 2002, 2003 and 2004.

Asia and Oceania

Middle East

Caspian Sea
area

SubtotalInterest in reserves
held by equity
method affiliates

Total

Oil
(MMbbls)

Gas
(Bcf)

Oil
(MMbbls)

Gas
(Bcf)

Oil
(MMbbls)

Gas
(Bcf)

Oil
(MMbbls)

Gas
(Bcf)

Oil
(MMbbls)

Gas
(Bcf)

Oil
(MMbbls)

Gas
(Bcf)

Proved Developed andUndeveloped Reserves
Reserves as of March 31, 2001
Extensions and discoveries
Acquisition and sales
Revisions of previous estimatesInterim production
Reserves as of March 31, 2002

187.4
–
–
8.1
(19.6)
175.9

3,745.9––
39.3(236.4)
3,548.8

18.4
–
–
–
(1.6)
16.8

–
–
–
–
–
–

–
–
–
–
–
–

–
–
–
–
–
–

205.7
–
–
8.1
(21.1)
192.7

3,745.9––
39.3(236.4)
3,548.8

7.9
–
–
0.4
(1.1)
7.2

8.6
–
–
(0.5)
(1.6)
6.5

213.7
–
–
8.5
(22.3)
199.9

3,754.5––
38.8(238.0)3,555.2

Reserves as of March 31, 2002
Extensions and discoveries
Acquisition and sales
Revisions of previous estimatesInterim production
Reserves as of March 31, 2003

175.9
–
–
(16.6)(16.4)
143.0

3,548.8––
70.0(255.6)
3,363.1

16.8
–
–
–
(1.6)
15.3

–
–
–
–
–
–

–
–
–
–
–
–

–
–
–
–
–
–

192.7
–
–
(16.6)(17.9)
158.2

3,548.8––
70.0(255.6)
3,363.1

7.2
–
2.9
(0.8)
(1.1)
8.2

6.5
–
–
(0.6)
(1.6)
4.3

199.9
–
2.9
(17.4)(19.0)
166.4

3,555.2––
69.4(257.2)
3,367.4

Reserves as of March 31, 2003
Extensions and discoveries
Acquisition and sales
Revisions of previous estimatesInterim production
Reserves as of March 31, 2004

143.0
32.0
12.7
(4.4)
(15.4)
167.8

3,363.1
177.7
34.1
424.2
(295.6)
3,703.5

15.3
–
–
0.2
(1.7)
13.8

–
–
–
–
–
–

–
–
177.9
1.6
(3.7)
175.8 (1)

–
–
–
–
–
–

158.2
32.0
190.6
(2.6)
(20.8)
357.4

3,363.1
177.7
34.1
424.2
(295.6)
3,703.5

8.2
–
(2.2)
(2.9)
(1.0)
2.1

4.3
–
(24.6)
22.0
(1.7)
–

166.4
32.0
188.4
(5.5)
(21.8)
359.5

3,367.4
177.7
9.5
446.2
(297.3)
3,703.5

89.0

1,372.6

13.8

–

24.5

–

127.3

1,372.6

2.1

–

129.4

1,372.6

Proved Developed Reserves
As of March 31, 2004
Note:(1) Includes proved reserves of 175.8 MMbbls attributable to a consolidated subsidiary in which there is a 49% minority interest. Proved reserves of 89.6
MMbbls are attributable to our 51% interest in this subsidiary.

Combined Figures of INPEX and JODCOThe table below sets forth information about combined figures of our and JODCO’s net proved and proved developed reserves as ofMarch 31, 2003 and 2004.

