Annual report 2006

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2 IDEMITSU PETROLEUM NORGE AS

Idemitsu P

etroleum N

orge AS A

nnual Report 2006.

Design and A

rt direction: Uniform

AS.

Photography: Page 5, 12, 13, 14 and front cover: Kai M

yre. Page 9: N

orsk Hydro A

SA.Page 11: Idem

itsu. Print: R

K G

rafisk AS

3ANNUAL REPORT 2006

CONTENTS

KEY DATA 04MESSAGE FROM THE MANAGING DIRECTOR 05EXPLORATION 06PRODUCTION AND OPERATIONS 08IDEMITSU GROUP 11ANNUAL REPORT OF THE BOARD OF DIRECTORS 12PROFIT AND LOSS STATEMENT 16BALANCE SHEET 17CASH FLOW STATEMENT 19ACCOUNTING PRINCIPLES 20NOTES TO THE ACCOUNTS 23AUDIT REPORT 31


KEy dATA2006 2005 2004 2003 2002

Operating revenues million NOK 4592 4093 4234 3136 2787

Operating profit million NOK 1967 2148 2226 1707 1551

Profit after tax million NOK 492 497 462 423 369

Crude oil sales million barrels 10,2 10.6 15.6 14,3 13.2

Daily oil production, thousand barrels 27.9 31.7 40.2 39.3 36.5

Investments, million NOK 695 357 283 582 614

Equity in % of balance 41% 37% 46% 48% 49%

Cash flow before financing, million NOK -426 1117 1434 439 -28

Crude oil reserves, million Sm3 19.8 21.3 20.4 20.6 21.3

Return on capital 72% 71% 64% 61% 23%

dEFINITIONS

Daily oil production = Average daily oil production, Idemitsu share

Investments = Offshore investments excl. production rights

Crude oil reserves = Probable, commercially recoverable resources

Return = Annual profit + interest expense +/- unrealized forex loss/gain on loan

Capital = Share capital and interest-bearing loans at year end

5ANNUAL REPORT 2006

2006 has been a year marked by important changes for Idemitsu Petroleum Norge AS (Idemitsu). The company has been through its first year as operator for a NCS license. Even though the operating activities are still limited compared to Idemitsu’s partner-operated activities, the operator tasks have offered new perspectives and challenges. Our operating activities have increased our focus on Health, Safety and Environment (HSE) issues further, and the continuous improvement of our HSE culture is an important goal for the company.

Growth and changes have also affected our organization. The company has had the pleasure of welcoming several new and highly qualified employees, who are expected to contribute substantially to the onward growth and development of the company through our team work spirit among professionals. With a view to further expansion, the company will have a continued requirement for new staff. Our existing portfolio of producing and prospective licenses, together with our long and stable history on the NCS, makes me confident that our company can continue to offer attractive job opportunities in the current competitive labor market for petroleum industry professionals.

On the operational side, the company has been taking part in several important development projects advanced to various stages during 2006. Fram Øst started production on schedule in October 2006, while a PDO for Vega Sør was submitted in December. In the 19th Round of Licensing, Idemitsu was awarded its first two licenses offshore Mid-Norway. Moreover, two licenses in the North Sea were recently awarded to Idemitsu in the Awards in Predefined Areas 2006. Idemitsu is firmly committed to expanding our exploration activities and production, through building on our current portfolio and by acquiring additional prospective acreage. For 2007, the participation in five exploration wells is planned.

In 2006 Idemitsu’s expansion reached the stage where new office premises were required. After careful preparations for almost a year, the company moved into bright and modern offices in the Skøyen/Sjølyst area in the beginning of 2007. During the preparations, substantial efforts have been made to create a comfortable, safe and healthy working environment. The office move marks a new era for our company, and I am hopeful that our company will thrive and expand in these new and inspiring surroundings.

mESSAgE FROm ThE mANAgINg dIRECTOR

Managing D

irector Kosuke T

suji.

Kosuke Tsuji Managing Director


2006 was a successful year for Idemitsu’s exploration activities in Norway. Idemitsu participated in one of the exploration and/or appraisal wells that were spudded, a well that proved up oil and gas resources. Out of the 26 wells quoted by the Norwegian Petroleum Directorate, only four resulted in new discoveries. In April 2006, Idemitsu was granted two licenses in the 19th Round of Awards. These are designated PL 390 (blocks 6506/4 and 6505/6 & 9 30% Idemitsu interest) and PL 391 (block 6506/1; 20% Idemitsu interest). The awarded acreage broadens Idemitsu’s geographical area of activities to the Mid-Norway offshore. Near-future activities in these licenses include 3D seismic acquisition. Following applications for Awards in Pre-defined Areas 2006 Idemitsu was awarded ownership in two new exploration licenses during February 2007. The licenses, designated PL 318 B (Idemitsu interest 20%) and PL 420 (Idemitsu interest 30%), comprise part blocks 35/4 & 5 and the western part of block 35/9, respectively. PL 318 B is located south of our PL 318 Peon gas discovery, while PL 420 is situated close to the Gjøa oil and gas discovery.In PL 057 (part block 34/4; 9.6% Idemitsu interest) partial relinquishment took place during 2006.

In PL 089 (part block 34/7; 9.6% Idemitsu interest) exploration has entered a late phase. However, the license still contains attractive exploration potential. In 2006 no exploration drilling was carried out due to limited rig availability. In PL 090 (located in block 35/11; 15% Idemitsu interest) work to mature undrilled prospects and leads to a drillable stage will continue.In PL 090 B (located mainly within block 35/11; 15% Idemitsu interest) the 35/11-14 S delineation well was drilled by the semisubmersible drilling rig

“Transocean Winner” to appraise the Astero oil and gas discovery made by well 35/11-13 in 2005. Well 35/11-13 proved oil and gas in Upper Jurassic sandstones, similar to the productive reservoirs of the adjacent Fram Vest Field. The 2006 results from 35/11-14 S are positive, and they are being assessed in conjunction with the rest of the area around the Fram Field as regards commercial exploitation. The license maintains a high activity level and further exploration drilling will be undertaken. In PL 318 (block 35/2; 20% Idemitsu interest) operations in well 35/2-1 R, the re-entered Peon gas discovery well, were completed with the drilling rig “Deepsea Trym” during July 2006. A planned production test was postponed during the operations. The Peon gas discovery was made during August 2005, about 100 km west of the coast of Sogn og Fjordane county. A programme aiming to increase the understanding of the discovery is now underway, in order to seek an optimal field development solution. Additional data acquisition and planning activities are in progress, and further drilling activities lies ahead.In PL 373 S (part block 34/4; 25% Idemitsu interest) reprocessing of 3D seismic was performed. An obligation well will be drilled during 2007.In Idemitsu-operated PL 377 S (part block 35/7; 70% Idemitsu interest) 3D seismic acquisition over the prospective areas was initiated during September 2006 and will be completed during 2007.