INPEX & JODCOINPEX & JODCO’s interest in reserves
held by equity method affiliates

Total

Combined figures for the year ended March 31, 2004

Oil
(MMbbls)

Gas
(Bcf)

Oil
(MMbbls)

Gas
(Bcf)

Oil
(MMbbls)

Gas
(Bcf)

Proved Developed andUndeveloped Reserves
Reserves as of March 31, 2003
Extensions and discoveries
Acquisition and sales
Revisions of previous estimatesInterim production
Reserves as of March 31, 2004

526.8
32.0
190.6
(2.4)
(43.6)
703.5

3,363.1
177.7
34.1
424.2
(295.6)
3,703.5

336.2
–
(2.2)
(1.6)
(19.6)
312.8

4.3–(24.6)
22.0
(1.7)
–

863.0
32.0
188.4
(4.0)
(63.2)
1,016.3

3,367.4
177.7
9.5
446.2
(297.3)
3,703.5

Proved Developed Reserves
As of March 31, 2004

473.4

1,372.6

312.8

–

786.2

1,372.675

Standardized Measure of Discounted Future Net Cash Flows and Changes Relating to Proved Oil and Gas Reserves
The standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves for the year ended
March 31, 2004 have been extracted without material adjustments from the reserve report dated June 4, 2004 prepared by DeGolyer
and MacNaughton, independent petroleum engineering consultants. In calculating the standardized measure of discounted future net
cash flows, year-end constant price and cost assumptions were applied to our estimated annual future production from proved reservesto determine future cash inflows. Future development costs are estimated based upon constant price assumptions and assume thecontinuation of existing economic, operating, and regulatory conditions. Future income taxes are calculated by applying the year-end
statutory rate to estimated future pre-tax cash flows after provision for the tax cost of the oil and natural gas properties based upon existinglaws and regulations. The discount was computed by application of a 10% discount factor to the estimated future net cash flows.
We believe that this information does not represent the fair market value of the oil and natural gas reserves or the present value of
estimated cash flows since no economic value is attributed to potential reserves, the use of a 10% discount rate is arbitrary, and prices
change constantly from year-end levels.
(Millions of yen)(1)Year ended March 31, 2003

Total

Asia and Oceania

Middle East

Caspian Sea area

¥2,632,676(853,363)(806,386)¥2,572,923(817,844)(784,686)¥ 59,753(35,519)(21,700)–––

Future net cash flows
10% annual discount for estimated timing of cash flows

972,927(482,675)

970,393(481,718)

2,534
(957)

–
–

Standardized measure of discounted future net cash flows¥ 490,252¥ 488,675¥ 1,577–

Share of equity method investees’ standardized measure of
discounted future net cash flows¥¥¥ 4,643–

Future cash inflows
Future production and development costs
Future income tax expenses

Note:

7,973

3,330

(1) Converted into Japanese yen using the exchange rate of ¥120.20=US$1.00 which was the exchange rate as of March 31, 2003.
(Millions of yen)

Year ended March 31, 2004
Total

Asia and Oceania

Middle East

Caspian Sea area

INPEX & JODCO

Future cash inflows
Future production and development costs
Future income tax expenses¥2,825,423(878,801)(784,076)¥2,214,915(695,001)(668,008)¥ 54,623(29,210)(23,208)¥ 555,885(154,590)(92,860)¥ 3,981,641(1,250,303)(1,486,212)

Future net cash flows
10% annual discount for
estimated timing of cash flows

1,162,546

851,906

2,205

308,435

1,245,126(589,645)(551,371)(394,243)(725)(156,403)

Standardized measure of
discounted future net cash flows¥ 611,175¥ 457,663¥ 1,480¥ 152,032 (1)Share of equity method investees’ standardized
measure of discounted future net cash flows¥–¥ 4,652

Note:

76

Combined figures
for the year ended
March 31, 2004

4,652

–

¥

655,481¥

14,592(1) Includes ¥152,032 million attributable to a consolidated subsidiary in which there is a 49% minority interest. A present value of ¥77,536 million is
attributable to our 51% interest in this subsidiary.

(Millions of yen)

Year ended March 31, 2004
Total

Asia and Oceania

Middle East

Standardized measure, beginning of period
Changes resulting from:
Sales and transfers of oil and gas produced,
net of production costs
Net change in prices, and production costs
Extensions, discoveries and improved recovery,
less related costs
Development costs incurred during the year
Revisions of previous quantity estimates
Accretion of discountNet change in income taxes
Other¥ 490,252¥ 488,675¥ 1,577(141,880)(60,480)(139,366)(66,477)

212,653
61,464(19,718)
91,705
16,522(39,343)

Standardized measure, end of period¥ 611,175

Caspian Sea area¥

Combined figures
for the year ended
March 31, 2004
INPEX & JODCO–¥ 549,272(2,514)
5,997––(188,083)
53,116

60,62160,356(19,494)
90,19419,759(36,605)

–
1,108
(224)
1,511
(3,237)(2,738)152,032–––––

212,653
68,343(34,838)
133,403(40,940)(97,445)¥ 457,663¥ 1,480¥152,032¥ 655,481

Probable Reserves Information
Probable reserve estimates included herein are (i) our probable reserve amounts as of March 31, 2004 and (ii) combined figures of ourand JODCO’s probable reserve amounts as of March 31, 2004. The proportional interest in probable reserves held by equity method
affiliates of (i) ours and (ii) ours and JODCO’s are not broken down by geographical regions, although in JODCO’s case all such reserves
are in the Middle East. For information on the inherent uncertainties involved in calculating probable reserves.
Interest in probablereserves held byequity method
Subtotalaffiliates

March 31, 2004

Asia and
Oceania

Middle East

Caspian Sea
and others

Crude oil, condensate, and LPG (MMbbl)
Natural gas (Bcf)

124.0
2,935.3

64.5
–

702.3
305.5

890.8
3,240.8

12.9
593.2

903.7
3,834.0

613.2

64.5

753.2

1,430.9

111.8

1,542.7

Interest in probablereserves held byequity method
Subtotalaffiliates

Total

Total (MMboe)

Total

Combined Figures of INPEX and JODCOMarch 31, 2004

Asia and
Oceania

Middle East

Caspian Sea
and others

Crude oil, condensate, and LPG (MMbbl)
Natural gas (Bcf)

124.0
2,935.3

442.3
–

702.3
305.5

1,268.5
3,240.8

407.9
593.2

1,676.4
3,834.0

613.2

442.3

753.2

1,808.7506.7

2,315.4

Total (MMboe)77

2. Oil and Gas Production
GeneralThe following table sets forth, in each of the principal geographical areas, (i) for the periods ended March 31, 2002, 2003 and 2004, ouraverage net daily crude oil and natural gas production and average net daily total production and (ii) an additional column for the period
ended March 31, 2004, showing the combined figures of our and JODCO’s average net daily production. The proportional interests in
production by equity method affiliates of (i) ours and (ii) ours and JODCO’s are not broken down by geographical regions.

Year ended March 31,

Combined figures
for the year
ended March 31,

2002

2003

2004

2004

53.6
4.2
–

44.8
4.2
–

42.3
4.7
10.1

42.3
67.1
10.1

57.9

49.0

57.0

119.4

Our proportional interest in production byequity method affiliates

3.1

3.0

2.7

53.8

Total

61.0

52.0

59.8

173.2

22.3

19.0

21.8

63.2

647,616.4––

700,274.0––

809,945.2––

809,945.2––

647,616.4

700,274.0

809,945.2

809,945.2

4,493.2

4,356.2

4,602.7

4,602.7

652,109.6

704,630.1

814,547.9

814,547.9

Annual production (Bcf)

238.0

257.2

297.3

297.3

Total Production (Mboe per day)
Asia and Oceania
Middle East
Caspian Sea Area

161.6
4.2
–

161.5
4.2
–

177.3
4.7
10.1

177.3
67.1
10.1

165.8

165.8

192.0

254.4

3.9

3.7

3.5

54.5

169.7

169.5

195.5

309.0

61.9

61.9

71.4

112.8

Crude Oil Production (Mbbls per day)
Asia and Oceania
Middle East
Caspian Sea area
Subtotal