Idemitsu will utilise its staff of skilled E&P professionals to continue and strengthen its exploration activities during the years to come. An important contribution towards meeting this end is further acquisition of promising exploration acreage through active licensing round participation and pursuit of attractive farm-in opportunities.

EXPLORATION

7ANNUAL REPORT 2006

License Idemitsu Interest (%)

PL 057 9.60

PL 089 9.60

PL 090 15.00

PL 090 B 15.00

PL 090 C 15.00

PL 090 D 15.00

PL 318 20.00

PL 318 B 20.00

PL 373 S 25.00

PL 377 S 70.00

PL 390 30.00

PL 391 20.00

PL 420 30.00

Trondheim

Bergen

Oslo

B

A

GasOilCondensate Idemitsu licensed areas

211 34 35 36

3 30 31 32

Agat

Gjøa

PL 373 S

Snorre

PL 377 S

PL 420

Vega

Astero Vega Sør

Fram Vest Fram Øst

Vigdis

Visund

Gullfaks Kvitebjørn

Huldra

Veslefrikk

Tordis

Sygna

Statfjord Øst

Troll

Peon

A

6407 6408

6507 6508

6406

6505

6405

6509

6409

PL 391

PL 390

Mikkel

Tyrihans Sør

Lavrans

Kristin

Tyrihans

MidgardÅsgard

Smørbukk

Snadd

Heidrun

Skarv

Idun

Marulk Norne

Victoria

B


PROdUCTION ANd OPERATIONSTAmPEN AREAFive of Idemitsu’s six producing fields are located in the Tampen Area of the North Sea. Good cooperation has been achieved among the fields in this area with Statoil as the common operator. All fields are represented in a Tampen Forum where we have common aspirations to improve health, safety and environmental standards while optimizing economic recovery of resources. Through cooperation in the Tampen Forum, companies have established common use of Light Well Intervention vessels, sharing of long-term rig contracts, joint seismic acquisition and a common Emergency Preparedness Plan. The fields are furthermore striving together to find optimum long-term solutions for their late phase production. Idemitsu is also grateful for the strong cooperation on the HSE side through the Tampen HSE Forum. Here companies share experience from their own HSE measures and verification activities.

SnorreThe Snorre reservoir is comprised of the Statfjord and Lunde sandstone formations at depths of 2300 to 2700 m which contain oil zones with varying recovery factor. The field has been developed in two phases. In the first phase, a tension leg platform (Snorre A) and a subsea production facility were installed. Production started on Snorre A from the Statfjord formation in 1992. In 1993, production also started from the Lunde formation via the subsea template. Partially stabilized oil is exported to

Statfjord A for final processing and offshore loading. Gas not used for injection at the Snorre field is exported through the Gassled system to Kårstø.

The second phase comprises a semi-submersible floater (Snorre B) located about 7 km north of Snorre A platform. The platform was installed in 2001. Production is mainly from the Lunde formation. Stabilized oil is exported to Statfjord B platform for offshore loading. Gas not used for injection may be exported via Snorre A.

Snorre A is in the process of being modified for safe operation in the extended production period to 2030. Major activities cover upgrade of the safety systems, new facilities for better working environment and modifications for increased robustness. This will improve the HSE level and the production regularity of the platform. A well work-over program has been carried out to maintain production at a high safety level for the existing wells. Even with a longer revision stop and an unplanned shut-down due to modification of the life-boats at Snorrre A, the platform still produced above expectations. The Snorre B platform delivered close to planned production volumes. Idemitsu’s share of the crude oil production from the Snorre field was 0.78 million Sm3 (4.9 MMSTB), as compared to 0.84 million Sm3 (5.3 MMSTB) in 2005. Idemitsu actively contributes to the HSE work for the field by coordination of the partners’ participation in management HSE

9ANNUAL REPORT 2006

© N

orsk Hydro A

SA

inspections on- and offshore.The Snorre unit has a determined strategy for increasing field recovery with a defined schedule for various Increased Oil Recovery (IOR) projects the next years. There are also plans being developed for continued production after possible shut-down of the connected facilities.

TordisThe Tordis Area, consisting of the structures Tordis, Tordis Øst, Tordis Sørøst and Borg is developed by subsea installations tied in to Gullfaks C by two production pipelines and one injection pipeline.

The production from Tordis started in 1994 and during the years of operation, the Tordis Area has shown generally good production performance and high regularity. After more than ten years of operation, the Tordis Area is now experiencing a natural decline in production. In order to counteract this development, the license partners have decided to implement the Tordis IOR project. This project will accelerate and increase production from today’s estimate of 51% recovery to 55% recovery. The project is divided into two steps:

1) Enable low pressure production at the Gullfaks C facilities

2) Expand the Tordis subsea facilities to include a subsea processing facility

Step 1 was completed in 2006 and the

pressure at Gullfaks C has been reduced. The subsea production facilities have been prepared for installation of the subsea processing facility in 2007.

Tordis IOR step two will be important in order to bring subsea processing forward as a proven technology. The experience that will be gained by utilizing subsea process-ing for the Tordis IOR project is expected to be of great value for the industry. Subsea processing is a key element in order to develop future deep water fields and long distance tiebacks.

Idemitsu’s share of the Tordis crude oil production was 0.16 million Sm3 (1.01 MMSTB) in 2006, as compared to 0.30 million Sm3 (1.83 MMSTB) in 2005. A prolonged revision stop resulted in lower production than planned.

VigdisThe Vigdis field is a satellite develoment tied in to Snorre A. Vigdis started its production in 1997. In 2003 the first phase of the Vigdis extension project came on stream. Phase two of the Vigdis extension project proceeds as planned. A new production template was installed in 2006 and will start production late 2007.

The phase two of the Vigdis Extension project will ensure the possibility to extend with a phase three development. This is obtained by installing a 4-slot template of which only two slots will be used for the


phase two development. After completion of the Vigdis extension projects, the field will altogether comprise six 4-slot templates and two satellite structures.

Idemitsu’s share of the Vigdis crude oil production was 0.36 million Sm3 (2.26 MMSTB) in 2006, as compared to 0.35 million Sm3 (2.22 MMSTB) in 2005.

A project has been established to utilize spare water injection capacity from Statfjord C to the Vigdis area. Additional capacity can be used for future developments.

Statfjord ØstStatfjord Øst is a subsea satellite field tied into the Statfjord C platform. In Statfjord Øst Idemitsu’s share of crude oil production was 0.06 million Sm3 (0.4 MMSTB) in 2006, as compared to 0.05 million Sm3 (0.3 MMSTB) in 2005.

SygnaSygna is also a subsea satellite field tied into the Statfjord C platform. Idemitsu’s share of the Sygna field’s crude oil production was 0.02 million Sm3 (0.1 MMSTB) in 2006, as compared to 0.03 million Sm3 (0.1 MMSTB) in 2005.

FRAm AREAIn 2002 Idemitsu purchased a 15% share in the PL 090 license and parts of the surrounding area, and thereby established a new core area for the company.

Fram VestThe Fram Vest field is located 20 kilometres north of the Troll C platform. The wellstream is transported to the Troll C platform for processing, and stabilised oil is transported to Mongstad through the Troll oil pipeline, while the gas is re-injected into the reservoir for pressure support. The Fram Vest started production in October 2003.

Idemitsu’s share of the Fram Vest crude oil production in 2006 was 0.23 million Sm3 (1.4 MMSTB), as compared to 0.27 million Sm3 (1.7 MMSTB) in 2005.

Fram ØstThe Fram Øst PDO was submitted to the authorities on 23 February 2005 and approved on 22 April 2005. The Fram Øst development is the second phase of Fram Area development after the successful Fram Vest in 2003.

Fram Øst reservoir will be developed by two 4-slot subsea templates with five producers and two water injectors. The wellstream is routed to the new pipeline and existing Fram Vest pipeline to Troll facilities on the Troll C Platform for processing. Production started 30 October 2006, with an expected plateau oil volume of 7 000 Sm3/sd. Peak gas production will reach 1.5 million Sm3/sd.

Idemitsu’s share of the Fram Øst crude oil production in 2006 was 0.02 million Sm3 (0.1 MMSTB).

Vega Sør (Fram B)The Vega Sør PDO was submitted to the authorities on 15 December 2006. Vega Sør will be jointly developed with Vega (PL 248, Vega Sentral/Vega Nord).The development consists of two producers drilled from a subsea 4-slot template and a new production pipeline connected to Gjøa platform through Vega Sentral and Vega Nord template. The production will be processed on Gjøa platform. Condensate will be transported through a new pipeline to Troll II transportation system, while gas will be transported through a new gas pipeline to FLAGS system.

Production start is planned to be in October 2010.

11ANNUAL REPORT 2006

IdEmITSU gROUPThe Idemitsu group was founded in 1911 by Sazo Idemitsu in order to realize his ideas and philosophy through business. The group has achieved remarkable business growth, especially through the second half of the twentieth century, and is now one of the largest independent energy corporations in Japan.

For over nine decades the company has adhered to a management philosophy rooted in “Wa”, the traditional Japanese concept of harmonious relationship. Today still, Idemitsu group has put into practice the concept of respect for human dignity in the conduct of business and is seeking to be a corporation that deserves the high expectations and trust of society.

The activities of the group now include oil-related business for stable supply of energy, and also compound energy

Sales revenue 3 327 billion JPY

Balance 2 280 billion JPY

Employees 4 447

VLCCs 6

LPG ocean carriers 2

Gas stations 5 249

Refineries in Japan 4

Petrochemical plants in Japan 2

Overseas offices 36 cities

IdEmITSU KEy FIgURES (Consolidated group figures for the year ended 31.03.2006)

businesses such as onsite fuel cell/gaseousenergy, oil exploration, highly value-added production of petrochemicals and lubricants, electronic materials and new biotechnology business.Idemitsu’s exploration activities started in 1971, with an aim to develop a full line integrated petroleum business that runs both upstream and downstream of petroleum business. Since the successful discovery of the first oil field offshore Japan in 1972, we have explored, developed and produced oil and gas for more than 30 years. In order to secure future oil and gas reserves and production, Idemitsu is actively pursuing a balanced combination of asset opportunities and new exploration acreages in our core areas of Norway and Southeast Asia. Norway has been a core area since we entered the Snorre development in 1989. Idemitsu group commits to expand invest-ments on the NCS and contribute to Norwegian society continuously.


ANNUAL REPORT OF ThE BOARd OF dIRECTORS 2006BUSINESS AREAIdemitsu Petroleum Norge AS (Idemitsu) is engaged in exploration for, development and production of crude oil and natural gas on the Norwegian Continental Shelf (NCS). Idemitsu was founded on 25 September 1989. On 2 October 1989, a 9.6% interest in the production licenses 057 and 089 was acquired from Statoil. These production licenses are located in the Tampen area in the Northern North Sea, and comprise the Snorre, Tordis, Statfjord Øst, Sygna, Vigdis and Borg fields.

In February 2002, Idemitsu’s bid for one of the Fram packages of SDFI was accepted by the Norwegian state. The Fram package included a 15% share in PL 090. Within PL 090, Fram Vest and Fram Øst started production in 2003 and 2006 respectively.

Idemitsu is part of the Japanese Idemitsu Kosan group. Idemitsu Snorre Oil Development Co., Ltd. (ISD), a Japanese company registered in Tokyo, owns all the shares. An owner share in ISD of 49.5% was sold in 2005 from the state owned company JNOC to the holding company Osaka Gas Summit Resources Co., Ltd. (Osaka Gas 70% and Sumitomo 30%)

OPERATIONSThe total net production from Idemitsu’s producing fields in 2006 was lower than in 2005. Most of Idemitsu’s producing fields are in a declining stage. But Snorre A production has been recovering after the

serious gas leak incident in late 2004, and from October 2006 Fram Øst has started production.

For the Vega Sør development (PL 090 C), a PDO was submitted to the government in December 2006.

Idemitsu is operator for PL 377 S in the Northern North Sea. In 2006, the acquisition of 3D seismic was initiated.

hEALTh, SAFETy & ENVIRONmENT (hSE)Idemitsu is committed, as a license partner and operator, to monitor and enhance safety and protection of the external environment in our licenses. The objective is to avoid accidents and provide a safe work environment for everybody working on installations where Idemitsu is a partner. Safety and environmental matters arising from the activities in our partner-operated licenses are reported to the authorities by operators Hydro and Statoil.

Idemitsu is working systematically to build a solid HSE culture in the company. As of yet, Idemitsu has no responsibility for offshore drilling or production operations. Consequently, the HSE external responsibility presently includes seismic acquisition in Idemitsu’s operated license PL 377 S, in addition to the ‘see-to’-duties in partner-operated licenses. This responsibility is taken seriously, and the company’s monitoring and follow-up is


consistent with and supported by its Governing Documentation. Until Idemitsu operates drilling or production activities, we have recognised that HSE-risks of our own employees are primarily related to onshore office work and the individuals’ leisure activities. One of our main objectives is to foster and maintain an internal HSE culture. Our HSE manager possesses formal HSE competency as well as relevant experience from the NCS, including participation in relevant industry HSE fora.