Annual production (MMbbls)
Natural Gas Production (Mcf per day)
Asia and Oceania
Middle East
Caspian Sea area
Subtotal
Our proportional interest in production byequity method affiliates
Total

Subtotal
Our proportional interest in production byequity method affiliates
Total
Annual production (MMboe)

Notes: (1) JODCO’s net production amount does not reflect reduction of royalties.
(2) JODCO’s investments in affiliates which hold the concession interest have been accounted for by the cost method in its non-consolidated financial
statements. However, these investments will be accounted for by the equity method of accounting in our consolidated financial statements for theyear ending March 31, 2005 and thereafter. The table above has been prepared as if JODCO’s investments in affiliates were accounted for by theequity method of accounting.

78

Subsidiaries and Affiliates
As of March 31, 2004

Consolidated Subsidiaries
Issuedcapital(Thousands)

Votingrights heldby us (%)

Exploration, development, production and sales of oil andnatural gas under South Natuna Sea Block B Project¥5,000,000

100.00Japan

Exploration, development, production and sales of natural gas
under Tengah Project in Offshore East Kalimantan, Indonesia¥1,020,000

100.00INPEX Alpha, Ltd.

Japan

Exploration, development, production and sales of oil and natural
gas in WA-10-L Block in Australia¥3,814,000

100.00INPEX Sahul, Ltd.

Japan

Exploration, development, production and sales of oil and natural
gas in JPDA03-12 Block in Joint Petroleum Development Area ofAustralia and East Timor¥4,600,000

100.00INPEX ABK, Ltd.

Japan

Exploration, development, production and sales of oil in Abu Al
Bukhoosh Block in United Arab Emirates¥2,500,000

95.00

INPEX Southwest Caspian Sea, Ltd.

Japan

Exploration, development, production and sales of oil in
ACG oil fields in Azerbaijan¥53,594,000

51.00

INPEX Timor Sea, Ltd.

Japan

Exploration and development of oil and natural gas in
Joint Petroleum Development Area of Australia and East Timor¥2,275,000

100.00INPEX Browse, Ltd.

Japan

Exploration and development of oil and natural gas under
WA-285-P Project in West Australia¥18,200,000

100.00INPEX Masela, Ltd.

Japan

Exploration and development of oil and natural gas in
Masela Block in Indonesia¥12,859,000

50.14

INPEX North Caspian Sea, Ltd.

Japan

Exploration and development of oil and natural gas in offshore
North Caspian Sea Block in Kazakhstan¥43,180,000

45.00

INPEX Offshore Northeast Mahakam, Ltd.

Japan

Exploration of oil and natural gas in Saliki Block in offshore
East Kalimantan, Indonesia¥803,000

100.00INPEX East Arguni, Ltd.

Japan

Being dissolved¥263,000

100.00INPEX West Arguni, Ltd.

Japan

Being dissolved¥442,000

100.00INPEX North Natuna, Ltd.

Japan

Exploration of oil and natural gas in Nila Block in Natuna Sea, Indonesia¥570,000

100.00INPEX Offshore North Mahakam, Ltd.

Japan

Exploration of oil and natural gas in East Kalimantan Block in offshore
East Kalimantan, Indonesia¥2,100,000

100.00INPEX Offshore South Sulawesi Ltd.

Japan

Being dissolved¥1,345,000

100.00INPEX North Makassar, Ltd.

Japan

Exploration of oil and natural gas in Donggala Block in offshore
East Kalimantan, Indonesia¥3,243,000

54.18

INPEX Trading, Ltd.

Japan

Sales, agency, and brokerage in connection with crude oil andmarket research and sales planning in connection with oil andnatural gas sales¥50,000

100.00INPEX Services, Ltd.

Japan

Management of owned properties and facilities¥65,000

100.00INPEX BTC Pipeline, Ltd.