At the end of the year, the company had 22 permanent employees. The Board of Directors regards the working environment as good. Total sick leave in 2006 was 1866 hours, equaling 5% of total working time. There have been no accidents or damage incidents. Operators Hydro and Statoil report the working environment, sick leave and accidents in Idemitsu’s licenses. Idemitsu has a practice of equal opportunity for both genders. The number of women in the Board of Directors has been 1 (20%) in 2006.

During October 2006 Idemitsu arranged its second internal HSE seminar. The seminarwas obligatory for management and technical personnel. The topic was a review of prevailing HSE regulations on the Norwegian Continental Shelf, with a particular emphasis on regulatory changes. The seminar lasted for two days for recently recruited personnel, whereas a one day update was provided for staff that had attended the previous seminar. The company’s office activities have not caused pollution to the external environment.

gAS SALESAll gas from the Tampen fields is sold to Statoil on a long term contract. In order to efficiently transport the gas to the delivery point, Idemitsu has entered into a contract with one of the larger gas producers on the NCS for dispatching and booking services in the Gassled system.

NGL products which are extracted from the rich gas entering the Kårstø terminal are sold exit Kårstø.

EXPLORATION & PORTFOLIOIdemitsu was awarded its first two license shares offshore Mid-Norway in the 19th licensing round. The Board is pleased that the active area of Idemitsu is expanding, and is hopeful that the activities in this area will further increase. In the Awards in Predefined areas 2006, Idemitsu was also awarded two license shares. They are both located in the Northern North Sea.

The Board of Directors regards the potential on the NCS as being good. Idemitsu intends to actively take part in coming licensing rounds and seek further investment opportunities on the NCS.

FINANCIAL RESULT(1) Profit and loss statementTotal sales income has increased by 12% compared to 2005. The increase is mainly due to higher crude oil price. The total sales volume of crude oil decreased from 10.6 to 10.2 million barrels.

Operating expenses have increased slightly. As part of the sales agreement for PL 089 and PL 057, Idemitsu must pay to the seller 50% of sales value of petroleum above a certain threshold level of the crude oil price. The total booked cost for this obligation in 2006 is 995.1 million NOK. The accrual for abandonment cost was increased significantly compared to previous years due to new estimates for abandonment by the operators.

Total investment in productions facilities in 2006 was 695 million NOK.

(2) Balance, Liquidity And Cash FlowIdemitsu currently has no long term loans. Proposed dividend for 2006 is 554.9 million NOK. Idemitsu has a comfortable liquidity situation. Equity represents 41.3% of total assets.

Most of the USD to NOK currency ex-change risk was covered by short term for-eign exchange contracts. Risk reductions by using the mentioned financial instruments will never exceed the actual risk position.

The 2006 financial statement is given under the going concern assumption.

Pictures taken from the New office in Oslo.


Trond StangChairman

Kosuke TsujiManaging Director

Catthrine Hambro Hajime Oshima

OUTLOOKIdemitsu’s annual profits are closely linked to the crude oil price and exchange rates. These elements, especially the crude oil price, are difficult to estimate. Idemitsu expects the crude oil price to remain high also in 2007. Due to the solid equity and high cash flow from existing licenses, Idemitsu can expect to be profitable even at significantly lower crude oil prices.

The crude oil production and sales volume also affect the annual results. The 2007 production is expected to be slightly higher than in 2006, due to the new production from Fram Øst.

The Board of Directors is not aware of any significant matters not already presented in this report or in the financial statements.

ALLOCATION OF ThE ANNUAL PROFITThe profit for the year of NOK 491 551 359 is proposed allocated as follows:

Dividends 554 900 000

Retained earnings -63 348 641

Total allocated 491 551 359

All of the Retained earnings are available for dividends.

18 April 2007

Shogo Hirahara

財務諸表

ÅR

SR

EG

NS

KA

PA

CC

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NT

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NOTE 2006 2005

OPERATINg REVENUESales of crude oil 1, 12 4 281 419 096 3 776 272 921

Sales of NGL 1 128 458 180 130 817 032

Sales of dry gas 1 153 344 899 151 123 193

Tariff income and other revenue 1 29 046 154 34 492 972

Total operating revenues 4 592 268 329 4 092 706 118

OPERATINg EXPENSESProduction cost, processing tariff, CO2 573 257 358 531 860 433

Gas and transportation costs 95 777 405 138 208 935

Statoil premium 7 995 064 963 775 366 517

Changes in inventory and over- / underlift 9 58 179 265 - 203 550 650

Exploration costs 74 189 337 28 394 197

Abandonment accrual expense 10 200 889 994 12 790 000

Salaries, social security, pension payments 2, 3 35 554 738 38 217 437

Other operating and administrative costs 3 34 201 329 36 138 916

Ordinary depreciation 4, 5 513 927 759 537 704 684

Ordinary depreciation of production rights 5, 7 48 510 030 51 902 031

Capitalized administration costs - 3 907 351 - 2 714 013

Total operating expenses 2 625 644 828 1 944 318 487

Operating profit 1 966 623 501 2 148 387 631

FINANCIAL INCOmE ANd EXPENSESInterest income 69 128 547 49 275 096

Foreign exchange gain 11, 12 257 905 213 259 972 643

Interest expense 34 324 287 21 647 739

Foreign exchange loss 11, 12 313 017 499 221 278 253

Other financial expenses 313 108 158 383

Net financial items - 20 621 134 66 163 363

Profit before taxes 1 946 002 368 2 214 550 994

Taxes on ordinary result 6 1 454 451 009 1 717 328 789

PROFIT FOR ThE yEAR 491 551 359 497 222 205

Proposed dividend 554 900 000 594 200 000

Allocated to retained earnings -63 348 641 -96 977 795

Total allocated 491 551 359 497 222 205

PROFIT ANd LOSS STATEmENT


NOTE 31.12.2006 31.12.2005FIXEd ASSETS

INTANgIBLE FIXEd ASSETSProduction rights 5, 7 677 201 804 725 711 833

Total intangible fixed assets 677 201 804 725 711 833

TANgIBLE FIXEd ASSETSSuccessful efforts exploration wells 5 163 561 247 89 611 220