CaymanInvestment in pipeline construction companies
Islands

US$27,300

100.00INPEX DLNGPL Pty Ltd.

Australia

Investment in pipeline construction companies and operation ofpipeline businesses

A$63,240

100.00Japan Oil Development Co., Ltd.*Japan

Exploration, development, production and sales of oil¥18,800,000

100.00Company Name

Location

Main business

INPEX Natuna, Ltd.

Japan

INPEX Tengah, Ltd.

* Japan Oil Development Co., Ltd. and BP-Japan Oil Development Company Ltd. became our subsidiary and affiliate, respectively, on May 17, 2004.

79

Issuedcapital(Thousands)

Votingrights heldby us (%)

¥4,804,000

83.50

Exploration, development, production and sales of oil andnatural gas in Southeast Sumatra Block in Indonesia¥400,000

100.00Japan

Being dissolved¥520,000

100.00INPEX Northeast Sahara, Ltd.

Japan

Being dissolved¥2,301,700

50.07

INPEX Rabe Timor Sea, Ltd.

Japan

Being dissolved¥5,441,400

47.00

Azadegan Petroleum Development, Ltd.

Japan

Appraisal and development of Azadegan Field¥10,000

100.00Company Name

Location

Main business

Issuedcapital(Thousands)

Votingrights heldby us (%)

Albacora Japão Petróleo Limitada

BrazilLease of production facilities in Albacora Block in offshore
North Campos, Brazil

Reals 29,525

50.00

MI Berau B.V.

Netherlands

Exploration, development, production and sales of natural gas inBerau Block in Papua, Indonesia

Euro 612,112

44.00

INPEX Offshore North Campos, Ltd.

Japan

Financing for oil and natural gas exploration and development
projects conducted by Frade Japão Petróleo Limitada¥5,456,000

37.50

JJI S&N B.V.

Netherlands

Exploration and development of oil and natural gas in Iranian andIslamic seas

Euro 35,301

25.00

Frade Japão Petróleo Limitada

BrazilExploration and development of oil and natural gas in Frade Block in
offshore north Campos, Brazil

Reals 92,923

0.0003

INPEX Northland, Ltd.

Japan

Being dissolved¥2,935,000

32.16

Bontang Train G Project Finance, Ltd.

Japan

Financing for construction of LNG production facility inEast Kalimantan Bongtang Block in Indonesia¥50,000

40.00

Bontang LNG Train H Investment, Ltd.

Japan

Financing for construction of LNG production facility inEast Kalimantan Bontang Block in Indonesia¥50,000

40.00

Project Finance BLRE, Ltd.

Japan

Financing for repayment of LNG production facility in Bontang¥20,000

30.00

BP-Japan Oil Development Company Ltd.*UK

Financing for oil exploration and development projects
conducted by Abu Dhabi Marine Areas Ltd.

£322

45.00

Angola Japan Oil Co., Ltd.

Japan

Production sharing contract related to offshore Angola 3/80 Block.
Palanca, Pacassa, Bufalo, Impala SE, Impala and Pambi fields incurrent production.

¥10,500
million10.00*AJOCO Exploration Co., Ltd.

Japan

Production sharing contract related to offshore Angola 3/85 Block.
Cobo and Pambi fields in current production.

¥6,400
million12.50*AJOCO’91 Exploration Co., Ltd.

Japan

Production sharing contract related to offshore Angola 3/91 Block.
Oombo field in current production.

¥2,996
million12.73*

Company Name

Location

Main business

INPEX Jawa, Ltd.

Japan

Exploration, development, production and sales of oil and natural gas
in offshore Northwest Java, Indonesia

INPEX Sumatra, Ltd.

Japan

INPEX South Natuna, Ltd.

Affiliates Under Equity Method* On September 27, 2004, we increased our shares in Angola Japan Oil Co., Ltd., AJOCO Exploration Co., Ltd. and AJOCO’91 Exploration Co., Ltd. to
19.60%, 25.00% and 25.00%, respectively.