Production facilities in operation 5, 8 2 905 945 512 2 582 341 084

Production facilities under development 5 6 066 181 141 985 340

Furniture and fixtures and cars 5 4 587 319 5 657 816

Total tangible fixed assets 3 080 160 259 2 819 595 461

FINANCIAL FIXEd ASSETSEmployee long term receivables 428 600 705 100

Other long term receivables 873 141 1 000

Total financial fixed assets 1 301 741 706 100

TOTAL FIXEd ASSETS 3 758 663 804 3 546 013 394

CURRENT ASSETS

STOCKSInventory, gas banking and underlift 9 76 839 519 68 517 853

dEBTORSAccounts receivable 22 333 869 40 124 805

Receivables from group companies 336 270 864 339 772 194

Other current assets 17 371 048 28 558 367

Total debtors 375 975 781 408 455 366

BANKBank and cash 859 590 327 1 880 135 731

TOTAL CURRENT ASSETS 1 312 405 627 2 357 108 950

TOTAL ASSETS 5 071 069 431 5 903 122 344

BALANCE ShEET


NOTE 31.12.2006 31.12.2005

EQUITyPaid-in share capital 13 727 900 000 727 900 000

Retained earnings 13 1 367 051 713 1 430 400 354

TOTAL EQUITy 2 094 951 713 2 158 300 354

LIABILITIES

PROVISIONSPension liabilities 2 1 297 854 1 049 684

Deferred tax 6 891 996 303 1 020 162 334

Abandonment accrual 10 444 399 994 243 510 000

Total provisions 1 337 694 152 1 264 722 019

CURRENT LIABILITIESSuppliers payable 137 322 668 65 305 743

Payables group companies 1 681 219 1 772 843

Accrued payroll taxes, VAT, etc. 6 217 337 9 189 565

Taxes payable 6 768 661 432 890 167 413

Other current liabilities and overlift 9, 14 724 540 910 1 513 664 408

Total current liabilities 1 638 423 566 2 480 099 972

TOTAL LIABILITIES 2 976 117 718 3 744 821 990

TOTAL EQUITy ANd LIABILITIES 5 071 069 431 5 903 122 344

Trond Stang Chairman

Kosuke TsujiManaging Director

Shogo Hirahara

Cathrine Hambro Hajime Oshima

BALANCE ShEET


2006 2005CASh gENERATEd FROm / USEd INOPERATINg ACTIVITIESProfit / (loss) before taxes for the year 1 946 002 368 2 214 550 994

Taxes paid -1 704 123 020 -1 599 778 766

Ordinary depreciation 562 437 789 589 606 715

Accrual for abandonment cost 200 889 994 12 790 000

Pension accrual 248 170 276 538

Unrealized forex (gain) / loss on loan 0 0

(Gain) / loss on sale of fixed assets - 221 620 - 282 507

Generated from the year’s operations 1 005 233 680 1 217 162 975

Change in inventory and short term

assets and liabilities (excl. dividend payment) - 656 712 506 324 611 213

Net cash flow from operations A 348 521 174 1 541 774 188

CASh FLOW USEd FOR INVESTmENTSInvestment in furniture and fixtures and cars - 2 069 465 - 3 776 748

Proceeds from sales of fixtures and cars 221 620 392 470

Investment in production rights 0 0

Investment in production facilities - 695 045 297 - 357 413 943

Investment in successful exploration wells - 77 377 795 - 65 412 563

Change in other long term assets - 595 641 1 923 595

Net cash flow to investments B - 774 866 578 - 424 287 189

CASh FLOW USEd FOR FINANCINgShare capital increases / (decreases) 0 0

Paid dividend - 594 200 000 - 684 300 000

New loans 0 0

Loan repayments 0 0

Net cash flow to financing C - 594 200 000 - 684 300 000

Net movement in bank and cash A+B+C -1 020 545 404 433 186 998

Bank and cash at 1 January 1 880 135 731 1 446 948 732

BANK ANd CASh AT 31 dECEmBER 859 590 327 1 880 135 731

Bank and cash: MNOK MNOK

restricted funds for employee withholding tax 4.6 4.6

CASh FLOW STATEmENT


ShARES IN JOINT VENTURESThe company’s shares in joint ventures on the Norwegian Continental Shelf are booked under the respective lines in the profit and loss statement and the balance sheet.

REVENUESRevenues are recognized according to the Sales method as opposed to the Entitlement method.

dEFERREd TAXES / TAX EXPENSETax expense comprises payable tax and deferred tax. The deferred tax asset or liability is calculated based upon net temporary differences between assets and liabilities recognized in the financial statements and their bases for tax purposes after offsetting for tax loss carry forwards, special tax deductions and uplift. The full liability method is followed and the asset or liability is not discounted to a net present value. Current tax rates are used when calculating deferred tax.

Uplift reduces the special petroleum tax paid by oil companies under the current tax regime. The uplift related to investments will therefore also reduce the deferred special petroleum tax liability. The full effect of uplift is recorded in the accounts when the investment is made.

dEVELOPmENT COSTS ANd dEPRECIATION ANd WRITE dOWNAll offshore development costs are capitalized from the time when a discovery is deemed to give future commercial production. Development costs are depreciated using the Unit of Production (U.O.P.) method. Under this method, the annual depreciation charge is based on the percentage of the remaining estimated produceable reserves of an oil field actually extracted in a given year. Certain future investments are required to produce the remaining estimated produceable reserves. These future investments are included in the depreciation base.

For tax purposes, offshore development costs are depreciated straight line over 6 years.

If the net recorded value after deduction of accumulated depreciation for a field exceeds its value of future net cash flows, an extraordinary write down is made.

CAPITALIZEd INTEREST COSTSAll interest costs associated with the development of production fields are capitalized up to production start and are thereafter depreciated using the U.O.P. method.

CAPITALIZEd gENERAL ANd AdmINISTRATIVE COSTSAll general and administrative costs associated with the development of petroleum fields are capitalized according to man hours spent on each field up to production start and are thereafter depreciated using the U.O.P. method.

PROdUCTION RIghTSProduction rights represent the excess of the price paid over the cost of assets acquired by the company. Production rights are depreciated using the U.O.P. method.

FURNITURE, FIXTURES ANd CARSFixed assets are recorded in the balance sheet at cost after deduction of total ordinary depreciation. Ordinary depreciation is based on cost and is calculated on a straight line basis over the estimated economic life of the asset, which is 3 or 5 years.

EXPLORATION COSTSExploration costs are accounted for in accordance with the “Successful efforts” method. Under this method, all costs associated with the exploration of licenses are expensed as incurred, with the exception of drilling and testing costs of exploration wells where a commercial discovery is made. Such expenses are capitalized under ‘Tangible fixed assets’ and depreciated using the U.O.P. method together with the producing asset the discovery gave rise to. Exploration wells where the status of a discovery is pending are initially capitalized, and written off fully if the discovery is later deemed non-commercial.

ABANdONmENT COSTSAnnual provisions are made for the future costs of well closure and removal of offshore installations. Provisions are calculated using the U.O.P. method on nominal figures.

ACCOUNTINg PRINCIPLES


SALARy PRESENTATION IN PROFIT ANd LOSS STATEmENTSThe Accounting Act 6-1 requires salaries to be presented separately in the profit and loss statement. Such detailed information is not available in the license accounts, and sala-ries from the license accounts are therefore included in the respective lines in the income statement.

PENSION COSTSThe company finances a collective defined benefit retirement plan which covers all its local employees. This plan is administered by a Norwegian insurance company. In accordance with actuarial calculations the net present value of the future pension obligations are estimated and compared with the value of all funds paid and previously saved. The difference is shown in the balance sheet under ‘Other long term liabilities’. Paid pension premiums and changes in net liability are recorded under ‘Salaries, social security, pension payments’ in the profit and loss statement.

FOREIgN CURRENCy TRANSACTIONSTransactions in foreign currencies are translated at the exchange rates prevailing at the time of the transaction. Unrealized gains and losses arising from the individual revaluation of long term assets and liabilities at Norges Bank year end rates are recognized through the profit and loss statement. Unrealized gains are not recognized for tax purpose except to the extent that they represent a reversal of a previously recorded loss. Short term assets and liabilities are revalued individually at Norges Bank year end rates, and unrealized gains and losses are recognized through the profit and loss statement.

FINANCIAL INSTRUmENTSShort term forward currency exchange contracts outstanding at the end of the year are revalued to market value. All other gains and losses are recognized at the time of realization.

CURRENT ASSETS ANd LIABILITIESCurrent assets and liabilities include items falling due within one year. ‘Bank and cash’ includes short term time deposits in banks. Current assets are recorded at face value. No losses are anticipated.

INVENTORIES ANd OVER- /UNdERLIFT OF PETROLEUm PROdUCTSLiabilities arising from lifting more than the company’s share of the joint venture’s petroleum production (overlifting) are valued at the higher of gross market value and production cost, and booked under ‘Other current liabilities and overlift’. Inventories and underlifting are valued at the lower of production or acquisition cost and net market value, and booked under ‘Current assets’. Full production cost including indirect cost is used for crude oil. For natural gas liquids and dry gas, full production cost after separation from crude oil is included according to the economic carrying ability principle.

gAS BANKINgGas banking inventories are valued at the lower of production cost (see above) and net market values.

RESEARCh ANd dEVELOPmENTThe company’s research and development costs, which are immaterial amounts, are expensed as incurred.

mAINTENANCEMaintenance costs are expensed as incurred. No accrual is made for periodic maintenance.

CASh FLOW mOdELThe indirect model is used. ‘Cash and bank’ includes bank deposits available for use at year end, except as noted for restricted funds.

注記

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NOTES TO ThE ACCOUNTS

1. SALES

Amounts in NOK Below 12G Above 12G

2006 2006

Service cost 1 164 467 535 864

Interest cost 429 564 318 657

Return on pension plan assets -387 390 -224 211

Amortization 173 418 61 157

Administration 54 013 40 607

Net pension cost 1 434 072 732 074

31.12.06 31.12.05 31.12.06 31.12.05

Mimimum obligation 7 215 798 5 545 630 4 394 130 4 765 629

Estimated effect of future salary increase 4 253 273 2 000 045 3 785 846 4 080 332

Estimated pension obligations 11 469 071 7 545 675 8 179 976 8 845 961

Pension plan assets (market value) 8 145 618 6 712 849 4 703 608 3 966 655

Unrecognized effects of change of plan 0 0 527 604 586 227

Unrecognized effects of estimate deviations 4 202 672 1 923 440 771 691 2 152 782

Net benefit obligations -879 219 -1 090 614 2 177 073 2 140 297

Economical assumptions:

Discount rate 4.35%

Expected compensation increase 4.50%

Expected return on pension plan assets 5.40%

Adjustments in National Insurance base rate 4.25%

Adjustments in pensions 1.60%

Pension rights for Japanese employees are covered in Japan by group companies. Idemitsu has a group pension insurance with Vital for the local employees. Net pension obligations are recorded under ‘Provisions’ in the Balance sheet. The annual change in net obligation is recorded as expense under ‘Other operating and administrative expenses’ in the Profit and loss statement.

2. PENSIONS

CRUdE OIL:All of the company’s crude oil production is sold to the ultimate parent company, Idemitsu Kosan Co., Ltd. The crude oil is sold on a FOB (Free On Board) basis. Idemitsu Kosan Co., Ltd. sells this oil directly to Statoil on a long term sales agreement. Idemitsu Petroleum Norge AS receives the norm price linked price paid by Statoil less a margin for Idemitsu Kosan Co., Ltd. This margin covers all sales and transportation and shipping activities as well as swapping arrangements to secure crude oil supply to Japan. In 2006, a total of 10.2 million barrels were sold.

ROyALTy: Idemitsu does not participate in production licenses where royalty is levied.

NgL:NGL is sold to Norsk Hydro based upon market prices, except ethane which is sold to Statoil.

dRy gAS:All dry gas is sold to Statoil on a long term contract.

TARIFF INCOmE:Vigdis well stream is processed at the Snorre TLP. Idemitsu has a 9.6% share of both fields. The processing tariff revenue and cost, which are booked under ‘Tariff income’ and ‘Production cost and Process Tariff’ respectively, have no net profit impact on the company’s accounts.

Below 12G Above 12G


3. ADMINISTRATION COSTS

Non-employed Directors have each received NOK 10 000 as remuneration. Employed Directors have not received remuneration for their work as members of the Board. Total compensation to Managing Director was 2.8 million NOK. No employee has options, profit sharings or “golden parachutes”. There are no loans or pledges of security to the Managing Director or board members.

Total booked compensation to auditor PriceWaterhouseCoopers AS is NOK 312 862, of which NOK 231 469 for statutory audit.

Split of payroll expenses 2006 2005

Wages and salaries 30 015 949 30 240 069

Social security tax 4 458 353 6 050 375

Pensions including pension liability 2 166 145 2 040 260

Allowances 339 846 420 994

4. DEPRECIATION AND RESERVES

The reserve numbers shown below are the estimated total producable reserves. The depletion of the reserves requires substantial future investments. These future investments are included in the depreciation base. The resulting depreciation charge is estimated to be equal to thedepreciation of current investments over the reserves exploitable from the current investments. Production rights are depreciated using the U.O.P. method based on the total production from the area in question. Idemitsu only accounts for reserves of crude oil (except for Fram Area), as reserves of natural gas liquids and dry gas have very little net economic value for the company.

The Idemitsu net remaining reserves (P50) at the end of 2006 are broken down as follows.

The net remaining reserves at the beginning of 2006 were 21.3 million Sm3 (134 MMSTB). During 2006, 1.6 million Sm3 (10 MMSTB) of net crude oil was produced.

million Sm3 MMSTB

Snorre 10.4 65

Tordis Area 1.5 10

Vigdis Area 2.3 14

Statfjord Øst & Sygna 0.5 3

Fram Area (O.E.) 5.1 32

Total (31.12.06) 19.8 125


5. FIXED ASSETS (1000 NOK)

Sales of fixed assets is less than 2 milion NOK accumulated.