80

Other Investments
As of March 31, 2004

Company Name

Location

CapitalINPEX Investment

Main BusinessIndonesia Nippon Oil Corporation, Ltd.

Japan

¥46,814 million¥2,393 million

Loaned capital funding for exploration anddevelopment in Indonesia under PERTAMINA
operation. Repayment of principal and interest,
project remuneration paid in form of products
supplied to Japan.

Jawa Oil Co., Ltd.

Japan

¥6,200 million¥744 million

Loaned capital funding for exploration anddevelopment in 2 blocks on Java Island under
PERTAMINA operation. Repayment of principal
and interest, project remuneration paid in form of
products supplied to Japan.
RDL Field in current production.

Burma Petroleum Development Co., Ltd.

Japan

¥346 million¥15 million

Loan contract for Myanmar Oil and Gas Enterprise(MOGE) related to exploration well drilling in
offshore Martaban.

Japex New Nanhai Ltd.

Japan

¥3,100 million¥93 million

Exploration, development, production and salesof oil in the 16/06 Block in the Pearl River
Mouth Basin.

New Huanan Oil Development Co., Ltd.

Japan

¥3,000 million¥60 million

Exploration, development, production and salesof oil in the 16/06 Block in the Pearl River Mouth
Basin.
Lufeng 13-1 Field in current production.

Sakhalin Oil and Gas Development Co., Ltd.

Japan

¥22,592 million¥973 million

Exploration and development of oil and natural
gas in three fields (Odoptu, Chayvo, Arkutun-Dagi)
located off the northeast of Sakhalin Islands.

Canada Oil Sands Co., Ltd.

Japan

¥36,483 million¥693 million

Oil sand development contract for the Athabasca
Block.

Wandoo Oil Development Co., Ltd.

Japan

¥3,000 million¥450 million

Exploration and development rights for the WA202-P, WA-14-L, WA-256-P, WA-257-P, WA-286P, AC/P24, T/RL1, and T/18P of the offshore
Dampier area of Western Australia.
Wandoo Field in current production.

81

Corporate Data

Corporate Name:

INPEX CORPORATION

Established:

February 1966

Capital:¥29.46 billion

Address:

4-1-18 Ebisu, Shibuya-ku, Tokyo 150-0013, Japan(Ebisu Neonart Bldg. Floors 14-18)

Telephone:+81-3-5448-1201

Facsimile:+81-3-5448-1259

URL:

http://www.inpex.co.jp

Overseas Offices:

INPEX Jakarta Office
7th Floor, Midplaza I, Jalan,Jenderal Sudirman Kav. 10-11, Jakarta 10220, Indonesia
Tel: 62-21-570-0557 Fax: 62-21-570-0575
Perth Office
INPEX Alpha, Ltd./INPEX Browse, Ltd. Perth Office
Level 27, Exchange Plaza, 2 The Esplanade,
Perth, Western Australia 6000, Australia
Tel: 61-8-9223-8433 Fax: 61-8-9223-8455

Board of Directors: President

INPEX Tehran Office
No. 25, 35th St, Alvand Ave, Argentina Square,
Tehran, Iran
Tel: 98-21-878-1194 Fax: 98-21-878-3261
JODCO Abu Dhabi Branch
Al Masaood, Tower Sheikh Hamdan Street, P.O. Box 2659,
Abu Dhabi, UAE
Tel: 971-2-6345612
Fax: 971-2-6336695

Kunihiko Matsuo

Executive Senior Vice President

Naoki Kuroda

Executive Senior Managing Director

Katsujiro Kida

Secretary Dept./ Corporate Strategies & Coordination/ General

Executive Senior Managing Director

Mutsuhisa Fujii

General Affairs/ Accounting & FinanceManaging Director

Kazuhisa Konoma

Oceania Area

Managing Director

Seiji Yui

Middle Eastern Projects

Managing Director

Noboru Tezuka

Tehran Office

Managing Director

Kunio Kanamori

Exploration & Geophysics

Director & General Manager

Katsuhiko Sakurai

Planning & New Ventures Dept.