Cost Additions Disposals Transfer to fields Book value Capitalized 01.01.06 in 2006 in 2006 in operation 31.12.06 interest

- 6 066 - - 6 066 -

141 985 302 869 - -444 854 - -

141 985 308 935 - -444 854 6 066 -

Accum. Accum. Cost Additions Disposals Cost depr. Depr. depr. Book value Capitalized

01.01.06 in 2006 in 2006 31.12.06 01.01.06 in 2006 31.12.06 31.12.06 interest

3 652 985 116 407 - 3 769 392 -2 746 888 -204 829 -2 951 717 817 675 325 327

1 584 945 50 523 - 1 635 468 -626 706 -132 832 -759 539 875 929 130 017

289 744 10 342 - 300 086 -264 835 -13 720 -278 555 21 530 15 814

795 163 148 208 - 943 371 -717 608 -32 643 -750 251 193 120 24 706

989 440 56 821 - 1 046 261 -732 127 -73 248 -805 375 240 886 39 587

90 556 491 - 91 047 -76 771 -3 185 -79 955 11 092 2 939

513 010 3 317 - 516 327 -168 566 -37 858 -206 424 309 903 16 546

- 444 854 - 444 854 - -9 045 -9 045 435 809 -

7 915 842 830 964 - 8 746 806 -5 333 501 -507 360 -5 840 861 2 905 945 554 936

Accum. Accum. depr. Depr. depr. Book value Capitalized

Cost 01.01.06 in 2006 31.12.06 31.12.06 interest

-660 787 -24 842 -685 630 333 471 21 879

-83 602 -23 668 -107 269 343 731 0

1 470 101 -744 389 -48 510 -792 899 677 202 21 879

Accum. Cost Additions Disposals Cost depr. Book value Capitalized

01.01.06 in 2006 in 2006 31.12.06 31.12.06 31.12.06 interest

7 338 - 7 338 -4 196 3 141 -

10 798 - 10 798 - 10 798 -

13 796 - 13 796 -5 218 8 578 -

28 307 60 328 88 636 - 88 636 -

17 659 153 17 812 -1 747 16 065 -

19 446 16 896 36 342 - 36 342 -

97 344 77 378 - 174 722 -11 161 163 561 -

Accum. Depr. Accum. Cost Additions Disposals Cost depr. Depr. disposals depr. Book value

01.01.06 in 2006 in 2006 31.12.06 01.01.06 in 2006 in 2006 31.12.06 31.12.06

24 021 2 093 -2 741 23 374 -18 364 -3 140 2 717 -18 787 4 587

1989 1990 1991 1992 1993 1994 1994 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

382 691 856 640 374 306 286 285 165 225 734 813 464 614 582 283 357 695

1 1 1 0 0 1 3 2 1 3 4 3 3 2 3 3 3 2

a) Petroleum fields under development

b) Petroleum fields in operation

c) Production rights - See Note 7

d) Successful efforts exploration wells

e) Other fixed assets

f) Additions of fixed assets (million NOK)

Vega Sør

Fram Øst

Total

Snorre

Snorre B

Statfjord Øst

Tordis

Vigdis

Sygna

Fram Vest

Fram Øst

Total

Prod.rights Snorre

Prod.rights Fram

Total

34/7-25S (STUJ)

34/7-29S (H-North)

34/7-31A (Borg N)

35/11-13 (Astero)

34/7-D4-H (M5)

35/2-1 (Peon)

Total

Furniture & fixtures

Year

Petroleum fields

Furniture & fixtures


6. TAXES (NOK)

Difference between profit before tax and tax basis 2006 2005

Profit before tax 1 946 002 368 2 214 550 994

Permanent differences 66 555 832 81 054 592

Movement temporary differences

- fixed assets 5 487 343 17 892 639

- other temporary differences 138 704 939 -74 381 681

Tax basis - corporate tax (28%) 2 156 750 482 2 239 116 544

-uplift -177 207 887 -165 686 988

Tax basis - special tax (50%) 1 979 542 595 2 073 429 555

Tax cost of the year

Payable tax 1 593 661 432 1 663 667 413

Correction prior years payable tax -11 044 392 -18 511 216

Change deferred tax -128 166 031 72 172 593

Total tax cost 1 454 451 009 1 717 328 789

Deferred tax liability related to temporary differences 31.12

Fixed assets 1 645 758 042 1 651 245 385

Other temporary differences -282 005 261 -143 300 322

Basis for corporate tax 1 363 752 781 1 507 945 063

-uplift, to be received -343 461 731 -312 069 628

Basis for special tax 1 020 291 050 1 195 875 434

Deferred corporate tax 28% 381 850 779 422 224 618

Deferred special tax 50% 510 145 525 597 937 717

Total deferred tax 891 996 303 1 020 162 334


7. § 10-RULINGS

Cash payment to Statoil shall be treated as follows: NOK

Cash payment for 9.6% of PL 057 and PL 089 1 100 000 000

Interest 21 879 151

Total 1 121 879 151

Allocated to Development cost Snorre - 102 778 360 - 1)

Remainder - Production rights 1 019 100 791 - 2)

1) Tax deductible over 5 years straight line. Uplift is given. 2) Never tax deductible for corporate tax or special petroleum tax purposes. No uplift given.

8. INTERESTS IN NORWEGIAN PRODUCTION LICENSES (AS OF 31.12.06)

Production License Block Expiry Year Producing Fields Operator Interest

057 34/4 2015 Snorre Statoil 9.6%

089 34/7 2024 Snorre, Tordis area, Vigdis area Statoil 9.6%

Statfjord Øst Statoil 4.8% 1)

Sygna Statoil 4.32% 2)

090 35/11 2024 Fram Vest, Fram Øst N. Hydro 15%

090 B 35/11 2024 N. Hydro 15%

090 C 35/11 2024 N. Hydro 15%

090 D 35/12 2010 N. Hydro 15%

318 35/2 2010 N. Hydro 20%

373 S 34/2,3,5,6 2011 BG Norge 25%

377 S 35/7 2013 Idemitsu 70%

390 6505/6,9 6506/4 2011 BG Norge 30%

391 6506/1 2011 BG Norge 20%

1) According to current unitization agreement where PL 089 and PL 037 each has 50% interest.2) According to first and final unitization agreement between PL 089 and PL 037.

The Petroleum Tax Act §10 states that transfer of interests in production licenses is subject to approval by the Norwegian government, and that the government can set certain conditions for approval related to the tax treatment of the transfer of interest. In connection with Idemitsu’s 1989 acquisition of a 9.6% interest in the production licenses 057 and 089 from Statoil, such a §10-ruling was made. This ruling states that:

In the Assignment Agreement for purchase of the 9.6% shares in PL 057 and PL 089, Idemitsu and Statoil agreed that Statoil shall receive 50% of the excess monthly value of petroleum production from these fields if the norm price exceeds USD 20/bbl, inflation-adjusted from 1989. There is a cap on the total amount. In 2006, the norm price exceeded this level in all months.