Director & General Manager

Michio Hikari

Gas Business Dept.

Director & General Manager

Sadafumi Tanigawa

Jakarta OfficeDirector & Coordinator

Shunichiro Sugaya

Development Dept. & Petroleum Technology Div.

Director & General Manager

Seiya Ito

Corporate Planning & Management Dept.

Director & Senior Deputy Managing Director

Wataru Tanaka

Tehran OfficeDirector (Outside Director)

Kazuo Wakasugi

Chairman, Japan Petroleum Exploration Co., Ltd.

Director (Outside Director)

Yukio Masuda

Member of the Board, Senior Executive Vice President, Chief

Administration/ Public Affairs/ Marketing

Executive Officer for Energy Business Group, Mitsubishi
Corporation
Director (Outside Director)

Junji Sato

President, Mitsui Oil Exploration Co., Ltd.

Director (Outside Director)

Shigeki Kuwahara

Executive Corporate Officer, Regional Strategy & Coordination
Department and Research Institute; Advisor to President forEnergy Division, and Metals & Mineral Resources Division,
Marubeni Corporation

82

AuditorNobuo Kawa

Auditor

Shigeru Watanabe

Auditor (Outside Auditor)

Ryoichi Ono

Executive Vice President, Japan Petroleum Exploration Co., Ltd.

Auditor (Outside Auditor)

Tadaaki Tokunaga

Executive Director, Japan Overseas Development Corporation

Profile
We are the leading upstream oil and gas company in Japan engaged for almost the past four decades in the exploration,
development and production of crude oil and natural gas outside Japan. Based on production and reserve amounts, weare the largest upstream oil and gas company in Japan. As of March 31, 2004, our total net proved reserves were approximately 977 MMboe and for the fiscal year ended March 31, 2004, our net production was 196 Mboe per day. We conduct
a substantial portion of our exploration, development and production activities through joint ventures with international oil
and gas companies. In May 2004, we increased our net proved reserves and production by acquiring JODCO, which holds
a working interest in the Abu Dhabi Marine concession area in the United Arab Emirates. On a combined basis, as of March
31, 2004, our total net proved reserves were 1,634 MMboe and for the fiscal year ended March 31, 2004, our net production
was 309 Mboe per day.

Contents
Financial Highlights ................................................................ 1

FORWARD-LOOKING STATEMENTS:

Summary Reserve and Operating Data ................................. 2

This annual report includes forward-looking information that reflects theCompany’s plans and expectations. Such forward-looking information isbased on the current assumptions and beliefs of the Company in light of
the information currently available to it, and involves known and unknown
risks, uncertainties, and other factors. Such risks, uncertainties and otherfactors may cause the Company’s actual results, performance, achievements or financial position to be materially different from any future results,
performance, achievements or financial position expressed or implied bysuch forward-looking information. Such risks and uncertainties include,
without limitations, fluctuations in the following:

A Message from the President .............................................. 3
The Ambition to Grow ........................................................... 4
Global Business Activities ...................................................... 10
Corporate Governance .......................................................... 26
Financial Section ................................................................... 29
Reserves and Production ...................................................... 74
Subsidiaries and Affiliates ...................................................... 79
Other Investments ................................................................. 81
Corporate Data ..................................................................... 82– the price of and demand for crude oil and natural gas;
– exchange rates; and– the costs associated with exploration, development, production andother related expenses.
The Company undertakes no obligation to publicly update or revise any
information in this annual report (including forward-looking information).

INPEX CORPORATION Annual Report 2004
INPEX CORPORATION
Annual Report 2004

Printed in Japan on recycled paper.

Year ended March 31, 20042004