In connection with Idemitsu’s acquisition in 2002 of shares in licenses 090, 174 and 191 from SDFI, another §10-ruling was made. This ruling states that the consideration to SDFI shall be non-deductible for Idemitsu. The consideration is classified as ‘Production rights’ in Idemitsu’s Balance sheet, and the depreciation according to the U.O.P. method is not deducted for tax purpose.


Crude Oil Inventory Inventory

Field in barrels value NOK

Snorre 82 423 12 516 072

Sygna 4 850 501 198

Fram 43 668 3 238 773

Value recorded as asset 31.12 A 16 256 043

Overlift

Field in barrels Net liability NOK

Statfjord Øst 22 069 8 076 943

Vigdis 101 067 36 989 082

Tordis 70 882 25 941 816

Value recorded as Other current liabilities and overlift 31.12 71 007 841

Inventory

Natural Gasoline value NOK

Value recorded as asset 31.12 B 89 078

Net liability NOK

Value recorded as Other current liabilities and overlift 31.12 2 700 540

Inventory

Ethane value NOK

Value recorded as asset 31.12 C 202 192

Net liability NOK

Value recorded as Other current liabilities and overlift 31.12 840 553

Gas banking

Value recorded as asset at 31.12 D 627 967

Stock of spare parts etc. held by operators E

59 664 239

Total inventory value A+B+C+D+E 76 839 519

9. INVENTORY

Idemitsu does not have inventory of propane and butane, as these products are sold on a monthly production basis to Norsk Hydro.

As a participant in Statfjord Øst, Idemitsu has stored gas at Statfjord.The stored volumes are valued at the lower of production cost and net market value.


10. ABANDONMENT COSTS

The Norwegian government may, at the termination of production or expiration of a license, require Idemitsu to remove offshore installations. Given reserve estimates at license expiry, Idemitsu finds it unlikely that the Norwegian government will exercise its option to take over the installations. With current and expected future fishery and environmental concerns, it is likely that the Norwegian government or international institutions and legislation will require the installations to be removed. It is also necessary to close down all production and injection wells as their use is completed. Well closure and removal cost accrual is recorded gross before tax.

Idemitsu records accruals for future removal and well closure cost according to the U.O.P. method for nominal numbers, retrospectively from each field’s start of production. Each year, the accrual is based upon updated information, and the accumulated accrual includes accrual for 2006 production, and changes in accruals for prior periods due to updated information.

There are significant uncertainties inherent in the calculations of abandonment costs, which is highly dependent upon future technology levels and the degree of removal required. Idemitsu obtains abandonment cost estimates from the operators. The removal estimates are based upon complete removal and onshore disposal of any installations not below the seabed. Pipelines will be cleaned and left buried. Well closure cost includes cleaning wells and installing cement plugs in the permeable zones and upper part of the well.

(Million NOK) Full field Full Field Reservoir Idemitsu net Idemitsu net IdemitsuField well closure cost removal cost IPN share produced well closure cost removal cost total accrual

Snorre 1 070 1 611 9.6% 62% 63.62 95.79 159.41

Snorre B 410 1 074 9.6% 38% 15.08 39.50 54.58

Tordis 571 535 9.6% 75% 41.32 38.72 80.04

Vigdis 1 056 352 9.6% 61% 62.06 20.69 82.75

Statfjord Øst 424 248 4.8% 84% 17.03 9.95 26.98

Sygna 201 64 4.32% 69% 5.98 1.90 7.88

Fram Vest 505 86 15% 35% 26.85 4.57 31.42

Fram Øst 703 76 15% 1% 1.21 0.13 1.34

233.15 211.25 444.40

Previously recorded 158.78 84.73 243.51

This year’s expense 74.37 126.52 200.89

Idemitsu’s through-put based share of pipeline/transportation system removal is immaterial. There is currently no legislation for onshore installation of pipelines on foreign territories. No accrual is made.


Revenues are largely denominated in USD, while investments and operating costs generally accrue in NOK. Idemitsu uses forward exchange contracts to minimize this NOK exposure. All foreign exchange contracts entered into are short term.

Idemitsu had a number of forward exchange contracts outstanding as of 31.12.06. All outstanding contracts have been revaluated to market value at 31.12.06.

The annual requirement to exchange currencies from USD to NOK is approximately between 200 and 300 million NOK for operations. In addition, all tax payments must be made in NOK. For investment in petroleum fields, the exchange requirement varies.

The credit risk of these foreign exchange contracts is negligible as the counterparties are financially strong banks. The foreign exchange contracts are linked to the real foreign exchange requirement so there is no liquidity risk.

With the exception of some short term foreign exchange contracts being entered into, Idemitsu is fully exposed to fluctuations in the USD / NOK exchange rate.

In 2006, the company was fully exposed to oil price fluctuation risk.

At year end, Idemitsu had no long term assets or liabilities in foreign currency.

The share capital consists of 7 279 shares of NOK 100 000, all fully paid. All shares are owned by Idemitsu Snorre Oil Development Co. Ltd., Japan.

ChANgES IN Retained earnings 31.12.05 1 430 400 354

Profit 2006 491 551 359

Dividends declared 554 900 000

Retained earnings 31.12.06 1 367 051 713

Idemitsu, as all other oil companies operating on the Norwegian Continental Shelf, has unlimited liability for possible compensation claims arising from its offshore operations, including pollution. To cover these liabilities, Idemitsu has obtained insurance covering such liabilities up to 1 065 million NOK for 100% share. The deductible is 30 million NOK. Liabilities arising from well blow outs are covered up to 1 916 million NOK for a 100% share, with a deductible of 30 million NOK. Liabilities arising from transportation of crude oil are the responsibility of the buyer, Idemitsu Kosan Co., Ltd.

Offshore assets are insured at replacement value with third party insurance companies.

Idemitsu is involved together with other partners in a forced arbitration process against Hydro regarding pension liabilities in Hydro-operated licenses for the period prior to 2001. No accrual has been made for any such possible liabilities.

Through its license ownership interests, Idemitsu has certain obligations for future investments. There are also substantial investments planned in fields where PDOs are not yet submitted to or approved by the government.

Idemitsu does not have any leasing agreements that can be defined as financial leases. Current leasing agreements are operational and the expenses are included un-der ‘Other operating and administrative costs’.

Idemitsu is committed to certain dry gas delivery, transportation, and processing obligations as an integral part of the license activity. These obligations are not in excess of planned future production.

11. FINANCIAL INSTRUMENTS

12. FINANCIAL RISK

13. EQUITY

14. OTHER LIABILITIES AND COMMITMENTS

EQUITy:


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Documents

Annual report 2006